ITEM 1. BUSINESS
General
We are an independent developer and producer of natural gas and oil, with operations in Pennsylvania, Kentucky and New York. Vadda was originally incorporated in Florida in May 1997 as Worldwide Dental Distribution Corp. Since our incorporation, our name has changed a number of times as a result of both acquisitions and changes in our business focus. In July 2003, Moarmoff Trust, an entity for which Anita Blankenship, who is the Chairwoman of our board of directors and our Executive Vice President, serves as sole trustee, acquired control of Worldwide Dental Distribution Corp. and our name was changed to Vadda Energy Corporation.
On December 1, 2009, pursuant to an Agreement and Plan of Merger dated November 6, 2009 (the “Merger Agreement”) with Mieka, Mieka Acquisition Corp., a Texas corporation and wholly owned subsidiary of Vadda, and 18 natural gas and crude oil joint ventures organized under the laws of the State of Texas (collectively the “Mieka Joint Ventures”), the Mieka Joint Ventures merged with and into Vadda.
In connection with the merger of the Mieka Joint Ventures, the Company issued an aggregate of 15,988,935 shares of Vadda common stock to the owners of the Mieka Joint Ventures, of which 967,708 shares were issued to Mieka, the managing venturer of the Mieka Joint Ventures. As a result of the merger of the Mieka Joint Ventures, the Company obtained working interests in producing natural gas and crude oil properties in Pennsylvania and Kentucky.
On December 30, 2009, under the terms of the Merger Agreement, Mieka Acquisition Corp. was merged into Mieka, which survived the merger and thereby became a wholly owned subsidiary of Vadda. In the Mieka merger, the shares of Mieka common stock held by Moarmoff Trust were converted into 69,000,000 shares of Vadda common stock and the shares of Mieka common stock held by Vadda were canceled. As a result of the Mieka merger, Vadda became the owner of 100% of Mieka’s common stock.
Immediately prior to the mergers with the Meika Joint Ventures and Mieka, Moarmoff Trust and certain of our officers and directors (Daro and Anita Blankenship and Verne Rainey) owned approximately 82.9% of Vadda’s outstanding common stock and Vadda owned approximately 19% of Mieka’s outstanding common stock. The remainder of Mieka’s outstanding common stock was owned by Moarmoff Trust. After the issuance of Vadda common stock in the mergers, Moarmoff Trust and these officers and directors beneficially owned approximately 81% of Vadda’s outstanding common stock. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” The Merger Agreement was approved by the holders of a majority of the units in each of the Mieka Joint Ventures and by the holders of a majority of the outstanding voting stock of Mieka and Vadda.
Both Vadda and Mieka are currently operating companies. Vadda directly holds the assets and liabilities formerly held by the Mieka Joint Ventures, and Mieka serves as managing venturer of joint ventures we have sponsored since the Mieka Joint Ventures merger.
Before and after the mergers, both Vadda and Mieka were under common control by virtue of the fact that Moarmoff Trust and Daro and Anita Blankenship were the majority stockholders of both entities. Accordingly, the mergers have been accounted for as combinations of entities under common control using the acquisition method of accounting, with no adjustment to the historical basis of the assets and liabilities of Mieka, and the operations were consolidated as though the merger occurred as of January 1, 2009.
Growth Strategy
Our long-term growth strategy is primarily focused on building cash flow from developing crude oil reserves through drilling horizontal wells in western New York and north central Pennsylvania and natural gas reserves on lease acreage in the Marcellus Shale and Utica Shale formations in southwestern Pennsylvania and eastern Ohio. We believe this strategy will create greater value for investors.
We hope to accomplish our objectives in the following manner:
·Generating turnkey drilling profits from wells funded and drilled by joint ventures we manage.
·Earning carried working interests in wells drilled by joint ventures we sponsor. In all wells drilled by sponsored joint ventures, our carried interest bears no drilling and completion costs. We bear only the cost of the leasehold rights and our share of operating expenses after the wells are drilled, completed and commence production.
·We also purchase an interest in each joint venture equal to 1% of the working interest owned by the joint venture. Such interest is not carried and pays its proportionate share of joint venture costs and expenses.
·Direct participation as a working interest owner in wells through a combination of strategies, including retention of carried working interests, overriding royalty interests and reversionary interests (which we expect will provide us ownership in wells after outside investors have recovered their drilling and completion costs from net revenues from the wells).
·Overhead fees and income earned as the managing venturer of joint ventures.
·Raising additional capital through debt or equity offerings.
·Exploiting our oil and gas wells through use of hydraulic fracturing, a method we have employed on past wells we have drilled and/or operated, and a technique we intend to utilize in our Marcellus Shale operations in Pennsylvania and in New York, to the extent drilling is permitted.
Oil and Gas Holdings
Based on a reserve report prepared by ValueScope, our total estimated proved developed reserves as of December 31, 2012 were 5,310 barrels of oil and 771,940 Mcf of natural gas. Our oil holdings are found in Warren County, Kentucky and Cattaraugus County, New York. Our natural gas holdings are located in Pennsylvania in Centre, Clearfield and Westmoreland Counties. We have 600 gross acres (594 net acres) of proved developed property located in Kentucky, 4,926 gross acres (2,353 net acres) of proved developed leasehold acreage in Pennsylvania, and 73 gross acres (5 net acres) of proved developed property in New York.
We seek to increase our reserves through acquisitions and drilling programs. We have focused and will continue to focus on properties located within the Marcellus Shale region, where we believe there are tremendous opportunities for growth.
Marketing and Sales of Natural Gas and Crude Oil
Natural gas and crude oil production from wells in which we own working interests is generally sold directly to natural gas marketing companies and crude oil purchasers. Sales are generally made on the spot market. These prices often are tied to West Texas Intermediate (WTI) crude and natural gas prices as posted in national publications. In the future, we may hedge a portion of our natural gas production.
The operators of these wells are responsible for marketing our share of production. As of December 31, 2012, our producing wells were operated as follows:
Income Derived from Managed Joint Ventures
We generate income from our management of joint ventures involved in the exploration and production of oil and natural gas. Generally, Mieka will enter into turnkey drilling and/or turnkey completion agreements with joint ventures it manages in order to assume the responsibilities for the joint ventures’ costs and expenses in connection with the drilling and/or completion of oil and natural gas wells in which the joint ventures hold interests. If the costs and expenses associated with drilling and completion of these wells are more than the amounts paid by the joint ventures under the turnkey agreements, losses are recognized immediately. The joint ventures also pay monthly management, administrative and overhead fees with respect to wells that are successfully completed.
Competition
We are in direct competition with numerous natural gas and oil producers, drilling and income programs and partnerships that are active in Pennsylvania, Kentucky and New York. Many competitors are large, well-known oil and gas and/or energy companies, although no single entity dominates the industry. Many of our competitors possess greater financial and technological resources, enabling them to identify and acquire more economically desirable properties and drilling prospects than us. Additionally, there is competition from other fuel choices to supply the energy needs of consumers and industry. Nevertheless, management believes that there exists a viable and sustainable market for smaller producers to market natural gas and crude oil production.
Horizontal Drilling and Hydraulic Fracturing
Vast quantities of natural gas and oil deposits exist in deep shale and other formations. It is customary in our industry to recover natural gas and oil from these deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Horizontal drilling techniques are used to efficiently steer the drilling equipment to reach targeted deposits that are not directly beneath the drill sites or otherwise accessible via conventional vertical drilling. Horizontal drilling is the process of drilling and completing, for production, a well that begins as a vertical bore extending from the surface to a subsurface location just above the target oil or gas reservoir, called the “kickoff point,” then bearing off on an arc to intersect the reservoir at the “entry point,” and, thereafter, continuing at a near-horizontal to substantially or entirely remain within the reservoir until the desired bottom hole location is reached.
Horizontal drilling is intended to obtain economic and other benefits that cannot be obtained with conventional vertical drilling due to the physical characteristics of oil and gas reservoirs, which often make vertical wells impossible, not economically feasible or simply not efficient. For example, because most reservoirs are much more extensive horizontally than they are vertically, horizontal drilling exposes significantly more reservoir rock to the wellbore surface than a conventional vertical well. Benefits of horizontal drilling typically include increased reservoir productivity due to the avoidance of unnecessarily premature water or gas intrusion (i.e., substances that may otherwise interfere with production) and the prolongation of the reservoir’s commercial life, as well as decreased environmental impact.
Although horizontal wells are generally more expensive than vertical wells, horizontal drilling often enables operators to achieve better returns on drilling investments because the production from one horizontal well is frequently significantly greater than the production from one vertical well.
Hydraulic fracturing is often combined with horizontal drilling to more efficiently recover commercial quantities of oil and gas deposits that exist in deep shale and other formations, such as the Marcellus Shale formation, which is a non-conventional reservoir. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where fluids (usually a mixture of water, sand and small amounts of several chemical additives) are pumped into a well under high pressure to stimulate hydrocarbon (natural gas and oil) production. Typically, the process begins after the well has been drilled to its desired depth and horizontal length. Then, after the fluids are injected to fracture the shale, the fracture fluid is generally flowed back out of the well, while the sand remains in order to keep the rock fractures propped open and allow oil or gas to flow more freely to the wellbore. Some flowback water is usually returned to the surface soon after the fracture process and collected in tanks or lined pits, where it is stored until it is transported to a permitted disposal facility or recycled and used to fracture additional wells. Once completed, wells are typically “flared” to burn gas containing elevated levels of water vapor and then capped temporarily while pipelines and other production equipment is put into place.
Hydraulic fracturing has been used since the 1940s and has become customary in the oil and gas industry. The process is used in a majority of oil and natural gas wells drilled in the U.S. today (where permitted) and is often necessary to produce commercial quantities of natural gas and oil from many reservoirs. We may elect to use hydraulic fracturing to attempt to produce commercial quantities of natural gas and oil, where permitted. The success of our exploration and production operations and profitability of our wells may depend on the use of hydraulic fracturing to stimulate or enhance production, including if the wells would not be economical without the use of hydraulic fracturing.
Environmental Regulation Relating to Hydraulic Fracturing
We may elect to utilize hydraulic fracturing techniques to enhance oil and natural gas extraction, which would result in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which we cannot predict, all of which could have an adverse effect on our operations and financial performance. Our ability to remove and dispose of water will affect production, and the cost of water treatment and disposal may affect profitability. The imposition of new environmental initiatives and regulations could also include restrictions on our ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil.
New Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing
The hydraulic process is typically regulated by state oil and gas commissions. Some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. The process is typically regulated by state oil and gas commissions. However, the EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and published a draft of permitting guidance in May 2012 addressing the performance of such activities. There are governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a study of potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. In addition, the EPA announced that it is launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. Also, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and, in August 2011, issued a report on immediate and longer-term actions that may be taken to reduce environmental a safety risks of shale gas development while the U.S. Department of the Interior has proposed disclosure, well testing and monitoring requirements for hydraulic fracturing on federal lands. At the same time, legislation has been introduced before Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process but none of this legislation has been adopted. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Colorado, Pennsylvania, Texas, West Virginia and Wyoming have each adopted a variety of well-construction, set back, or disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure.
New York has placed a permit moratorium on high-volume fracturing activities combined with horizontal drilling pending the results of a study regarding the safety of hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, these laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. See “-Risks Associated with Hydraulic Fracturing.”
Risks Associated with Hydraulic Fracturing
We successfully deployed hydraulic fracturing in connection with our 2009 Marcellus PA Westmoreland/Marcellus Shale Project I Joint Venture well and generally expect to utilize hydraulic fracturing on all of the wells we drill in the Marcellus Shale in Pennsylvania (and when permitted, in New York). Because we use hydraulic fracturing, our current and future operations are, and are expected to be, subject to material financial and operational risks associated with hydraulic fracturing, such as underground migration and the surface spillage or mishandling of fracturing fluids, including chemical additives. The risks associated with hydraulic fracturing include the following risks among others:
If we are unable to dispose of the water we use to facilitate hydraulic fracturing (or any water we remove from any strata) on a cost-effective basis or unable to comply with related environmental regulations, our ability to produce oil and gas commercially could be impaired. We believe that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs, especially shale formations such as the Marcellus Shale in Pennsylvania and in New York, when permitted). We expect to rely heavily on hydraulic fracturing. The hydraulic fracturing process we utilize in our current and future drilling, extraction and production operations is expected to require significant amounts of water. Hydraulic fracturing can require between three to five million gallons of water per horizontal well. In addition, hydraulic fracturing produces water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may significantly increase our operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance. Our ability to remove and dispose of water will affect our production, and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil.
New legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. The hydraulic fracturing process is typically regulated by state oil and gas commissions. Some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado and Wyoming have each adopted a variety of well construction, set back or disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. New York has placed a permit moratorium on high volume fracturing activities combined with horizontal drilling pending the results of a study regarding the safety of hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, these laws could make it more difficult or costly for us to perform fracturing to stimulate production. While the EPA has yet to take any action to enforce or implement its newly asserted regulatory authority under the Safe Drinking Water Act’s Underground Injection Control Program, industry groups have filed suit challenging the EPA’s recent decision. In addition at the federal level, the EPA’s commencement of a study of the potential environmental impacts of hydraulic fracturing activities, congressional investigation of hydraulic fracturing practices and legislation introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process all present additional risks to our use of the hydraulic fracturing process.
If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our hydraulic fracturing activities could become subject to additional permitting requirements and also to attendant permitting delays and potential increases in costs. Legislative and regulatory efforts at the federal level and in some states have sought to render permitting and compliance requirements more stringent for hydraulic fracturing. If new laws are enacted or new regulations adopted, these changes could have an adverse effect on our operations.
Government Regulation
General
All of our operations are conducted onshore in the United States. The U.S. natural gas and oil industry is regulated at the federal, state and local levels, and some of the laws, rules and regulations that govern our operations carry substantial penalties for noncompliance. These regulatory burdens increase our cost of doing business and, consequently, affect our profitability.
Regulation of Natural Gas and Oil Operations
Our exploration and production operations are subject to various types of regulation at the U.S. federal, state and local levels. Applicable regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation include, but are not limited to:
·the location of wells;
·the method of drilling and completing wells;
·the surface use and restoration of properties upon which wells are drilled;
·the plugging and abandoning of wells;
·the disposal of fluids used or other wastes generated in connection with operations;
·the marketing, transportation and reporting of production; and
·the valuation and payment of royalties.
Our operations are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells that may be drilled in a particular area) and the unitization or pooling of natural gas and oil properties. In this regard, some states, including Kentucky, where we hold oil properties, allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In Pennsylvania, where we hold natural gas interests, pooling is generally involuntary, but is currently voluntary with respect to drilling in the Marcellus Shale, where we currently conduct operations. As of the date of this report, a law has been recommended by Pennsylvania’s Marcellus Shale Advisory Commission. If passed by the state legislature, the law would require forced pooling within the Marcellus Shale. In areas where pooling is voluntary, it may be more difficult to form units and therefore, more difficult to fully develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of natural gas and oil we can produce and to limit the number of wells and the locations at which we can drill. There is currently no price regulation of our sales of natural gas, oil and natural gas liquids, although governmental agencies may elect in the future to regulate certain sales.
Environmental, Health and Safety Regulation
Our business operations and ownership and operation of natural gas and oil interests are subject to various federal, state and local environmental, health and safety laws and regulations pertaining to the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees or otherwise relating to pollution, preservation, remediation or protection of human health and safety, natural resources, wildlife or the environment. We must take into account the cost of complying with environmental regulations in planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities. In most instances, the regulatory frameworks relate to the handling of drilling and production materials, the disposal of drilling and production wastes and the protection of water and air. In addition, our operations may require us to obtain permits for, among other things,
·air emissions;
·the construction and operation of underground injection wells to dispose of produced saltwater and other non-hazardous oilfield wastes; and
·the construction and operation of surface pits to contain drilling muds and other non-hazardous fluids associated with drilling operations.
Federal, state and local laws may require us to remove or remediate previously disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations at contaminated areas or to perform remedial well plugging operations or response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and analogous state laws impose joint and several liabilities, without regard to fault or legality of the original conduct, on classes of persons who are considered responsible for releases of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and persons that disposed of or arranged for the disposal of hazardous substances at the site. CERCLA and analogous state laws also authorize the EPA, state environmental agencies and, in some cases, third parties to take action to prevent or respond to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such actions.
Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the natural gas and oil that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas and oil.
Other federal and state laws, in particular the federal Resource Conservation and Recovery Act, regulate hazardous and nonhazardous wastes. Under a longstanding legal framework, certain wastes generated by our natural gas and oil operations are not subject to federal regulations governing hazardous wastes, though they may be regulated under other federal and state laws. These wastes may in the future be designated as hazardous wastes and may thus become subject to more rigorous and costly compliance and disposal requirements.
We have made and will continue to make expenditures to comply with environmental, health and safety regulations and requirements. These are necessary business costs in the natural gas and oil industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental, health and safety laws and regulations, as well as claims for damages to property or persons, resulting from company operations, could result in substantial costs and liabilities, including civil and criminal penalties. We believe that we are in material compliance with existing environmental, health and safety regulations.
Safe Drinking Water Act. The federal Safe Drinking Water Act, or SDWA, and comparable state laws regulate the nation’s public drinking water supply by regulating “public water systems” as well as underground sources of drinking water. Under the SDWA, the EPA sets standards for drinking water quality and oversees the states, localities and water suppliers that implement those standards. The U.S. Congress is currently considering legislation referred to as the Fracturing Responsibility and Awareness of Chemicals Act to amend the SDWA to repeal an exemption from regulation for hydraulic fracturing. Although we believe that hydraulic fracturing is an important and commonly used process to stimulate oil or natural gas production, sponsors of this legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could permit third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, the proposed legislation could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens. This could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business, as well as delay the development of unconventional gas resources from shale formations that are not commercially viable without the use of hydraulic fracturing.
We have not incurred any costs associated with the above regulations to date; however, there can be no assurance that the costs required to comply with the regulations above will not be substantial. Furthermore, if we are deemed not to be in compliance with applicable environmental laws, we could be forced to expend substantial amounts to be in compliance, which would have a materially adverse effect on our available cash and liquidity, and/or could force us to curtail or abandon our current business operations.
Employees
As of December 31, 2012, we had 17 full-time employees. With the successful implementation of our growth strategy, management believes we may require additional employees in the future.
Reports to Stockholders
We are subject to the information reporting requirements of the Securities Exchange Act and we file reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K. The public may read and copy any materials we file with the SEC in the SEC’s Public Reference Section, Room 1580, 100 F Street N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Section by calling the SEC at 1-800-SEC-0330. Additionally, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, which can be found at http://www.sec.gov.
ITEM 1A.
ITEM 1A. RISK FACTORS
We are a “smaller reporting company” as defined by Rule 12b-2 under the Securities Exchange Act, and as such, are not required to provide the information required under this Item.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable to a smaller reporting company.
ITEM 2.
ITEM 2. PROPERTIES
Principal Office
We maintain our principal offices at 600 Parker Square, Suite 250, Flower Mound, Texas 75028. Our telephone number at that office is (214) 222-6500. Our current office space consists of approximately 7,800 square feet, under a 6 ½-year lease term which commenced October 1, 2012. The new lease allows for six months of free rent, and the 2013 monthly rental of $9,755 began on April 1, 2013. We believe this property is in good condition and suitable to carry on our business.
Oil and Gas Producing Activities
In January 2009, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. In addition to expanding the definition and disclosure requirements for crude oil and natural gas reserves, the new rule changes the requirements for determining quantities of crude oil and natural gas reserves. The rule requires disclosure of crude oil and natural gas proved reserves by significant geographic area, using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and allows the use of reliable technologies to estimate proved crude oil and natural gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. Reserve and related information for 2012 is presented consistent with the requirements of the rule.
Presented below are the estimates of our proved oil and natural gas reserves as of December 31, 2012 based upon a report prepared by ValueScope. All of our proved reserves are located in the United States.
Disclosure of Reserves
(1)Total Mcf equivalent (Mcfe), which is oil (bbl) converted to natural gas (Mcf) at the rate of 1 bbl to 6 Mcf.
As specified by the SEC regulations, when calculating economic producibility, the base product price must be the 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the prior 12-month period. The benchmark base prices used for this evaluation were $94.71 per barrel of oil for West Texas Intermediate oil at Cushing, Oklahoma, and $2.76 per Million British thermal units (MMBtu) for natural gas at Henry Hub, Louisiana. The oil and gas prices were adjusted on each well based on deductions such as quality, energy content and basis differential, as appropriate. Prices for oil and natural gas were held constant throughout the remaining life of the properties.
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows should not be construed as the market value of the reserves at the dates shown. The 10% discount factor required to be used under the provisions of applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry. The standardized measure of discounted future net cash flows is materially affected by assumptions about the timing of future production, which may prove to be inaccurate.
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserve estimates are considered proved if economic productivity is supported by either actual production or conclusive formation tests. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.
The process of estimating quantities of natural gas and crude oil reserves is complex, requiring significant judgments in evaluating available geological, geophysical, engineering and economic data. We have limited management and staff and are dependent upon outside consulting petroleum engineers who we annually engage to prepare estimates of our proved reserves associated with the majority of our producing properties. For the year ended December 31, 2012, reserve estimates were prepared by ValueScope, an independent financial evaluation firm with experience in oil and gas reserve valuation and analysis. ValueScope provided their report to our senior management team (Daro and Anita Blankenship, Nicola Blankenship, Martin N. Mayrath and Rodney Trout), which is responsible for oversight of our reserve information.
As of December 31, 2012, we had total estimated proved reserves of 808,830 Mcf of natural gas and 5,310 barrels of crude oil. Combined, these total estimated proved reserves are equivalent to 840,690 Mcf of natural gas.
Qualifications of Technical Persons and Internal Controls over the Reserves Estimation Process
We represent to ValueScope that we have provided all relevant operating data and documents, and in turn, we review the reserve reports provided by ValueScope to ensure completeness and accuracy. Management cautions that estimates of proved reserves may be imprecise and subject to revision based on production history, changes in royalty interests, price changes and other factors. The preparation of our natural gas and oil reserve estimates were completed in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) “Extractive Activities Oil and Gas (Topic 932) - Oil and Gas Reserve Estimation and Disclosure,” which includes the verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review.
Nicola Blankenship, our Vice President of Operations, is directly responsible for overseeing the preparation of our reserve estimates and providing the historical and other information regarding our properties to ValueScope. Such information includes ownership interest, natural gas and crude oil production, well test data, commodity prices and lease operating expenses. Mr. Blankenship’s job responsibilities during the last eight years have included daily monitoring of our producing wells, approval of expense billings and review of daily drilling reports.
The reserve estimates provided in this report were prepared by Greg Scheig, Principal and Energy Practice Leader of ValueScope. Mr. Scheig has more than 20 years of experience in valuation of oil and gas reserves and is a member of the Society of Petroleum Engineers. He holds a Bachelors of Science in Petroleum Engineering from the University of Texas at Austin. The process performed by Mr. Scheig and ValueScope to prepare reserve amounts, including its estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, is based in part on data provided by the Company. The estimates of reserves were determined by accepted industry methods. Methods utilized by ValueScope in preparing the estimates include extrapolation of historical production trends and analogy to similar producing properties. ValueScope believes the assumptions, data, methods and procedures utilized in preparing the estimates were appropriate for the purpose served by its report, and that it utilized all methods and procedures it considered necessary to prepare its report.
The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of our reserve estimates in accordance with SEC regulations. The preparation of reserve estimates are created by ValueScope and overseen by our management team, including Daro Blankenship, Anita Blankenship, Nicola Blankenship, Martin N. Mayrath and Rodney Trout.
Proved Undeveloped Reserves
At the end of 2012, our oil and gas reserves included 36,890 Mcf of proved undeveloped natural reserves. The proved undeveloped reserves consist of one natural gas well and one oil well that are expected to be converted into proved developed reserves by the fourth quarter of 2013.
Oil and Gas Production, Production Prices and Production Costs
The following table summarizes the annual sales volumes, average sales prices and lifting costs per equivalent unit for the years ended December 31, 2012, 2011 and 2010. Equivalent barrels of oil were obtained by converting gas to oil on the basis of their relative energy content-six thousand cubic feet of gas equals one barrel of oil. During 2012, 2011 and 2010 the average selling price for natural gas was $2.85, $4.29 and $5.06 per Mcf, respectively, and the average selling price for crude oil was $87.62, $89.31 and $75.69 per barrel, respectively.
