Vadda Energy 10K 2011 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2011

o TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________to ____________

Commission File Number: 0-28171

VADDA ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Florida	27-0471741
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1660 S. Stemmons Freeway; Suite 440; Lewisville, Texas 75067

(Address of principal executive offices)

Registrant's telephone number, including area code: (214) 222-6500

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.001 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section13 or Section 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule-405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer”, “non-accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer* o

*(Do not check if a smaller reporting company)

Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $968,376 based on its closing price per share of $0.05 as of August 4, 2011, which is a date within 30 days of the filing of the registrant’s registration statement on Form 10 on July 5, 2011. (Note that there is no active trading market with respect to the registrant’s common stock, and the closing price per share indicated above reflects the last previous close, from November 2009, as reported on the OTC Markets Pink Sheets.)

The number of shares of registrant's common stock outstanding as of February 29, 2012 was 104,235,236.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

			Page

Definitions of Certain Terms and Conventions Used in This Report			1

Cautionary Statement Concerning Forward-Looking Statements			2

PART I
	Item 1.	Business	3
	Item 1A.	Risk Factors	9
	Item 1B.	Unresolved Staff Comments	9
	Item 2.	Properties	10
	Item 3.	Legal Proceedings	13
	Item 4.	Mine Safety Disclosures	13

Part II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases Of Equity Securities	14
	Item 6.	Selected Financial Data	14
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	21
	Item 8.	Financial Statements and Supplementary Data	21
	Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	21
	Item 9A.	Controls and Procedures	21
	Item 9B.	Other Information	22

Part III
	Item 10.	Directors and Executive Officers of the Registrant	23
	Item 11.	Executive Compensation	25
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	26
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	27
	Item 14.	Principal Accountant Fees and Services	28

Part IV
	Item 15.	Exhibits and Financial Statement Schedules	29

Signatures			31

Consolidated Financial Statements			F-1

DEFINITIONS OF CERTAIN TERMS AND CONVENTIONS USED IN THIS REPORT

Within this annual report on Form 10-K, the following terms and conventions have specific meanings:

“bbl” means a standard barrel containing 42 U.S. gallons.

“Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

“CERCLA” means the U.S. Comprehensive Environmental Response, Compensation, and Liability Act, as amended.

Unless the context requires otherwise, references in this report to “Company” “we,” “us” or “our” means Vadda Energy Corporation, Mieka Corporation, a Delaware corporation and a wholly owned subsidiary of Vadda, and Mieka LLC, a Delaware limited liability company that is a variable interest entity (“VIE”) under common ownership control with Vadda and Mieka.

“EPA” means the U.S. Environmental Protection Agency.

“GAAP” means accounting principles that are generally accepted in the United States of America.

“Mcf” means one thousand cubic feet and is a measure of gas volume.

“Mcfe” means Mcf equivalent (Mcfe), which is oil (bbl) converted to natural gas (Mcf) at the rate of 1 bbl to 6 Mcf.

“Mieka” means Mieka Corporation, a Delaware corporation and a wholly owned subsidiary of Vadda.

“Mieka LLC” means Mieka LLC, a Delaware limited liability company that is a VIE under common ownership control with Vadda and Mieka.

“MMBtu” means one million Btus.

“proved reserves” means quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (Rule 4-10(a)(22) of Regulation S-X)

“reserves” means estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. (Rule 4-10(a)(26) of Regulation S-X)

“SDWA” means the U.S. Safe Drinking Water Act, as amended.

“SEC” means the U.S. Securities and Exchange Commission.

“Securities Act” means the U.S. Securities Act of 1933, as amended.

“Securities Exchange Act” means the U.S. Securities Exchange Act of 1933, as amended.

“standardized measure” means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a ten percent discount rate.

“Vadda” means Vadda Energy Corporation.

“ValueScope” means ValueScope, Inc., our independent petroleum consultant.

“VIE” means variable interest entity.

“West Texas Intermediate” or “WTI” means a light, sweet blend of oil produced from fields in western Texas.