(1)All natural gas production is located in Pennsylvania.
(2)All crude oil production is located in Kentucky and New York.
(3)Lifting cost represents lease operating expenses divided by the net volumes of production, and is measured in equivalent Mcf based on an energy content factor of six-to-one (i.e., six Mcf of natural gas to one barrel of oil). Lease operating expenses include normal operating costs such as pumper fees, operator overhead, salt water disposal, repairs and maintenance, chemicals, equipment rentals, production taxes and ad valorem taxes.
Drilling and Other Exploratory and Development Activities
We are the managing venturer of natural gas and crude oil drilling joint ventures and earn carried working interests in wells drilled on behalf of such joint ventures. During 2012, we drilled two oil wells, one of which was completed in 2012, and one of which has been drilled, and is expected to be fracked by the end of the third quarter of 2013. In 2011, we drilled three natural gas wells, two of which have been completed and are awaiting pipeline, and one which has been drilled and is expected to be fracked by the end of the third quarter of 2013.
Present Activities
As of December 31, 2012, we owned interests in six wells (0.68 net wells) two of which are producing and four that have been drilled and are awaiting completion in the Marcellus Shale formation in Pennsylvania and in New York.
Delivery Commitments
We are not currently committed to providing a fixed and determinable quantity of oil or gas under any existing contract.
Oil and Gas Properties, Wells, Operations and Acreage
Our natural gas and crude oil properties consist essentially of carried interests and working interests owned by us in various natural gas and oil wells on leases located in Kentucky, Pennsylvania and New York. Below is a brief synopsis of each of our core areas of operation:
Pennsylvania (Natural Gas). As of December 31, 2012, we owned working interests ranging from 1.2% to 100% in 69 gross (33.1 net) producing or capable of producing natural gas wells and net revenue interests in such wells ranging from .4% to 81.25% (or approximately 26.8 net wells), located in Centre, Clearfield, Jefferson and Westmoreland Counties of Pennsylvania.
Kentucky and New York (Crude Oil). As of December 31, 2012, we owned working interests ranging from 6.4% to 100% in 16 gross (1.0 to 16.0 net) producing or capable of producing oil wells and net revenue interests in such wells ranging from 4.6% to 87.5% (or approximately .7 to 14.0 net wells), located in Warren County, Kentucky and Cattaraugus County, New York. Ranges of gross and net wells are based on net working interest and revenue interest held in such wells.
Developed and Undeveloped Acreage. As of December 31, 2012, we had 4,926 gross acres (2,353 net acres) of proved developed leasehold acreage located in Pennsylvania, 600 gross acres (594 net acres) located in Kentucky, and 73 gross acres (5 net acres) located in New York. As of December 31, 2012, our undeveloped acreage consisted of 803 gross acres (52 net acres) located in Pennsylvania and 528 gross acres (34 net acres) located in New York.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Not applicable.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
part ii
ITEM 5.
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases Of Equity Securities
Market Information
Though our common stock was previously quoted on the Pink OTC Markets under the symbol “VDDA.PK,” there is currently no established public trading market for our common stock and we can give no assurance that one will develop in the future. As of December 31, 2012, there were no outstanding options or warrants to purchase, or securities convertible into, shares of our common stock and no shares of our common stock could be sold pursuant to Rule 144 under the Securities Act. As of the date hereof, we have not agreed to register any of our common stock under the Securities Act for sale by stockholders, are not publicly offering any of our common stock and are not proposing to publicly offer any of our common stock.
Stockholders
As of July 31, 2013, there were 1,110 holders of record of our common stock. Some of the shares of our common stock are held in either nominee name or street name brokerage accounts. The actual number of beneficial owners of such shares is not included in the foregoing number of holders of record.
Dividends
We have not declared or paid any cash dividends on our capital stock and do not anticipate paying any cash dividends on our capital stock in the foreseeable future. Payment of dividends on the common stock is within the discretion of our board of directors. The board of directors currently intends to retain future earnings, if any, to finance our business operations and fund the development and growth of our business. The declaration of dividends in the future will depend upon our earnings, capital requirements, financial condition and other factors deemed relevant by the board of directors.
Securities Authorized for Issuance Under Equity Compensation Plans
We do not have any compensation plans under which equity securities are authorized for issuance.
ITEM 6.
ITEM 6. Selected Financial Data
We are a “smaller reporting company” as defined by Rule 12b-2 under the Securities Exchange Act, and as such, are not required to provide the information required under this Item.
ITEM 7.
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Vadda is a publicly-held, independent energy company engaged primarily in the exploration for, and development of, natural gas and crude oil reserves. We generate our revenues and cash flows from two primary sources: profits from the difference between the amounts we received in turnkey fees from joint ventures we manage and our actual costs to conduct the joint ventures’ operations and proceeds from the sale of oil and gas production on properties we hold.
As of December 31, 2012, we owned interests in approximately 83 producing natural gas and oil wells. Our natural gas and oil production for 2012 consisted of 68,179 Mcf of gas and 305 bbls of oil. These amounts represent decreases of 19.4% from our 2011 gas production of 84,652 Mcf and 49.2% from our 2011 oil production of 600 bbls.
We began 2012 with estimated proved reserves of 1,301,610 Mcfe and ended the year with 840,690 Mcfe.
Implementation of Strategy
Our long-term growth strategy is primarily focused on building cash flow from developing crude oil reserves through drilling horizontal wells in southern New York and north central Pennsylvania and natural gas reserves on lease acreage in the Marcellus Shale and Utica Shale formations in southwestern Pennsylvania and eastern Ohio. We believe this strategy will create greater value for investors. As part of this strategy, we have formed the joint ventures discussed below.
2009 Mieka PA Westmoreland/Marcellus Shale Project I-Marcellus I JV
In June 2010, we formed our first drilling joint venture that consisted of wells targeting the Marcellus Shale formation. The 2009 Mieka PA Westmoreland/Marcellus Shale Project I (“Marcellus I JV”) received $2,304,000 in capital contributions from outside investors. As the managing venturer we contributed $23,273 of capital for a 1% interest in the joint venture, which equals a 0.44% working interest and a 0.36% net revenue interest in the joint venture wells. We also purchased $82,500 of the Marcellus I JV in January 2010 on the same terms and conditions as outside investors, which equals 1.63% working interest and 1.35% net revenue interest in the wells. In addition, we hold a 4.91% carried working interest (3.35% net revenue interest) in each of the wells, which is carried to the tanks, outside the joint venture. We also hold an additional 36.04% working interest (29.28% net revenue interest) in the wells outside the joint venture.
2010 Mieka PA/WestM/Marcellus Shale Project II-Marcellus II JV
The 2010 Mieka PA/WestM/Marcellus Project II (“Marcellus II JV”) was formed in January 2011. In October 2011, the Marcellus II JV was closed with total capital contributions of $4,435,200 from outside investors. The Marcellus II JV was originally formed to drill one vertical oil and gas well and one horizontal oil and gas well targeting the Marcellus Shale formation in Pennsylvania. In March 2013, the venture voted to acquire interest in two horizontal wells in New York in substitution for the horizontal well. As of March 31, 2013, the vertical well has been drilled, tested and completed and is awaiting a pipeline, and the horizontal wells have not commenced operations. Mieka holds a .77% carried working interest (0.00% net revenue interest) in the vertical well. As the managing venturer we contributed $44,800 of capital for a 1% interest in the joint venture, which equals a 0.44% working interest and a 0.36% net revenue interest in the vertical well and a 0.36% working interest and a 0.30% net revenue interest in the horizontal wells.
2011 Mieka/Jefferson-Cattaraugus Oil & Gas Project A-Mieka Jefferson A JV
The 2011 Mieka/Jefferson-Cattaraugus Oil & Gas Project A (“Mieka Jefferson A JV”) began accepting investor subscriptions in December 2011 and had received capital contributions of $6,147,417 as of July 31, 2013. The Mieka Jefferson A JV was originally formed to drill two gas wells, one vertical and one horizontal, targeting the Marcellus Shale formation and two horizontal oil wells, which were to be drilled to the 1st, 2nd or 3rd Bradford Sands formation in western New York. In March 2013, the venture voted to acquire interests in two horizontal wells in New York in substitution for the horizontal gas well. As of July 31, 2013, the vertical natural gas well had been drilled, tested, and fracked. One of the horizontal wells has been drilled, tested and completed, another of the horizontal wells has been drilled and tested, and the other two horizontal wells have not yet commenced operations. Mieka holds a 6% carried working interest (4.25% net revenue interest) in the wells that have commenced operations, and will hold a 4% carried working interest (3.4% net revenue interest) in the wells that have not commenced operations. As the managing venturer we have contributed $86,616 of capital for a 1% interest in the joint venture, which equals a 0.44% working interest and a 0.36% net revenue interest in the wells that have commenced operations and will equal a 0.36% working interest and a 0.30% net revenue interest in the wells that have not commenced operation.
Additionally, Mieka LLC holds a 10% working interest (8.12% net revenue interest) in one of the wells that has commenced operations.
Mieka LLC purchased $612,500 of joint venture units in December 2011, which represents a 3.11% working interest and 2.57% net revenue interest in the wells.
Oil and Gas Operating Statistics
Our management team has defined and tracks performance against several key production, sales and operational performance indicators, including, without limitation, the following:
- average daily natural gas and oil production;
- weighted average sales price received for natural gas and oil; and
- lifting costs.
We believe that tracking these performance indicators on a regular basis enables us to better understand whether we are on target to achieve our internal production, sales and other plans and projections and forecast working capital, cash flow and liquidity items and allows us to determine whether we are successfully implementing our strategies.
The following table sets forth information regarding production volumes, average sales prices received and lifting costs for the periods indicated:
Production Volumes, Sales Prices and Lifting Costs
(1) All natural gas production is located in Pennsylvania.
(2) All crude oil production is located in Kentucky and New York.
(3) Lifting cost represents lease operating expenses divided by the net volumes of production, and is measured in equivalent Mcf based on an energy content factor of six-to-one (i.e., six Mcf of natural gas to one barrel of oil). Lease operating expenses include normal operating costs such as pumper fees, operator overhead, salt water disposal, repairs and maintenance, chemicals, equipment rentals, production taxes and ad valorem taxes.
Results of Operations
Comparison of Year Ended December 31, 2012 to Year Ended December 31, 2011
Total Revenues. Total revenues increased $3,519,614, or 840.0%, to $3,938,637 for 2012 from $419,023 for 2011, driven primarily by the recognition of turnkey drilling revenues in 2012.
Turnkey Drilling Revenues. Turnkey drilling revenues were $3,733,168 in 2012, compared to $0 in 2011. Currently prescribed accounting rules require a well to be drilled and completed before turnkey revenues can be recognized. Turnkey drilling revenues of $2,605,600 received from investors during the year ended December 31, 2011 were not recognized as income in 2011 and deferred to 2012 because of certain requirements of U.S. generally accepted accounting principles.
.
Natural gas and oil sales. Natural gas and oil sales decreased $215,805 or 51.5%, to $203,218 for 2012 from $419,023 for 2011, due to normal production decline in existing wells, coupled with a decrease in the price of natural gas. The average price for 2012 was $2.85 compared to $4.29 in 2011.
Costs and Expenses. Total costs and expenses increased $2,634,625, or 61.9%, to $6,889,987 for the year 2012 from $4,255,362 for 2011. This increase was due to the recognition of turnkey drilling costs of $1,970, 417 in 2012, compared to $0 in 2011. In addition, 2012 included a charge for the impairment of goodwill of $2,740,171, compared to $0 in 2011. Refer to the Critical Accounting Policies and Estimates section for further details on the goodwill impairment. These increases were offset by the recognition in the prior year of a valuation allowance of $1,832,500 recorded on the prepayment to operator. General and administrative expenses decreased $2,030,205, or 51.8%, to $1,885,912 for the year 2012 from $3,916,117 for the previous year primarily due to the valuation allowance.