With respect to information on the working interest in wells, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying “gross” wells, drilling locations and acres by the Company’s working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and section 21E of the Securities Exchange Act. Forward-looking statements are statements other than historical fact and give our current expectations or forecasts of future events. They may include estimates of natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned capital expenditures and anticipated asset acquisitions and sales, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations.

Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results include:

·	the volatility of natural gas and oil prices;

·	the limitations our level of cash flow or ability to raise capital may have on our operational and financial flexibility;

·	declines in the values of our natural gas and oil properties resulting in ceiling test write-downs;

·	the availability of capital on an economic basis to fund reserve replacement costs;

·	our ability to replace reserves and sustain production;

·	uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the timing of development expenditures;

·	inability to generate profits or achieve targeted results in our drilling and well operations;

·	leasehold terms expiring before production can be established;

·	drilling and operating risks, including potential environmental liabilities associated with hydraulic fracturing;

·	changes in legislation and regulation adversely affecting our industry and our business;

·	general economic conditions negatively impacting us and our business counterparties; and

·	transportation capacity constraints and interruptions that could adversely affect our cash flow.

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this annual report, and we undertake no obligation to update this information. Forward-looking statements are not guarantees of future performance and actual results may differ significantly from the results discussed in the forward-looking statements. We urge you to carefully review and consider the disclosures made in this report (including “Item 1. Business—Competition,” “Item 1. Business—Horizontal Drilling and Hydraulic Fracturing,” “Item 1. Business—Government Regulation” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”) and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.

PART I

ITEM 1. BUSINESS

General

We are an independent developer and producer of natural gas and oil, with operations in Pennsylvania and Kentucky. 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 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.

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.

Oil and Gas Holdings

Based on a reserve report prepared by ValueScope, our total proved reserves at December 31, 2011 were 7,030 barrels of oil1 and 1,243,500 Mcf of natural gas. Our oil holdings are found in Warren County, Kentucky, and its 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 and 4,686 gross acres (2,343 net acres) of proved developed leasehold acreage in Pennsylvania.

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, 2011, our producing wells were operated as follows:

Natural Gas and Crude Oil Wells as of December 31, 2011
Operator	Natural Gas		Oil		Total
Mid-East Oil Company		49		0		49
Hayden Harper KA, LLC		20		0		20
Mieka LLC		1		13		14
Total:		70		13		83

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.

1 As compared to 8,260 barrels of oil at December 31, 2010. Please note that due to a clerical error, this amount was erroneously reflected in the registrant’s registration statement on Form 10 as 8.26 million barrels of oil.

Competition

We are in direct competition with numerous natural gas and oil producers, drilling and income programs and partnerships that are active in Pennsylvania and Kentucky. 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., 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. 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 nearly all oil and natural gas wells drilled in the U.S. today and is often necessary to produce commercial quantities of natural gas and oil from many reservoirs. We may elect to use hydraulic fracturing to produce commercial quantities of natural gas and oil. 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. In addition, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. The EPA has also commenced a study of the potential environmental impacts of hydraulic fracturing activities and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before the U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. See “—Risks Associated with Hydraulic Fracturing.”

Risks Associated with Hydraulic Fracturing

We successfully deployed hydraulic fracturing in connection with our Marcellus I JV well and generally expect to utilize hydraulic fracturing on all of the wells we drill in the Marcellus Shale. 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. 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 and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. 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 the state’s Marcellus Shale Advisory Commission. If passed by the state legislature, it will 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, 2011, we had 16 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. 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. UNRESOLVED STAFF COMMENTS

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 2. PROPERTIES

Principal Office

We maintain our principal offices at 1660 Stemmons Freeway, Suite 440, Lewisville, Texas 75067. Our telephone number at that office is (214) 222-6500. Our current office space consists of approximately 5,229 square feet and our lease is on a month-to-month basis. The monthly rental totals $13,073. We believe this property is generally in good condition and suitable to carry on our business.

We are in the process of negotiating a new 6 ½ year lease for approximately 7,800 square feet of office space located in Flower Mound, Texas, which will serve as a new location for our principal offices.

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 2011 and 2010 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, 2011 based upon a report prepared by ValueScope. All of our proved reserves are located in the United States.