Net Loss. Net loss was $3,085,623 or $0.03 per basic and diluted common share, for the 2012 as compared to $3,123,092, or $0.03 per basic and diluted common share, for 2011. The decrease in net loss of $37,469 was attributable primarily to the valuation allowance recorded on the prepayment to operator in 2011 and net profit on turnkey drilling earned in 2012, offset by the goodwill impairment charge in 2012. Net loss represents a consolidated net loss which includes a loss of $35,123 attributable to Mieka LLC. Mieka LLC is a variable interest entity that is not owned by the Company but which shares common control. Due to Mieka LLC’s ownership and dependence upon the Company and its subsidiaries for its cash flows, its financial information is required to be consolidated with Vadda’s and Mieka’s financial statements under variable interest entity accounting. See Note 9 to our audited consolidated financial statements included elsewhere in this report.
Liquidity and Capital Resources
Sources and Uses of Funds
Cash flow from operations is our most significant source of liquidity. We generate our operating cash flow from two primary sources:
Turnkey oil and gas drilling joint ventures, from which we generally receive turnkey fees (which generate profits to the extent the turnkey price we charge to the joint ventures exceeds the actual costs necessary to acquire leases and drill, test and complete wells for such joint ventures) and carried working interests in such wells (which generate monthly revenue and cash flow to the extent such wells produce natural gas and oil), as well as interests in such joint ventures purchased by the Company (which also generate monthly revenue and cash flow to the extent such wells produce natural gas and oil); and
Natural gas and oil sales, which are generally attributable to working interests owned and held directly by us in wells on producing oil and gas properties (which generate monthly revenue and cash flow to the extent such wells produce natural gas and oil) and carried working interests in such wells (which also generate monthly revenue and cash flow to the extent such wells produce natural gas and oil), as well as overriding royalty interests and reversionary interests (which may generate additional monthly revenue and cash flow to the extent such wells produce natural gas and oil).
Cash and cash equivalents totaled $358,519 as of December 31, 2012, as compared to $1,382,166 as of December 31, 2011. Cash (used in) / provided by operating activities was ($917,986) for the year ended December 31, 2012, compared to $174,988 for the year ended December 31, 2011.
Changes in cash flows from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as impairments of assets, depreciation, depletion and amortization and deferred income taxes. For example, changes in turnkey drilling revenues, production volumes and market prices for natural gas and oil directly impact the level of our cash flow from operations. See the discussion herein under “Results of Operations.”
Although our long-term growth strategy calls for an increased focus on our own natural gas and oil operations and we intend to rely less on turnkey drilling revenues in the future, we expect to continue our reliance on these sources of liquidity in the future. We use cash flows from operations to fund expenditures related to our exploration, development and acquisition of natural gas and oil properties. We have historically obtained most of the capital to fund expenditures related to our turnkey drilling ventures from the sale of interests in the joint ventures to outside participants. Since 2001, we have raised approximately $44.3 million from outside investors in 32 joint ventures that drilled 167 oil and gas wells.
However, our ability to raise capital from outside investors through joint ventures is dependent upon the ability of the investors to deduct intangible drilling costs on their federal income tax returns. If there are changes to the U.S. tax laws to eliminate or significantly limit this deduction, it could materially adversely affect our ability to fund our turnkey drilling operations and generate our turnkey drilling revenues.
In addition to cash flows from operations, we have in the past obtained capital through sales of our common stock and may seek to generate additional capital through the issuance of our debt or equity securities in the future, including sales of convertible preferred stock, senior notes, contingent convertible senior notes and common stock of the Company.
We used $57,028 of cash for financing activities during the year ended December 31, 2012, compared to $21,635 generated from financing activities for the year ended December 31, 2011. We used $48,632 of cash for investing activities during the year ended December 31, 2012, compared to $651,414 used for investing activities for the year ended December 31, 2011.
Although we typically retain a significant degree of control over the timing of our capital expenditures, we may not always be able to defer or accelerate certain capital expenditures to address any potential liquidity issues. In addition, changes in drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary.
As of December 31, 2012, we had a working capital deficit of $4,965,172, which consisted of $1,182,650 of current assets offset by $6,147,822 of current liabilities. Current assets as of December 31, 2012 included cash of $358,519, prepaid drilling costs of $455,009, receivable from affiliate of $280,046, accounts receivable of $59,146 and deferred income tax of $29,930. Current liabilities as of December 31, 2012 included deferred revenue of $5,796,556, accounts payable and accrued liabilities of $298,095, payable to stockholders of $45,319, and current portion of note payable of $7,852.
As of December 31, 2011, we had a working capital deficit of $3,961,546, which consisted of $2,993,054 of current assets offset by $6,954,600 of current liabilities. Current assets as of December 31, 2011 included cash of $1,382,166, deferred income tax of $835,275, prepaid drilling costs of $699,836 and accounts receivable of $75,777. Current liabilities as of December 31, 2011 included deferred revenue of $6,528,474, accounts payable and accrued liabilities of $248,106, payable to affiliate of $75,659, payable to stockholders of $88,564 and current portion of note payable of $13,797.
Outlook
We believe that our future growth is dependent on our ability to:
generate turnkey drilling revenues and profits;
obtain carried interests in wells drilled by new joint ventures;
directly participate in wells drilled in the Marcellus Shale, Utica Shale and oil sands in New York, Pennsylvania and eastern Ohio; and
raise additional capital through debt or equity offerings.
We may not be able to raise additional capital or generate turnkey drilling revenues or profits in amounts sufficient to fund such growth. If we are unable to achieve a sufficient level of cash inflows and/or cannot secure equity financing on satisfactory terms, we may be unable to expand our operations and meet our current obligations. Additional equity financings are likely to be dilutive to holders of our common stock and debt financings, if available, may involve significant payment obligations and covenants that restrict how we operate our business.
Critical Accounting Policies and Estimates
Management’s discussion and analysis of financial condition and results of operations are based upon our audited consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate such estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Below, we have provided expanded discussion of the more significant accounting policies, estimates and judgments. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of our consolidated financial statements. Please read the notes to our audited consolidated financial statements included elsewhere in this report for a discussion of additional accounting policies and estimates made by management.
Oil and Gas Producing Activities
Our oil and gas producing activities were accounted for using the successful efforts method of accounting. Costs to acquire leasehold rights in oil and gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed.
We earn carried working interests in wells drilled by joint ventures that we manage. Upon the successful completion of a well, the joint venture is assigned leasehold rights on acreage that comprises the legal spacing for the well. The joint ventures pay 100% of the drilling and completion costs. We also intend to have ownership in wells drilled in the Marcellus Shale on leases in which its joint ventures do not participate.
Depletion and Depreciation
Estimates of natural gas and oil reserves utilized in the calculation of depletion are prepared using certain assumptions. Reserve estimates are based upon existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. Natural gas and oil reserve estimates are inherently imprecise and are subject to change as more current information becomes available. Capitalized costs are depleted and amortized using the units of production method, based upon reserve estimates.
Impairments
The carrying value of oil and gas properties is assessed for possible impairment on at least an annual basis, or as circumstances warrant, based on geological analysis or changes in proved reserve estimates. When impairment occurs, an adjustment is recorded as a reduction of the asset carrying value.
Asset Retirement Obligations
A provision has been recorded for the estimated liability for the plugging and abandonment of natural gas and oil wells at the end of their productive lives. The liability and the associated increase in the related asset are recorded in the period in which the asset retirement obligation, or ARO, is incurred. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.
The estimated liability is calculated using the estimated remaining lives of the wells based on reserve estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs.
The Company recognized $10,632 and $52,502 of accretion expense in 2012 and 2011, respectively. This difference is due to an adjustment to the well lives in 2011 to more accurately reflect economic lives.
Goodwill
In 2009, the Company recorded $2,740,171 of goodwill related to the acquisition of certain oil and gas joint ventures, as more fully described in Note 1. Goodwill represents the excess of the purchase price over the fair value of the net assets acquired. The Company follows FASB ASC Topic 350, “Goodwill and Intangible Asset Impairment Testing.”
The Company tests goodwill for impairment annually at December 31, or more frequently as circumstances dictate. The first step in assessing whether an impairment of goodwill is necessary is an optional qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is greater than its carrying amount. If the Company concludes that fair value of the reporting unit more than likely exceeds the related carrying amount, then goodwill is not impaired and further testing is not necessary.
If the qualitative assessment is not performed or indicates fair value of the reporting unit may be less than its carrying amount, the Company compares the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill, and determines whether an impairment is necessary. Because quoted market prices for the Company’s reporting units are not available, management must apply judgment in determining the estimated fair value of reporting units for purposes of performing goodwill impairment tests. Management uses all available information to make these fair-value estimates, including the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets and observed for the oil and gas exploration and production reporting unit, and market multiples of earnings before interest, taxes, depreciation, and amortization (EBITDA). In estimating the fair value of its oil and gas exploration and production, the Company assumes production profiles utilized in its estimation of reserves that are disclosed in the Company’s supplemental oil and gas disclosures, market prices based on the forward price curve for oil and gas at the test date (adjusted for location and quality differentials), capital and operating costs consistent with pricing and expected inflation rates, and discount rates that management believes a market participant would utilize based upon the risks inherent in the Company’s operations.
In the second step, the reporting unit's fair value is allocated to all of the assets and liabilities of the reporting unit, including any unrecognized intangible assets, in a hypothetical analysis that calculates the implied fair value of goodwill in the same manner as if the reporting unit was being acquired in a business combination. If the implied fair value of the reporting unit's goodwill is less than the carrying value, the difference is recorded as an impairment loss. We also compare the fair value of purchased intangible assets with indefinite lives to their carrying value. We estimate the fair value of these intangible assets using an income approach. We recognize an impairment loss when the estimated fair value of intangible assets with indefinite lives is less than the carrying value.
The goodwill impairment tests as of December 31, 2012 indicated the fair value of the Company was significantly below the carrying value of its net assets. A decrease in gas prices and a reduction in the revenue forecast resulted in a lower calculated fair value of the Company from the prior year. An impairment loss of $2,740,171 was recorded in 2012, which represents 100% of the value of goodwill on the Company’s books. No impairment loss had been recognized in 2011.
Pricing Mechanism for Oil and Gas Reserves Estimation
The SEC rules require reserve estimates to be calculated using a 12-month average price. Price changes may be incorporated to the extent defined by contractual arrangements.
The rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if economic recoverability can be established with reasonable certainty. These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells. Because the revised rules generally expand the definition of proved reserves, proved reserve estimates could increase in the future based upon adoption of the revised rules.
Unproved Reserves
The SEC’s prior rules prohibited disclosure of reserve estimates other than proved in documents filed with the SEC. The revised rules permit disclosure of probable and possible reserves and provide definitions of probable reserves and possible reserves. Disclosure of probable and possible reserves is optional. We are not including any disclosures pertaining to probable or possible reserves. In January 2010, the FASB issued an Accounting Standards Update (ASU) 2010-03, “Extractive Industries-Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosure.” This ASU amends the FASB accounting standards to align the reserve calculation and disclosure requirements with the requirements in the new SEC Rule, Modernization of Oil and Gas Reporting Requirements. The ASU is effective for reporting periods ending on or after December 31, 2009.
Recently Issued Accounting Standards
The SEC and FASB continually adopts new reporting requirements and makes revisions to existing disclosures required for oil and gas companies, which are intended to provide investors with a more meaningful and comprehensive understanding of such information. There have been no new pronouncements issued which impacted the company in the current year, except as noted below.
Impairment
In September 2011, the FASB issued an update to existing guidance on testing goodwill for impairment. This update simplifies the assessment of goodwill for impairment by allowing an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If impairment is indicated, it is necessary to perform the two-step impairment review process. It also amends the examples of events or circumstances that would be considered in a goodwill impairment evaluation. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We have adopted the new guidance in fiscal 2012.
ITEM 7A.
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
We are a “smaller reporting company” as defined by Rule 12b-2 under the Securities Exchange Act, and as such, are not required to provide the information required under this Item.
ITEM 8.
ITEM 8. Financial Statements AND SUPPLEMENTARY DATA
The report of our independent registered public accounting firm and our consolidated financial statements, related notes and supplementary data are included as part of this annual report beginning on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.
Not applicable.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain disclosure controls and procedures as defined in Rule 13a-15(e) or 15d-15(e) under the Securities Exchange Act, which (1) are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (2) include controls and procedures designed to ensure that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or the person or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Our management evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of such disclosure controls and procedures as of December 31, 2012, the end of the period covered by this report, as required by paragraph (b) of Rule 13a-15 or Rule 15d-15 under the Securities Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at a reasonable assurance level as of December 31, 2012. Management took significant steps to improve its disclosure controls and procedures during 2012. Management continues to take steps to improve its disclosure controls and procedures.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Securities Exchange Act Rule 13a-15(f). Our internal control over financial reporting is designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, effectiveness of internal control over financial reporting may vary over time.