Disclosure of Reserves

Summary of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices
	Oil (bbls)		Natural Gas (Mcf)		Total (Mcfe)(1)
Remaining Net Reserves
PROVED
Developed
North American-United States		7,030		1,243,500		1,285,680
Undeveloped
North American-United States		—		15,930		15,930
TOTAL PROVED		7,030		1,259,430		1,301,610

Income Data ($ Dollars)					Total
Future Net Revenue	$	587,090	$	5,398,160	$	5,985,250
Less: Operating Expense		305,500		2,989,590		3,295,090
Less: Sev. Taxes		26,420		—		26,420
Future Net Income	$	255,170	$	2,408,570	$	2,663,740

(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 $83.46 per barrel of oil for West Texas Intermediate oil at Cushing, Oklahoma, and $4.29 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 years ended December 31, 2011 and 2010, 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, William J. Amdall and Philip Kwong), which is responsible for oversight of our reserve information.

As of December 31, 2011, we had total estimated proved reserves of 1,259,430 Mcf of natural gas and 7,030 barrels of crude oil. Combined, these total estimated proved reserves are equivalent to 1,301,610 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, William Amdall and Philip Kwong.

Proved Undeveloped Reserves

At the end of 2011, our oil and gas reserves included 15,930 Mcf of proved undeveloped natural reserves. The proved undeveloped reserves consist of three natural gas wells that were converted into proved developed reserves in 2012.

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, 2011, 2010 and 2009. 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 2011, 2010 and 2009 the average selling price for natural gas was $4.29, $5.06 and $4.44 per Mcf, respectively, and the average selling price for crude oil was $89.31, $75.69 and $58.47 per barrel, respectively.

	Years Ended December 31,
	2011		2010		2009
Production:
Natural gas-Mcf(1)		84,653		89,410		25,022
Crude oil-bbl(2)		600		840		86

Prices:
Natural gas(1)	$	4.29	$	5.06	$	4.44
Crude oil(2)		89.31		75.69		58.47

Lifting cost per equivalent Mcf(3)	$	1.67	$	1.89	$	1.43

(1)	All natural gas production is located in Pennsylvania.

(2)	All crude oil production is located in Kentucky.

(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 2011, we drilled three natural gas wells, all of which are expected to be completed by the end of the second quarter of 2012. In 2010, we drilled one natural gas well, which was productive. During 2009, we drilled 14 oil wells, of which one was productive, one was capable of production awaiting completion, and 12 were dry holes.

Present Activities

As of December 31, 2011, we owned interests in four wells (0.55 net wells) one of which is producing and three that have been drilled and are awaiting completion in the Marcellus Shale formation in Pennsylvania.

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 working interests owned by us in various natural gas and oil wells on leases located in Kentucky and Pennsylvania. Below is a brief synopsis of each of our core areas of operation:

Pennsylvania (Natural Gas). As of December 31, 2011, we owned working interests ranging from 41.4% to 100% in 65 gross (28.2 net) producing or capable of producing natural gas wells and net revenue interests in such wells ranging from 33% to 81.25% (or approximately 34.9 net wells), located in Centre, Clearfield, Jefferson and Westmoreland Counties of Pennsylvania.

Kentucky (Crude Oil). As of December 31, 2011, we owned working interests ranging from 87% to 100% in 14 gross (12.2 to 14.0 net) producing or capable of producing oil wells and net revenue interests in such wells ranging from 25% to 87.5% (or approximately 3.5 to 12.3 net wells), located in Warren County, Kentucky. 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, 2011, we had 4,686 gross acres (2,343 net acres) of proved developed leasehold acreage located in Pennsylvania and 600 gross acres (594 net acres) located in Kentucky. As of December 31, 2011, our undeveloped acreage consisted of 240 gross and 10 net acres located in Pennsylvania.