A significant deficiency is a deficiency, or a combination of deficiencies, in internal control over financial reporting that is less severe than a material weakness, yet important enough to merit attention by those responsible for oversight of the company’s financial reporting. 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 the company’s annual or interim financial statements will not be prevented or detected on a timely basis.
Our management, with the participation and under the supervision of our Chief Financial Officer, evaluated and assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this report. In making this assessment, management used the criteria set forth in the Internal Control - Integrated Framework by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). We evaluated control deficiencies identified through our test of the design and operating effectiveness of controls over financial reporting to determine whether the deficiencies, individually or in combination, are significant deficiencies or material weaknesses. In performing the assessment, our management has identified the following material weaknesses:
Lack of adequate internal control over preparation of required disclosures for financial reporting.
Inadequate control over accounting records, which required material journal entries.
Lack of segregation of duties throughout the organization due to the small size.
Based upon management’s assessment and its identification of such material weaknesses, management concluded that our internal control over financial reporting was not effective as of December 31, 2012. During 2013, management has taken steps to correct such weaknesses in internal control over financial reporting and continues to take steps to improve its internal control over financial reporting.
This annual report does not include an attestation report of our 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 rules of the Securities and Exchange Commission that permits the Company, as a smaller reporting company, to provide only management’s report in this annual report.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the year ended December 31, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors, Executive Officers and Other Key Officers
Our directors, executive officers and other key officers, and their ages and positions, are as follows:
Set forth below is a biographical description of each director, executive officer and other key officer of the Company.
Daro Blankenship. Mr. Blankenship was named our President and Chief Executive Officer in April 2009, and was appointed a Director of the Company in March 2013. He is also the Founder and Managing Director of Mieka, where he has worked since 2001. From 1995 to May 2001, he was the President and controlling stockholder of Realtec Real Estate Corporation in Dallas, Texas. Mr. Blankenship was formerly the Vice President of Operations for SonWest Resources, Inc., an independent oil company in Dallas, Texas concentrating on the operation of producing properties. Mr. Blankenship is a director of The Mieka Foundation, a 501(c)(3) charitable organization that provides financial support to abused children, the elderly, families in need and animal protection causes. Mr. Blankenship attended Vincennes University in Indiana and is married to Anita Blankenship, our Chairwoman of the Board of Directors and Executive Vice President, and is also the father of Nicola Blankenship, our Vice President of Operations/Public Relations.
Anita G. Blankenship. Ms. Blankenship has served as our Chairwoman of the Board of Directors as well as Executive Vice President and Assistant Secretary since July 2005. From July 2003 until April 2009, she acted as our President and Chief Executive Officer. She is also the President and Chief Executive Officer of Mieka. Ms. Blankenship is also the Chief Executive Officer and principal owner of Realtec Mortgage Corporation and a Vice President of Realtec Real Estate Corporation, now inactive businesses. Until 1997, Ms. Blankenship was the president of SonWest Resources, Inc., an independent oil company in Dallas. Ms. Blankenship is the founder and a director of the Mieka Foundation, a 501(c)(3) charitable organization that provides financial support to abused children, the elderly, families in need and animal protection causes. Ms. Blankenship attended Wright State University and is married to Daro Blankenship, our President and Chief Executive Officer and is also the mother of Nicola Blankenship, our Vice President of Operations/Public Relations. Ms. Blankenship has voting and investment control over the shares held by Moarmoff Trust, our majority stockholder.
Martin N. Mayrath. Mr. Mayrath has served as our Chief Financial Officer since August 2012. He is also the principal of Mayrath & Company, PC, a public accounting firm that provides accounting and tax services, including part time CFO services, and accounting system design, implementation and on-going maintenance and review to clients for over 35 years. Mayrath & Company, PC, has been engaged by the Company and its subsidiaries, since 2004 and currently assists in its financial and tax reporting. Mr. Mayrath began his career with Condley & Company, Abilene, Texas in 1973, where he became licensed as a certified public accountant. During his tenure at Condley & Company, he focused on all aspects of oil and gas accounting and taxation, including working extensively on private placement joint ventures. Mr. Mayrath graduated from the University of Texas in 1973 and is a member of the American Institute of Certified Public Accountants, the Texas Society of Certified Public Accountants and the Dallas CPA Society. He is also a member of the Council of Petroleum Accountants Societies.
Verne Rainey. Mr. Rainey has served as a director since July 2003 and has also served as a director of both Mieka and Mieka Foundation, a 501(c)(3), charitable organization, since their inception. Mr. Rainey has been retired for the past five years. Mr. Rainey served as a professional pilot for American Airlines from 1965 to 1997 and was also a United States Air Force Captain. He holds a B.S. in Mechanical Engineering with a minor in Mathematics from Grove City College in Grove City, Pennsylvania.
Terrell A. Dobkins Mr. Dobkins was elected a director is 2012, and has over thirty years of experience as an energy industry executive. He trained as a petroleum engineer with Amoco Production Company and Amoco Research before moving on to American Hunter Exploration and Barrett Resources Corporation.. After leaving Barrett Resources in 1998, Mr. Dobkins was the Vice President-Production at the start up, Pennaco Energy. Pennaco was sold to Marathon in 2001. Subsequently, in August, 2002, Mr. Dobkins was a key executive in the start up of Antero Resources as Vice President-Production. In August, 2007, Mr. Dobkins was a principal founder of Rimrock Energy, LLC. Mr. Dobkins left Rimrock Energy in January, 2009 to pursue an opportunity in the Marcellus.
Nicholas Steinsberger Mr.Steinsberger was elected a director in 2012, and began his career with Mitchell Energy & Development in 1987. After the sale of Mitchell Energy to Devon Energy in January 2002, Mr. Steinsberger continued as Completion Manager for the Barnett Shale and was responsible for development of the first 30 horizontal wells. In July, 2003, Mr. Steinsberger became Vice-President - Engineering for Republic Energy, responsible for drilling and completing approximately 30 wells in the Barnett Shale in a one year period before selling their assets to Burlington. After the sale, Mr. Steinsberger started a consulting business.
Richard Patterson Smith. Mr. Smith was elected a director in 2012. He is the founder and owner of Technological Solutions International since 1995, which provides technical, marketing, and management consulting support in solving engineering, technology and operational problems associated with remote sensing, mission management, and system deployment, employment and sustainment. Previously he was Vice-President, Board Member and General Manager for Geodynamics Corporation. Prior to that he held various positions within the US Air Force, including Director of Electronic Combat, Space, Reconnaissance & Surveillance, and Soviet Radio Electronic Combat Studies; Director of Intelligence Collection Management; and Staff Officer, Deputy Chief of Staff, Plans, Directorate of Aeronautical and Future Requirements and Program Manager for Strategic Air Command’s Reconnaissance Systems.
Robert Myers. Mr. Myers has served as our Vice President of Project Development since April 2009. He has been the Vice President of Project Development of Mieka since 2005, where he is responsible for strategic planning of projects. Mr. Myers has been in the oil and gas industry since 1972. He was the Executive Vice President of the Federal Energy Corporation from 1974 to 1981. In 1981 he founded Janus International, Inc., an independent oil company, and Janus Securities Corporation. As Chief Executive Officer of Janus International, Mr. Myers was responsible for day-to-day operations, including drilling and completion operations in Kansas and Texas. He was President and Chief Executive Officer of Myers Operations, an independent oil company from 1984 to 1999, where he oversaw all drilling and leasing operations. In addition, Mr. Myers was a member of a coalition of independent oil and gas operators that convened with the Chairman of the U.S. Senate’s Ways and Means Committee to discuss national energy policies. Mr. Myers graduated from University of Wyoming with a B.S. in Mathematics in 1969.
Rodney Trout. Mr. Trout has served as our Vice President of Accounting since July 2012. From February 2010 to June 2012, he served as Office Manager/Accountant for our CPA firm at Mayrath & Company. From September 2008 to February 2010, he served as Chief Accountant/Corporate Treasurer for Audio Video Marketing, LTD. From September 2001 to August 2003, he served as Controller/Accounting Supervisor for Audio Video Distributing, LTD and AVAD, a wholesale distributor in audio/video electronics. From September 1984 to December 2000, he served as Controller/Accounting Supervisor for Campbell Associates, Inc., a wholesale distributor for high-tech medical equipment. Mr. Trout received a Bachelor of Business Administration in 1972 from Texas Tech University.
Nicola D. Blankenship. Mr. Blankenship has served as our Vice President of Operations/Public Relations since April 2009. He has been employed by Mieka since 2003 and has served as its Vice President of Public Relations since June 2004. Mr. Blankenship was Vice President of Operations for Realtec Mortgage Corporation from 2000 to 2002, where he initiated and performed corporate oversight of operations and management of mortgage offices throughout the United States. Mr. Blankenship is a director of The Mieka Foundation, a 501(c)(3) charitable organization that provides financial support to abused children, the elderly, families in need and animal protection causes. He graduated from Texas Bible Institute and attended Brookhaven College. Mr. Blankenship is the son of Anita and Daro Blankenship.
Stephen Romo. Mr. Romo has served as our Vice President of Marketing since May 2009. He has been Venture Representative of Mieka since 2004, where he is responsible for facilitating funding of drilling projects. He was the Vice President of Marketing and Broker for Coldwell Banker Romo Realtors from 1992 until 2003. Mr. Romo attended Richland Junior College for two years before attending the University of North Texas.
Robert Thompson. Mr. Thompson has served as Vice President of Drilling and Field Engineering since June of 2012. Mr. Thompson has over 25 years experience in both National and International Hydrocarbon Recovery Projects. He has managed drilling projects within the major basins in the United States to include the Anadarko, Permian, San Juan, and the extraction of the hydrocarbons reserves in the Barnett and Marcellus Shale formations. As Project Manager and Well Site Consultant Engineer, Mr. Thompson has worked with Exxon-Mobile, Conoco Phillips and as a liaison Project Manager for Almansoori Specialized Engineering to Kuwait Oil Company and the Kuwaiti Government. Currently Mr. Thompson is the Vice President of Drilling Operations and Field Engineering for Mieka Energy and directs it’s drilling operations involving high pressure vertical and multi-lateral directional G.P.S. projects in the Marcellus Shale and Upper/Middle Devonian Sandstones Productive Horizons in New York and Pennsylvania.
Zhenhao C. Hong. Mr. Hong has been the Vice President of Asian Relations of Mieka Corporation since October 2011. He previously served as Vice President of Accounting of Mieka Corporation and also served as the Vice President of Accounting for Vadda Corporation. Mr. Hong is a certified public accountant licensed in Texas. Prior to joining Mieka he was an accountant for Sino-US Evening News and auditor for Grant Thornton LLP. He also worked for Future Uptrend LLC as a business consultant. Mr. Hong graduated from the University of Texas at Austin with a Masters degree in Accounting.
Involvement in Certain Legal Proceedings
In April 2011, in the Matter of Mieka Corporation, Daro Blankenship and Stephen Romo, Case No. XY-11-CD-11, Fred J. Joseph, the Colorado Securities Commissioner and the Colorado Division of Securities entered a Final Cease and Desist Order (the “Order”) against Mieka, Daro Blankenship and Stephen Romo (the “Respondents”) (1) directing the Respondents to refrain from committing or causing any violations of Sections 301, 401 or 501 of the Colorado Securities Act, or otherwise engaging in conduct in violation of the Colorado Securities Act, (2) providing that the offer of interests in Colorado required registration under Colorado Revised Statute Section 11-51-301 or that an exemption to such registration was available, and (3) providing that the Respondents violated provisions of the Colorado Securities Act relating to the employment of securities broker/dealers or sales representatives. The Respondents appealed the Order to the Colorado Court of Appeals in May 2011. The appellate court affirmed the Order on May 10, 2012.