ITEM 3. LEGAL PROCEEDINGS

Mieka, Daro Blankenship and Stephen Romo (the “Appellants”) are currently appealing a Final Cease and Desist Order entered against them by Fred J. Joseph, the Colorado Securities Commissioner, and the Colorado Division of Securities, directing them 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. The appeal, which was filed in the Colorado Court of Appeals on May 23, 2011, was initiated by the Appellants from the Final Cease and Desist Order entered in the Matter of Mieka Corporation, Daro Blankenship and Stephen Romo, Case No. XY-11-CD-11 in April 2011. In the Colorado Order being appealed, the Colorado Securities Commissioner found that (1) joint venture interests in a joint venture sponsored by Mieka were “investment contracts” and therefore “securities” within the meaning of the Colorado Securities Act, (2) the offer of such interests in Colorado required registration under Colorado Revised Statute Section 11-51-301 or an exemption to that registration requirement and (3) the Appellants violated provisions of the Colorado Securities Act relating to the employment of securities broker/dealers or sales representatives. The Appellants are appealing the Colorado Order on the basis that the Commissioner’s findings were not supported by substantial evidence, the Colorado Order was overbroad and exceeded the Commissioner’s authority under the Colorado Securities Act and the Appellants did not receive proper notice of the proceeding and were deprived of their right to a fair hearing. Appellate briefs have been submitted by both parties, and a decision on the appeal is pending.

ITEM 4. MINE SAFETY DISCLOSURE

Not applicable.

PART II

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, 2011, 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 March 30, 2012, there were 1,108 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. 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. 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, 2011, we owned interests in approximately 85 producing natural gas and oil wells. Our natural gas and oil production for 2011 consisted of 84,652 Mcf of gas and 600 bbls of oil. These amounts represent decreases of 5.3% from our 2010 gas production of 89,410 Mcf and 28.6% from our 2010 oil production of 840 bbls.

We began 2011 with estimated proved reserves of 1,626,470 Mcfe and ended the year with 1,301,610 Mcfe.

Implementation of Strategy

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. In addition, we own a 3.94% carried working interest (2.79% net revenue interest), which is carried to the tanks, outside the joint venture. We also purchased $82,500 of the Marcellus I JV in January 2010 on the same terms and conditions as outside investors.

The Marcellus I JV drilled a total of two natural gas wells, one of which was completed in December 2010 and the second well had been drilled to its total depth as of December 31, 2011. During the first quarter of 2012, the second well was successfully completed.

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. 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 joint venture wells. In addition we own a 0.77% carried working interest (0.55% net revenue interest), which is carried to the tanks in two natural gas wells, one of which is a horizontal well.

As of December 31, 2011, the vertical well had been drilled and is expected to be completed by the end of the second quarter of 2012.

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 $980,000 as of December 31, 2011. When closed, we will own a 6% carried working interest (4.25% net revenue interest) in two gas wells, one vertical and one horizontal, targeting the Marcellus shale formation and two horizontal oil wells, which will be drilled to the 1st, 2nd or 3rd Bradford sands formation in western New York. As of December 31, 2011, the vertical natural gas well had been drilled and is expected to be completed by the end of the second quarter of 2012.

Mieka LLC purchased $614,500 of joint venture units in December 2011.

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

	Years Ended December 31,
	2011		2010		2009
Production:
Natural gas-Mcf(1)		84,653		89,410		25,022
Crude oil-bbl(2)		600		840		86

Prices:
Natural gas(1)	$	4.29	$	5.06	$	4.44
Crude oil(2)		89.31		5.69		58.47

Lifting cost per equivalent Mcf(3)	$	1.67	$	1.89	$	1.43

(1)	All natural gas production is located in Pennsylvania.

(2)	All crude oil production is located in Kentucky.

(3)

Results of Operations

Comparison of Year Ended December 31, 2011 to Year Ended December 31, 2010

Total Revenues. Total revenues decreased $1,234,160, or 74.7%, to $419,023 for 2011 from $1,653,183 for 2010, driven primarily by the inability to recognize turnkey drilling proceeds as revenue in 2011 and decreased natural gas and oil sales.

Turnkey Drilling Revenues. Turnkey drilling revenues of $2,605,600 received from investors during the year ended December 31, 2011 were not recognized as income in 2011 because of certain requirements of U.S. generally accepted accounting principles. Currently prescribed accounting rules require a well to be drilled and completed before turnkey revenues can be recognized. At December 31, 2011, the Company had $6,528,474 of deferred revenue, representing three wells, one of which was completed during the first quarter of 2012 and two that are expected to be completed during the second quarter of 2012.