In May 2005, the Indiana Securities Commissioner entered an Order directing Mieka and Daro Blankenship to cease and desist from violations of Sections 23-2-1-3, 23-2-1-8(a)&(b), and 23-2-1-12 of the Indiana Securities Act. The Indiana Order, which was brought against, among others, Mieka, a joint venture for which Mieka served as managing venturer, and Daro Blankenship, alleged Mieka and Mr. Blankenship (1) offered securities in Indiana without an exemption from registration, (2) violated provisions of the Indiana Securities Act relating to the registration and employment of securities broker/dealers and/or agents and (3) made misrepresentations and/or omissions of material facts in connection with the offer of a security. The Indiana Order was entered without notice to Mieka or Mr. Blankenship and without providing Mieka or Mr. Blankenship an opportunity to respond or present its position on any issue.
Except as described in the preceding two paragraphs, during the past ten years, none of our other directors, executive officers or other key officers was involved in any legal proceedings that are material to an evaluation of the ability or integrity of such directors and officers.
Election of Directors and Officers
Our board of directors is currently composed of five members. Each directors serves for an annual term or until his or her successor is duly elected and qualified by a plurality vote at the next annual meeting of the stockholders, subject to his or her earlier resignation, removal by the stockholders (by majority vote of the shares issued and outstanding and entitled to vote) or death. Any vacancy occurring in the board of directors may be filled by the vote of a majority of the directors then in office, though less than a quorum, or at a special meeting of stockholders called for that purpose. A director elected to fill a vacancy is elected for the unexpired term of his or her predecessor in office or his or her successor is duly elected and qualified, subject to his or her earlier resignation, removal by the stockholders (by majority vote of the shares issued and outstanding and entitled to vote) or death.
Officers are elected by the board of directors at its annual meeting and hold office until the next annual meeting of the board of directors or until their respective successors are duly elected and qualified.
Code of Ethics
Our board of directors has not yet adopted a code of ethics that applies to our Chief Executive Officer and senior financial officers. However, the board of directors is in the process of developing such a code of ethics and intends to adopt such a code of ethics sometime in 2013.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The summary compensation table below sets forth information concerning the compensation of our named executive officers (as defined in the SEC’s Regulation S-K) for 2011 and 2012, including all compensation awarded to, earned by or paid to each named executive officer for all services rendered to the Company by such person in all capacities during each such year.
Narrative Disclosure to Summary Compensation Table
We paid salaries to each of the named executive officers in each of 2011 and 2012. No bonuses were paid in 2011 or 2012. All compensation and bonuses were paid in cash pursuant to standard company payroll practices. We do not have arrangements with any of our employees, including the named executive officers, to pay or provide any non-cash compensation. None of the named executive officers are a party to an employment agreement and all serve at the discretion of our board of directors.
Martin N. Mayrath is a principal of Mayrath & Co., PC, which has been engaged by the Company to perform the function of Chief Financial Officer, in addition to providing tax services. In 2012, the Company paid a total of $103,562 to Mayrath & Co. for their services.
Compensation of Directors
We had two directors, Anita Blankenship and Verne Rainey, during the year ended December 31, 2012. During the year ended December 31, 2012, neither Ms. Blankenship nor Mr. Rainey received any cash or equity compensation for their services as directors of the Company.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth certain information regarding beneficial ownership of our common stock as of December 31, 2012, by:
each of our named executive officers;
each of our directors;
each person who is known by us to beneficially own more than 5% of our common stock; and
all of our executive officers and directors as a group.
The table gives effect to the shares of common stock that could be issued to the named stockholder or group upon the exercise of outstanding options, warrants, convertible securities and other rights held by the stockholder or group within 60 days of December 31, 2012. Unless otherwise noted in the footnotes to the table and subject to community property laws where applicable, the following persons have sole voting and investment control with respect to the shares beneficially owned by them. The address of each person known to us to beneficially own more than 5% of any class of our voting stock is set forth in the table. The address of each executive officer and director is c/o Vadda Energy Corporation, 600 Parker Square, Suite 250, Flower Mound, Texas 75028.
(1)Based upon 104,235,236 shares of common stock outstanding as of December 31, 2012.
(2)Includes (a) 2,650,000 shares of common stock held of record by his wife, Anita Blankenship, (b) 76,750,000 shares of common stock held of record by Moarmoff Trust, of which his wife, Anita Blankenship, is sole trustee, and (c) 967,708 shares held of record by Two Ships LLC, a company owned by Daro and Anita Blankenship.
(3)Includes (a) 2,650,000 shares of common stock held of record by her husband, Daro Blankenship, (b) 76,750,000 shares of common stock held of record by Moarmoff Trust, of which Ms. Blankenship is the sole trustee and (c) 967,708 shares held of record by Two Ships LLC, a company owned by Daro and Anita Blankenship.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Related Party Transactions
Pursuant to an arrangement between the Company and Mieka LLC, an entity wholly owned by our principal stockholders, Mieka LLC provides drilling and completion services on wells owned by the Company. Prices charged to the Company by Mieka LLC under turnkey drilling arrangements do not reflect prevailing rates that would be charged by outside third parties in arms-length transactions. During the year ended December 31, 2012 and 2011, the Company incurred drilling costs associated with turnkey drilling contracts with Mieka LLC of $1,935,117 and $669,836, respectively. As of December 31, 2012 and 2011, the Company was obligated to pay $1,562,206 and $662,292, respectively, to Mieka LLC.
In 2012, Mieka LLC was charged an administrative fee of $96,000 from Vadda Energy Corporation and $408,000 from Mieka Corporation. This activity is eliminated in the consolidated financial statements.
During the years ended December 31, 2012 and 2011, Daro and Anita Blankenship, principal shareholders of the Company, received aggregate compensation from the Company of $229,500 and $238,500, respectively.
Martin N. Mayrath is a principal of Mayrath & Co., PC, which has been engaged by the Company to perform the function of Chief Financial Officer, in addition to providing tax services. In 2012, the Company paid a total of $103,562 to Mayrath & Co. for their services.
At December 31, 2012, the Company had a receivable from affiliate of $280,046. This was primarily a receivable in the amount of $344,634 from the Mieka Jefferson A JV for investments received by the joint venture at the end of the year which were not transferred over to the Company until January 2013, offset by payables to the Marcellus I JV and Marcellus II JV. At December 31, 2011, the Company’s payable to affiliate in the amount of $75,659 consisted of payables to the Marcellus I JV and Marcellus II JV.
In June 2009, the FASB amended its guidance on accounting for variable interest entities. The new accounting guidance resulted in a change in our accounting policy effective January 1, 2010. Among other things, the new guidance requires more qualitative than quantitative analyses to determine the primary beneficiaries of variable interest entities, requires continuous assessments of whether reporting entities are the primary beneficiaries of variable interest entities and amends certain guidance for determining whether entities are variable interest entities. Under the new guidance, variable interest entities must be consolidated if reporting entities have both the power to direct the activities of the variable interest entities that most significantly impact the economic performance of the variable interest entities and the obligation to absorb losses or the right to receive benefits from the variable interest entities that could potentially be significant to the variable interest entities. This new accounting guidance was effective for the Company on January 1, 2010, and was applied prospectively.
Management performs an analysis of the Company’s variable interests to determine if those type interests are held in other entities. The analysis primarily is based on a qualitative review, but also includes quantitative considerations in evaluating the variable interests. Qualitative analyses are performed based on an evaluation of the design by the entity, its organizational structure, to include decision-making ability, and financial arrangements. When used to supplement qualitative analyses, quantitative analyses are based on forecasted cash flows of the entity. GAAP requires reporting entities to consolidate variable interest entities when they have variable interests that provide a controlling financial interest in variable interest entities. Entities that consolidate variable interest entities are referred to as primary beneficiaries.
Mieka LLC (“VIE”), an entity under our common control, was evaluated as a variable interest entity of the Company. The VIE’s only source of revenue was noted as being from the drilling of oil and gas wells contracted with the Company through certain turnkey contracts executed by the Company. The relationship was evaluated to determine if the arrangement gave the Company a variable interest in a variable interest entity, and to determine whether we were the primary beneficiary that would result in consolidating the VIE. We are considered to be the primary beneficiary as a result of the obligation to absorb losses that could be significant to the VIE. Additionally, since future revenue for the VIE is reliant upon the Company entering into future turnkey contracts or drilling programs, we direct activities that most significantly impact economic performance of the VIE. The Company was determined to be the primary beneficiary of the VIE for 2012 and 2011, and the VIE has been included in our audited consolidated financial statements as of and for the years ended December 31, 2012 and 2011.
Director Independence
Our securities are not currently listed on a national securities exchange or interdealer quotation system which would require that the board of directors include a majority of directors that are “independent.” We believe that Verne Rainey, Terrell A. Dobkins, Nicholas Steinsberger and Richard Patterson Smith are the only members of our board of directors that would qualify as “independent” directors as that term is defined in the NASDAQ Global Market listing standards.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Our board of directors appointed Weaver and Tidwell, L.L.P. as our independent registered public accounting firm to audit our consolidated financial statements for 2012 and 2011 and to render other professional services as required. We do not currently have an audit committee.
Weaver and Tidwell, L.L.P.’s fees for all professional services during 2012 and 2011 were as follows:
(1)Our annual audit was performed by Weaver and Tidwell L.L.P. for the years ended December 31, 2012 and 2011. Audit services and fees are incurred and paid in the year following the audit. Thus the audit fees for the year ended December 31, 2012 will be reflected in our December 31, 2013 financial statements. Includes annual audit and quarterly review fees, as well as fees for consents to SEC filings.
Our board of directors has not yet adopted formal pre-approval policies and procedures with respect to the engagement of our principal accountant to render audit or non-audit services. However, only our board of directors has the authority to engage our principal accountant to perform any services.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report.
Financial Statements. Our consolidated financial statements are included in this report as follows:
Financial Statement Schedules. All other schedules are omitted because they are not applicable, not required or because the required information is included in the consolidated financial statements or related notes.
Exhibits. The following exhibits are filed as part of, or incorporated by reference into, this report.
EXHIBIT INDEX
*Filed herewith.
**Pursuant to Rule 406T of Regulation S-T, these interactive data files are not deemed filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act or Section 18 of the Securities Exchange Act and otherwise not subject to liability
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VADDA ENERGY CORPORATION
Date: August 27, 2013 By: /s/ Daro Blankenship
Daro Blankenship
President and Chief Executive Officer
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.
Signature and Name
Title
Date
/s/ Daro Blankenship
Director, President and Chief Executive Officer
August 27, 2013
Daro Blankenship
(principal executive officer)
/s/ Martin N. Mayrath
Chief Financial Officer
August 27, 2013
Martin N. Mayrath
(principal financial officer)
/s/ Anita G. Blankenship
Chairwoman of the Board of Directors,
August 27, 2013
Anita G. Blankenship
Executive Vice President and Assistant Secretary
/s/ Verne Rainey
Director
August 27, 2013
Verne Rainey
Director
Terrell A. Dobkins
Director
Nicholas Steinsberger
/s/ Richard Patterson Smith
Director
August 27, 2013
Richard Patterson Smith
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Vadda Energy Corporation
We have audited the accompanying consolidated balance sheets of Vadda Energy Corporation and Subsidiaries (the Company) as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Vadda Energy Corporation and Subsidiaries as of December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ Weaver and Tidwell, L.L.P.
Dallas, Texas
August 27, 2013
VADDA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2012 AND 2011
See accompanying notes to consolidated financial statements
VADDA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2012 AND
See accompanying notes to consolidated financial statements
VADDA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011
See accompanying notes to consolidated financial statements
VADDA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2012 AND
See accompanying notes to consolidated financial statements
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
NOTE 1 - BASIS OF PRESENTATION
Vadda Energy Corporation (“Vadda”) was originally incorporated in Florida in 1997. The foregoing consolidated financial statements include the accounts of Vadda, its wholly owned subsidiary, Mieka Corporation (“Mieka”) and Mieka LLC, a variable interest entity (“VIE”), which collectively are referred to as the “Company.” The Company is an independent developer and producer of natural gas and oil, with operations in Pennsylvania and Kentucky. Mieka LLC qualifies as a VIE based on the common ownership that exists in Vadda, Mieka and Mieka LLC and based on Mieka being the primary beneficiary for the VIE as more fully described in Note 9.
On December 30, 2009, Vadda completed a merger with Mieka, whereby Vadda increased its ownership in Mieka from 19% to 100%. All fees and expenses related to the merger and the consolidation of the combined companies were expensed as required under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 805, “Business Combinations.” Mieka’s shareholders received 69,000,000 newly issued shares of the Company’s common stock in connection with the merger.