Natural gas and oil sales. Natural gas and oil sales decreased $117,786, or 21.9%, to $419,023 for 2011 from $536,809 for 2010, due to normal production decline coupled with a decrease in the price of natural gas. The average price for 2011 was $4.29 compared to $5.06 in 2010.

Costs and Expenses. Total costs and expenses increased $362,957, or 9.3%, to $4,255,362 for the year 2011 from $3,892,405 for the prior year, due to the valuation allowance recorded on the prepayment to operator. The increase was partially offset by the deferral of turnkey drilling costs in 2011 associated with the delayed recognition of turnkey drilling proceeds as revenue in 2011. General and administrative expenses increased $1,880,727, or 92.4%, to $3,916,117 for the year 2011 from $2,035,390 for the previous year primarily due to the valuation allowance and, to a lesser degree, increased costs of being a public reporting company.

Net Loss. Net loss was $3,123,092 or $0.03 per basic and diluted common share, for the 2011 as compared to $1,688,596, or $0.01 per basic and diluted common share, for 2010. The increased net loss was attributable primarily to the valuation allowance recorded on the prepayment to operator and no recognition of turnkey drilling revenue in 2011. Net loss represents a consolidated net loss which includes a loss of $185,020 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 $1,382,166 as of December 31, 2011, as compared to $1,836,957 as of December 31, 2010. Cash provided by operating activities was $174,988 for the year ended December 31, 2011, compared to $829,193 for the year ended December 31, 2010.

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 $41.5 million from outside investors in 32 joint ventures that drilled 166 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 generated $21,635 of cash from financing activities during the year ended December 31, 2011, compared to $260,604 for the year ended December 31, 2010. The 2010 amount consists of net cash proceeds from the sale of our common stock in a private placement offering

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, 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 $336,670, payable to affiliate of $75,659, and current portion of note payable of $13,797.

As of December 31, 2010, we had a working capital deficit of $1,491,472. Current assets as of December 31, 2010 included cash of $1,836,957, deferred income tax of $813,365 and accounts receivable of $95,678. Current liabilities as of December 31, 2010 included deferred revenue of $3,923,974, accounts payable and accrued liabilities in the amount of $294,319 and income taxes payable of $19,179.

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. 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.

Goodwill

At December 31, 2011 and December 31, 2010, we had $2,740,171 of goodwill related to the acquisition of certain oil and gas joint ventures on December 1, 2009, as more fully described in Note 2 to our audited consolidated financial statements.

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.” Our analysis consists of two steps. Step 1 tests the company for impairment by comparing the fair value of equity to the book value of equity. If the fair value is less than the book value, then a Step 2 analysis must be performed. If the fair value of goodwill is less than its carrying amount, impairment is recorded based on the difference. We annually assess the carrying value of goodwill for impairment. No impairment loss was recorded for the years ended December 31, 2011 and 2010.

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. The following recently adopted changes will have the greatest impact on our financial statements.

Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The guidance requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods and retrospectively for all comparative periods presented. Under GAAP, derivative assets and liabilities can be offset under certain conditions. The guidance requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. We are currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on our financial position or results of operations.

Common Fair Value Measurement and Disclosure

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs.” The guidance amends previously issued authoritative guidance and requires new disclosures, clarifies existing disclosures and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the guidance clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing fair value measurements guidance. We are currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on our financial position or results of operations.

Comprehensive Income

In June 2011, authoritative guidance was issued on the presentation of comprehensive income. Specifically, the guidance allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. The new guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This guidance will be applied retrospectively and will be effective for our interim and annual reporting periods beginning after December 15, 2011. The changes in presentation of comprehensive income will have no effect on the calculation of net income, comprehensive income or earnings per share.

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. Early adoption is permitted. We will adopt the new guidance in fiscal 2012.

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. 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 F-1.

ITEM 9. CHANGES IN AND DISAGREMMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.

Not applicable.