Before and after the merger, Vadda and Mieka were under common control, by virtue of the fact Moramoff Trust was the majority shareholder of both Mieka and Vadda. Accordingly, in accordance with ASC Topic 805, with respect to business combinations for transactions between entities under common control, the merger has been accounted for using a method similar to the pooling-of-interest method, with no adjustment to the historical basis of the assets and liabilities of Mieka and Vadda. The statements of operations were consolidated as though the merger occurred as of the beginning of the first accounting period presented in these consolidated financial statements.
As of December 1, 2009, the Company completed the acquisition of 18 natural gas and crude oil joint ventures (collectively the “Joint Ventures”) accounted for in accordance with ASC Topic 805.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The accompanying consolidated financial statements and related notes are presented in accordance with U.S. generally accepted accounting principles and are expressed in U.S dollars. The Company’s consolidated financial statements include the accounts of Vadda, its wholly owned subsidiary and VIE after elimination of significant intercompany balances and transactions.
Natural Gas and Oil Properties
The Company follows the successful efforts method of accounting for oil and gas producing activities. Under the successful efforts method of accounting, costs that relate directly to the discovery of oil and gas reserves are capitalized. These capitalized costs include:
· The costs of acquiring leases and mineral interests in properties;
· Costs to drill and equip exploratory wells that find proved reserves;
· Costs to drill and equip development wells; and
· Costs for support equipment and facilities used in oil and gas producing activities.
These costs are depreciated, depleted and amortized on the units of production method, based on estimates of recoverable proved developed oil and gas reserves.
The Company held only depletable natural gas and crude oil properties as of December 31, 2012 and 2011.
Capitalized costs are evaluated for impairment in accordance with ASC Topic 360, Accounting for the Impairment or Disposal of Long Lived Assets, whenever events or changes in circumstances indicate that an assets carrying amount may not be recoverable. To determine if a depletable unit is impaired, the Company compares the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property is recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Proved properties are assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when the Company determines that the property will not be developed. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value. No impairment of proved property was recorded for the years ended December 31, 2012 and 2011.
Other Property and Equipment
Other property and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Depreciation and amortization expense is based on cost less the estimated salvage value using straight-line method over the assets estimated useful life. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.
The following table presents property and equipment by major categories as of December 31, 2012 and 2011 and the estimated useful lives.
The Company recorded depletion, depreciation and amortization of $161,274 and $139,692 for the years ended December 31, 2012 and 2011, respectively.
Pricing Mechanism for Oil and Gas Reserves Estimation
The SEC rules require reserve estimates to be calculated using a 12-month average price. Price changes may be incorporated to the extent defined by contractual arrangements.
The rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if economic recoverability can be established with reasonable certainty. These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells. Because the revised rules generally expand the definition of proved reserves, proved reserve estimates could increase in the future based upon adoption of the revised rules.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
Prepayment to Operator
The Company acquired 18 oil and gas Joint Ventures in December 2009 and included in the assets were claims by certain of the Joint Ventures against an operator relating to its business dealings with the Joint Ventures in the aggregate amount of $1,832,500, which was recorded as a prepayment to operator. Effective December 30, 2011, the Company entered into a written settlement agreement with the operator, pursuant to which the operator agreed to make a payment of $3,000,000 to the Company. The settlement obligation was evidenced by the operator’s execution of a Secured Promissory Note bearing interest at the rate of 1% per annum, which increases to 14% per annum upon an event of default. The note is secured by a grant of a security interest in all of the operator’s assets and guaranteed by a principal of the operator. The note was immediately due and payable on December 31, 2011, but was not paid when due.
The Secured Promissory Note was recorded at the carrying value of the outstanding claims against operator in the amount of $1,832,500 as of the effective date of the note, December 30, 2011. Based on the historical settlement issues of the outstanding claims, the Company has recorded a reserve of $1,832,500 against the note as of December 31, 2012 and 2011.
Turnkey Drilling Revenue Recognition
The Company is the managing venturer of various oil and gas drilling joint ventures. In this role the Company enters into turnkey drilling agreements with operators whereby a profit is earned by arranging the drilling and completion of prospect wells funded by the individual joint ventures. In accordance with ASC Topic 605, “Revenue Recognition,” revenue is deferred until wells are completed as producing wells or determined to be nonproductive. The turnkey drilling revenue is recorded on a gross basis with the associated turnkey drilling costs, as agreed to in the turnkey drilling contract with the operator, being deferred until the associated revenue is recognized. Early recognition of loss is recorded if it is determined that the well cost will exceed the applicable revenue received on the specific well. Total turnkey drilling revenue recognized for the years ended December 31, 2012 and 2011 was $3,733,168 and $0, respectively. As of December 31, 2012 and 2011 the Company had $5,796,556 and $6,528,474 in deferred turnkey drilling revenue, respectively.
No costs are incurred by the Company for its carried working interests retained in wells drilled by managed joint ventures.
Natural Gas and Oil Sales
Natural gas and crude oil revenue is recognized as income as production is extracted and sold. Production taxes are included in lease operating expenses.
Administrative Fee Income
The Company serves as the managing venturer of various natural gas and crude oil drilling joint ventures. In this role the Company earns a monthly management fee for administrative duties performed. The monthly fees have historically been based on the number of wells owned by the ventures and the extent of operational duties required. As of December 1, 2009, all of the existing joint ventures were acquired by the Company and such monthly management fees were discontinued on these joint ventures. In 2012, management fee income in the amount of $2,251 was earned from the new joint ventures.
Use of Estimates
The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of net revenue and expenses in the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including depletion, depreciation, accretion and measurement of asset retirement obligations and valuation allowance on its prepayment to operator, goodwill impairment analysis, and deferred tax assets. We regularly evaluate our estimates and assumptions related to the useful life and recoverability of long-lived assets. We base our estimates and assumptions on current facts, historical experience and various other factors that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities and the accrual of costs and expenses that are not readily apparent from other sources. The actual results experienced by us may differ materially and adversely from our estimates. To the extent there are material differences between our estimates and the actual results, our future results of operations will be affected.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
Financial Instruments
The carrying value for cash and cash equivalents, accounts receivable and accounts payable approximates fair value based on the timing of the anticipated cash flows and current market conditions.
Cash and Cash Equivalents
The Company considers all highly liquid instruments with original maturities of three months or less when acquired, to be cash equivalents. We had no cash equivalents at December 31, 2012 or 2011. The Company’s bank accounts periodically exceed federally insured limits. The Company maintains its deposits with high quality financial institutions and, accordingly, believes its credit risk exposure associated with cash is minimal related to oil and gas accounts receivable.
Allowance for Doubtful Accounts
The Company routinely assesses the recoverability of all material receivables to determine their collectability. All of the Company’s receivables are from the operators of properties in which the Company owns an interest. Generally, the Company’s crude oil and natural gas receivables are collected within three months. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2012 and 2011, the Company had no amount recorded as an allowance for doubtful accounts for accounts receivable.
Goodwill
In 2009, the Company recorded $2,740,171 of goodwill related to the acquisition of certain oil and gas joint ventures, as more fully described in Note 1. Goodwill represents the excess of the purchase price over the fair value of the net assets acquired. The Company follows FASB ASC Topic 350, “Goodwill and Intangible Asset Impairment Testing.”
The Company tests goodwill for impairment annually at December 31, or more frequently as circumstances dictate. The first step in assessing whether an impairment of goodwill is necessary is an optional qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is greater than its carrying amount. If the Company concludes that fair value of the reporting unit more than likely exceeds the related carrying amount, then goodwill is not impaired and further testing is not necessary.
If the qualitative assessment is not performed or indicates fair value of the reporting unit may be less than its carrying amount, the Company compares the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill, and determines whether an impairment is necessary. Because quoted market prices for the Company’s reporting units are not available, management must apply judgment in determining the estimated fair value of reporting units for purposes of performing goodwill impairment tests. Management uses all available information to make these fair-value estimates, including the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets and observed for the oil and gas exploration and production reporting unit, and market multiples of earnings before interest, taxes, depreciation, and amortization (EBITDA). In estimating the fair value of its oil and gas exploration and production, the Company assumes production profiles utilized in its estimation of reserves that are disclosed in the Company’s supplemental oil and gas disclosures, market prices based on the forward price curve for oil and gas at the test date (adjusted for location and quality differentials), capital and operating costs consistent with pricing and expected inflation rates, and discount rates that management believes a market participant would utilize based upon the risks inherent in the Company’s operations.
In the second step, the reporting unit's fair value is allocated to all of the assets and liabilities of the reporting unit, including any unrecognized intangible assets, in a hypothetical analysis that calculates the implied fair value of goodwill in the same manner as if the reporting unit was being acquired in a business combination. If the implied fair value of the reporting unit's goodwill is less than the carrying value, the difference is recorded as an impairment loss. We also compare the fair value of purchased intangible assets with indefinite lives to their carrying value. We estimate the fair value of these intangible assets using an income approach. We recognize an impairment loss when the estimated fair value of intangible assets with indefinite lives is less than the carrying value.
The goodwill impairment tests as of December 31, 2012 indicated the fair value of the Company was significantly below the carrying value of its net assets. A decrease in gas prices and a reduction in the revenue forecast resulted in a lower calculated fair value of the Company from the prior year. An impairment loss of $2,740,171 was recorded in 2012, which represents 100% of the value of goodwill on the Company’s books. No impairment loss had been recognized in 2011.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
Asset Retirement Obligation
Obligations associated with the retirement of long-lived assets are recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset (natural gas and crude oil properties) and amortized on a units-of-production basis over the life of the related reserves. Accretion expense in connection with the discounted liability is recognized over the remaining life of the related liability.
Contingencies, Risks and Uncertainties
The Company’s policy regarding loss contingencies arising for claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Such accruals are adjusted as additional information becomes available or circumstances change.
From time to time, the Company is involved in litigation matters relating to claims arising from the ordinary course of business. While the results of such claims and legal actions cannot be predicted with certainty, the Company’s management does not believe that there are claims or actions, pending or threatened against the Company, the ultimate disposition of which would have a material adverse effect on its business, results of operations, financial condition or cash flows.
Loss Per Share
Loss per share is based on the weighted average number of shares of common stock outstanding during the period. The Company had no anti-dilutive stock or stock equivalents outstanding as of December 31, 2012 and 2011.
Income Taxes
Income taxes are provided for the tax effects of transactions reported in the consolidated financial statements and consist of taxes currently due (see Note 4), if any, plus net deferred taxes related primarily to differences between the basis of assets and liabilities for financial and income tax reporting. Deferred tax assets and liabilities represent the future tax return consequences of those differences.
Investment in Joint Venture
The Company owns interests in the 2009 Mieka PA Westmoreland/Marcellus Shale Project I in the amount of $105,773, the 2010 Mieka PA/WestM/Marcellus Shale Project II in the amount of $44,800, and the Mieka/Jefferson-Cattaraugus Oil & Gas Project A in the amount of $699,116. These investments represent the Company’s cost in the ventures as of December 31, 2012. The Company owns 4.71% of the Mieka PA Westmoreland/Marcellus Shale Project I Joint Venture, 1% of the 2010 Mieka PA/WestM/Marcellus Shale Project II Joint Venture, and 8.07% of the Mieka/Jefferson-Cattaraugus Oil & Gas Project A.
Liquidity and Going Concern
The Company evaluated the ability to continue as a going concern through the year ended December 31, 2013 due to the following factors:
·Recurring operating losses.
·Working capital deficiencies.
·Negative cash flows from operating activities.
·Accumulated deficits
Cash flow from operations is our most significant source of liquidity. We generate our operating cash flow from two primary sources:
·Turnkey oil and gas drilling joint ventures, from which we generally receive turnkey fees (which generate profits to the extent the turnkey price we charge to the joint ventures exceeds the actual costs necessary to acquire leases and drill, test and complete wells for such joint ventures) and carried working interests in such wells (which generate monthly revenue and cash flow to the extent such wells produce natural gas and oil), as well as interests in such joint ventures purchased by the Company (which also generate monthly revenue and cash flow to the extent such wells produce natural gas and oil); and
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
·Natural gas and oil sales, which are generally attributable to working interests owned and held directly by us in wells on producing oil and gas properties (which generate monthly revenue and cash flow to the extent such wells produce natural gas and oil) and carried working interests in such wells (which also generate monthly revenue and cash flow to the extent such wells produce natural gas and oil), as well as overriding royalty interests and reversionary interests (which may generate additional monthly revenue and cash flow to the extent such wells produce natural gas and oil).