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, 2011, 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, 2011. 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 account 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, 2011. During 2012, 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 quarter ended December 31, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III

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:

Name	Age	Position
Daro Blankenship	64	President and Chief Executive Officer; Managing Director of Mieka
Anita G. Blankenship	63	Chairwoman of the Board of Directors, Executive Vice President and Assistant Secretary; President of Mieka
William J. Amdall	58	Chief Financial Officer
Verne Rainey	74	Director; director of Mieka
Robert Myers	67	Vice President of Project Development
Philip Kwong	51	Vice President of Accounting
Nicola D. Blankenship	36	Vice President of Operations/Public Relations
Stephen Romo	47	Vice President of Marketing

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. 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.

William J. Amdall. Mr. Amdall has served as our Chief Financial Officer since April 2009. He began his career with Peat, Marwick, Mitchell & Co. (now KPMG) in June 1977, where he became licensed as a certified public accountant. From 1980 to 1991, he served as the Chief Financial Officer of three publicly traded oil and gas companies where he gained experience in financial reporting and SEC regulations, mergers and acquisitions, public and private financings and stockholder/investor relations. From 1992 to 2004, Mr. Amdall’s principal occupation was financial consulting as a sole proprietor, primarily doing contract CFO work. In 2005, he co-founded North American Royalty Corp, an oil and gas royalty company and served as its Vice President and Chief Financial Officer until 2009. While employed at North American Royalty Corp. Mr. Amdall was responsible for the monthly accounting duties and the preparation and filing of a registration statement with the SEC. Mr. Amdall received a BBA in Accounting from The University of North Texas in 1977.

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.

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.

Philip Kwong. Mr. Kwong has served as our Vice President of Accounting since July 2011. From August 2008 to July 2011, he served as an instructor and technical advisor at Rockwall Christian Academy. From June 2008 to September 2008, Mr. Kwong was a Senior Accountant for SkyWi Telecommunication Corp. Mr. Kwong was a Senior Accountant/Financial Analyst for Accretive Solutions, a national consulting firm, from February 2006 to May 2008, where his duties included forensic accounting for six royalty companies, Sarbanes-Oxley compliance and preparation of business outlook and quarterly forecasts for Idearc Media and Ericcson. Mr. Kwong received a Bachelor of Science in Accounting and Finance in 1982 from the University of San Carlos in the Philippines and an MBA in Accounting in 2010 from the University of Phoenix.

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.

Involvement in Certain Legal Proceedings

In April 2011, the Securities Commissioner of Colorado entered a Final Cease and Desist Order directing Mieka, Daro Blankenship and Stephen Romo 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. The Colorado Order alleged that Mieka, Mr. Blankenship and Mr. Romo violated the Colorado Securities Act by offering securities without an exemption from registration and violated provisions of the Colorado Securities Act relating to the registration and employment of securities brokers/dealers or sales representatives. Mieka and Messrs. Blankenship and Romo have appealed this order and the appeal is pending. See “Item 3. Legal Proceedings.”

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 two 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 2012.

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 2010 and 2011, 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.

Name and Principal Position	Fiscal Year	Salary ($)		Bonus ($)		Total ($)
Daro Blankenship	2011	$	106,000	$	—	$	106,000
President and Chief Executive Officer	2010	$	104,000	$	80,022	$	184,022

Anita G. Blankenship	2011	$	132,500	$	—	$	132,500
Chairwoman, Vice President and Assistant Secretary	2010	$	130,000	$	35,003	$	165,003

Narrative Disclosure to Summary Compensation Table

We paid salaries to each of the named executive officers in each of 2010 and 2011. No bonuses were paid with respect to 2011, but bonuses were paid to each of the named executive officers with respect to 2010. 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.

Compensation of Directors

We had two directors, Anita Blankenship and Verne Rainey, during the year ended December 31, 2011. During the year ended December 31, 2011, neither Ms. Blankenship nor Mr. Rainey received any cash or equity compensation for their services as directors of the Company.

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, 2011, 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, 2011. 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, 1660 S. Stemmons Freeway, Suite 440, Lewisville, Texas 75067.

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership			Percent of Class(1)
Directors and Named Executive Officers:
Daro Blankenship		83,017,708	(2)		79.6%
Anita G. Blankenship		83,017,708	(3)		79.6%
Verne Rainey		1,450,000			1.4%
William J. Amdall		0			0.0%
All directors and executive officers as a group (4 people):		84,467,708			81.0%
Moarmoff Trust 1660 Stemmons Freeway Lewisville, Texas 75067		76,750,000			73.6%

(1)	Based upon 104,235,236 shares of common stock outstanding as of December 31, 2011.

(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. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related Party Transactions

During the year ended December 31, 2011, Daro and Anita Blankenship, who together have voting control of our common stock, received aggregate compensation from the Company of $238,500.

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, 2011, we incurred drilling costs associated with turnkey drilling contracts with Mieka LLC of $699,836. As of December 31, 2011, we were obligated to pay $662,292 to Mieka LLC.

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 2011 and 2010, and the VIE has been included in our audited consolidated financial statements as of and for the years ended December 31, 2011 and 2010.

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 Verne Rainey is the only member of our board of directors that would qualify as an “independent” director as that term is defined in the NASDAQ Global Market listing standards.

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 2010 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 2011 and 2010 were as follows:

Type of Service		2011				2010
Audit fees(1)		$	77,000			$	70,000

(1)

Our annual audit was performed by Weaver and Tidwell L.L.P. for the years ended December 31, 2011 and 2010. Audit services and fees are incurred and paid in the year following the audit. Thus the audit fees for the year ended December 31, 2011 will be reflected in our December 31, 2012 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. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

The following documents are filed as part of this report.

1.	Financial Statements. Our consolidated financial statements are included in this report as follows:

	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2011 and 2010	F-2
Consolidated Statements of Operations for the years ended December 31, 2011 and 2010	F-3
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2011 and 2010	F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2011 and 2010	F-5
Notes to Consolidated Financial Statements	F-6
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	F-15

2.	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.

3.	Exhibits. The following exhibits are filed as part of, or incorporated by reference into, this report.

EXHIBIT INDEX

Exhibit		Description
2.1		Agreement and Plan of Merger dated November 6, 2009 (filed as Exhibit 2.1 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
3.1		Articles of Amendment and Restatement to the Articles of Incorporation of Vadda Energy Corporation dated October 15, 2009 (filed as Exhibit 3.1 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
3.2		By-Laws (filed as Exhibit 3.2 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
10.1		Partial Assignment of Oil and Gas Leases dated February 24, 2009 between Mid-East Oil Company and Mieka Corporation (filed as Exhibit 10.1 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
10.2		Joint Venture Agreement 2009 Mieka PA Westmoreland/Marcellus Shale Project I, effective October 5, 2009 (filed as Exhibit 10.2 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
10.3		Joint Venture Agreement 2010 Mieka PA/West M/Marcellus Project II, effective July 16, 2010 (filed as Exhibit 10.3 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
10.4		Participation and Operating Agreement dated December 15, 2010 between Mieka, LLC and Mieka Corporation (filed as Exhibit 10.4 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
10.5		Participation and Operating Agreement dated December 28, 2009 between Mieka, LLC and Mieka Corporation (filed as Exhibit 10.5 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
10.6		First Amendment to Partial Assignment of Oil and Gas Leases dated February 24, 2009 between Mieka Corporation and Mid-East Oil Company (filed as Exhibit 10.6 to our Form 10 filed with the SEC on July 5, 2011 and incorporated by reference herein)
*10.7		Compromise Settlement Agreement dated effective December 30, 2011 by and between Mark A. Thompson, Mid-East Oil Company, Mieka Corporation and Vadda Energy Corporation
*21.1		List of Subsidiaries
*23.1		Consent of ValueScope, Inc.
*31.1		Certification of Principal Executive Officer of Periodic Report pursuant to Rule 13a-14a/Rule 14d-14(a)
*31.2		Certification of Principal Financial Officer of Periodic Report pursuant to Rule 13a-14a/Rule 14d-14(a)
*32.1		Certification of Principal Executive Officer of Periodic Report pursuant to 18 U.S.C. Section 1350
*32.2		Certification