The Company’s plan to generate cash flows to meet ongoing drilling obligations and fund general and administrative expenses through December 31, 2013 is to execute the following:
·Continue to generate turnkey drilling revenues and profits;
·Obtain carried interests in wells drilled by new joint ventures;
·Directly participate in wells drilled in the Marcellus Shale, Utica Shale and oil sands in New York, Pennsylvania and eastern Ohio
We may not be able to raise additional capital or generate turnkey drilling revenues or profits in amounts sufficient to fund ongoing drilling obligations and general and administrative expenses. If we cannot continue to raise additional capital or start generating sufficient cash flow from operations we may have to significantly delay the timing of expenditures for drilling and/or administrative expenses to meet our current obligations or consider curtailing operations. Although we typically retain a significant degree of control over the timing of our capital expenditures, we may not always be able to defer or accelerate certain capital expenditures to address any potential liquidity issues, although largely discretionary. We have been able to raise significant turnkey funds from January 1, 2013 through July 2013 to allow us to continue as a going concern and expect to continue to raise additional turnkey funds to fund operations through the year ended December 31, 2013 although such cannot be assured.
NOTE 3- STOCKHOLDERS’ EQUITY
No capital transactions occurred during the years ended December 31, 2012 and 2011. The Company has no anti-dilutive instruments at December 31, 2012 or 2011.
NOTE 4 - INCOME TAXES
The Company accounts for income taxes under the asset and liability method prescribed under ASC Topic 740-10, “Income Taxes.” Under such method, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis and net operating loss and credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that the tax rate changes. Realization of deferred tax assets are assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The Company recorded a valuation allowance of $418,019 and $309,920 as of December 31, 2012 and 2011, respectively.
The Company recognizes the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting a more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company had applied this methodology to all tax positions for which the statutes of limitation remains open, and there were no additions, reductions or settlements in unrecognized tax benefits during the tax years ended December 31, 2012, 2011 and 2010 for Vadda and tax years ended June 30, 2012, 2011 and 2010 for Mieka. The Company has no material uncertain tax positions at December 31, 2012 and 2011.
While the Company is reporting consolidated financial statements for Vadda and Mieka for the twelve months ended December 31, 2012 and 2011, income tax returns have been filed separately with Vadda reporting on a December 31 year-end for tax purposes and Mieka reporting on a June 30 year-end for tax purposes.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
The following table presents the components of the Company’s provision (benefit) for income taxes:
A reconciliation between the statutory federal income tax rate and the Company’s effective income tax rate is as follows:
The components of the Company’s net deferred tax asset and liability are as follows at the dates indicated:
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
Deferred income tax assets and liabilities are classified as current or long-term consistent with the classification of the related temporary difference and are recorded in the Company’s consolidated balance sheets as follows:
The Company had net operating loss (“NOL”) carryforwards of approximately $3.3 million that are available to offset future taxable income. The loss carryforwards expire beginning December 31, 2031 for federal purposes. Management has elected to provide a valuation allowance on the entire potential tax benefit related to the NOL carryforward of Vadda, which is approximately $1.2 million. The decision was based in part on the historical taxable loss of the Company.
The Company is subject to U.S. federal income taxes and income taxes in various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. With few exceptions, the Company is no longer subject to U.S. federal, state or local, or non-U.S., income tax examinations by tax authorities for the years before 2007. The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable.
NOTE 5 - ASSET RETIREMENT OBLIGATIONS
In accordance with ASC Topic 410-20, “Asset Retirement Obligations,” the Company recognizes a liability for future asset retirement obligations which is based on the estimated cost of plugging and abandonment of its oil and gas wells and related facilities. This liability is offset by the associated asset retirement costs which are capitalized as part of the carrying amount of the related proved oil and gas assets. The related capitalized asset retirement costs are included in proved oil and gas properties.
The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements.
Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Judgments are based upon such things as field life and estimated costs. Such costs could differ significantly when they are incurred.
A rollforward of the Company’s AROs as of and for the years ended December 31, 2012 and 2011 are as follows:
NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company has established a hierarchy to measure its financial instruments at fair value in accordance with ASC Topic 820-10, “Fair Value Measurements and Disclosures,” which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). ASC Topic 820-10 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants on the measurement date. A fair value measurement assumes that the transaction to sell the asset or transfer the liability occurs in the principal market for the asset or liability. The three levels of the fair value hierarchy under FASB ASC Topic 820-10 are described below:
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
Level 1 - Valuation based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access.
·Level 2 - Valuation based on quoted prices for similar assets or liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities.
·Level 3 - Valuations based on inputs that are supportable by little or no market activity and that are significant to the fair value of the asset or liability.
Nonrecurring Fair Value Measurements
The remeasurement of goodwill is classified as a Level 3 fair value assessment due to the significance of unobservable inputs developed using company-specific information. The Company used the income approach to measure the fair value of the business. Under the income approach, the fair value of the business is calculated based on the present value of the estimated future cash flows. Cash flow projections are based on management's estimates of revenue growth rates and operating margins, taking into consideration industry and market conditions. The discount rate used is based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business's ability to execute on the projected cash flows. The unobservable inputs used to fair value these reporting units include projected revenue growth rates, profitability and the risk factor added to the discount rate.
NOTE 7 - RELATED PARTY TRANSACTIONS
Pursuant to an arrangement between the Company and Mieka LLC, an entity wholly owned by our principal stockholders, Mieka LLC provides drilling and completion services on wells owned by the Company. Prices charged to the Company by Mieka LLC under turnkey drilling arrangements do not reflect prevailing rates that would be charged by outside third parties in arms-length transactions. During the years ended December 31, 2012 and 2011, the Company incurred drilling costs associated with turnkey drilling contracts with Mieka LLC of $1,935,117 and $669,836, respectively. As of December 31, 2012 and 2011, the Company was obligated to pay $1,562,206 and $662,292, respectively, to Mieka LLC. This activity is eliminated in the consolidated financial statements.
In 2012, Mieka LLC was charged an administrative fee of $96,000 from Vadda Energy Corporation and $408,000 from Mieka Corporation. This activity is eliminated in the consolidated financial statements.
During the years ended December 31, 2012 and 2011, Daro and Anita Blankenship, principal shareholders of the Company, received aggregate compensation from the Company of $229,500 and $238,500, respectively.
Martin N. Mayrath is a principal of Mayrath & Co., PC, which has been engaged by the Company to perform the function of Chief Financial Officer, in addition to providing tax services. In 2012, the Company paid a total of $103,562 to Mayrath & Co. for their services.
At December 31, 2012, the Company had a receivable from affiliate of $280,046. This was primarily a receivable in the amount of $344,634 from the Mieka Jefferson A JV for investments received by the joint venture at the end of the year which were not transferred over to the Company until January 2013, offset by payables to the Marcellus I JV and Marcellus II JV. At December 31, 2011, the Company’s payable to affiliate in the amount of $75,659 consisted of payables to the Marcellus I JV and Marcellus II JV.
NOTE 8 - LEASES
The Company leases office space of approximately 7,800 square feet, under a 6 ½-year lease term which commenced October 1, 2012. The lease allows for six months of free rent, and the 2013 monthly rental of $9,755 beginning on April 1, 2013.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
Future lease obligations are as follows:
Total rent expense for the years ended December 31, 2012 and 2011 were $104,580 and $135,082, respectively.
NOTE 9 - Variable Interests Entities (VIE)
ASC 810-10 requires more qualitative than quantitative analyses to determine the primary beneficiaries of variable interest entities, requires continuous assessments of whether reporting entities are the primary beneficiaries of variable interest entities, and amends certain guidance for determining whether entities are variable interest entities. Variable interest entities must be consolidated if reporting entities have both the power to direct the activities of the variable interest entities that most significantly impact the economic performance of the variable interest entities and the obligation to absorb losses or the right to receive benefits from the variable interest entities that could potentially be significant to the variable interest entities.
Management performs an analysis of the Company’s variable interests to determine if those type interests are held in other entities. The analysis primarily is based on a qualitative review, but also includes quantitative considerations in evaluating the variable interests. Qualitative analyses are performed based on an evaluation of the design by the entity, its organizational structure, to include decision-making ability, and financial arrangements. When used to supplement qualitative analyses, quantitative analyses are based on forecasted cash flows of the entity.
GAAP requires reporting entities to consolidate variable interest entities when they have variable interests that provide a controlling financial interest in variable interest entities. Entities that consolidate variable interest entities are referred to as primary beneficiaries.
Mieka, LLC (VIE) an entity under common control of the Company was evaluated as a variable interest entity of the Company. The VIE’s only source of revenue is from the drilling of oil and gas wells contracted with the Company through certain turnkey contracts entered into by the Company. The relationship was evaluated to determine if the arrangement gave the Company a variable interest in a variable interest entity and to determine whether the Company was the primary beneficiary that would result in consolidating the VIE.
The Company was considered to be the primary beneficiary as a result of the obligation to absorb losses that could be significant to the VIE. Additionally, since future revenue for the VIE is dependent upon the Company entering into future turnkey contracts or drilling programs, the Company directs activities that most significantly impact economic performance of the VIE. The Company was determined to be the primary beneficiary of the VIE for 2012 and 2011 and the VIE has been included in the consolidated financial statements as of and for the years ended December 31, 2012 and 2011.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
The table below reflects the amount of assets and liabilities from the VIE included in the consolidated balance sheets as of December 31, 2012 and 2011.
NOTE 10 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Natural Gas and Oil Operations
The following table sets forth the revenue and direct cost information relating to the Company’s oil and gas exploration and production activities:
(1)Reflects DD&A of capitalized cost of oil and gas producing properties.
(2)Amount includes de minimis production taxes related to Kentucky oil wells.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Capitalized Costs
Natural Gas and Oil Reserve Information
The Company has limited management and staff and is dependent upon outside consulting petroleum engineers for the preparation of its annual natural gas and crude oil reserve estimates. The preparation of the Company’s natural gas and oil reserve estimates were completed in accordance with ASC Topic 932, which includes the verification of input data delivered to its third party reserve specialist, as well as a multi-functional management review.
Nicola Blankenship, the Company’s Vice President of Operations, is responsible for overseeing the preparation of the Company’s reserve estimates and providing the historical and other information regarding our properties to Valuescope. Such information includes for our properties, such as ownership interests, natural gas and crude oil production, well test data, commodity prices and lease operating expenses. Mr. Blankenship’s job responsibilities during the last eight years have included daily monitoring of the Company’s producing wells, approval of operating expense billings and review of daily drilling reports.
The reserve estimates reported herein were prepared by Gregory E. Sheig, Vice President of ValueScope, Inc. (“ValueScope”). The process performed by Mr. Scheig to prepare reserve amounts included its estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, is based in part on data provided by the Company.
Valuescope, an independent financial analysis and valuation firm with expertise in the valuation of oil and gas reserves, has reviewed the estimates of the Company’s natural gas and crude oil reserves as of December 31, 2012 and 2011. Gregory E. Sheig, the person responsible for the review of proved reserve estimates meets the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the standard pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers.
ValueScope provided its report to the Company’s senior management team (Daro and Anita Blankenship, Nicola Blankenship and Martin Mayrath) who is responsible for oversight. The Company made representations to the independent engineers that it provided all relevant operating data and documents, and in turn, management reviews the reserve reports provided by the independent engineers to ensure completeness and accuracy. The Company’s management cautions that estimates of proved reserves may be imprecise and subject to revision based on production history, price changes and other factors.
Vadda Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
All of the Company’s natural gas and crude oil reserves are located within Pennsylvania and Kentucky. A summary of the changes in quantities of proved natural gas and crude oil reserves for the years ended December 31, 2012 and 2011 follows:
Proved natural gas reserves as of December 31, 2012 include undeveloped reserves of 36,890 Mcf.
Future Net Cash Flows
Future cash inflows as of December 31, 2012 and 2011 were calculated in accordance with SEC Modernization Rules, using an average of natural gas and oil prices in effect on the first day of each month in 2012 and 2011, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalations.
The following tables set forth unaudited information concerning future net cash flows for natural gas and oil reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s natural gas and oil assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.
The changes in the standardized measure of future net cash flows for the years ended December 31, 2012 and 2011 are as follows: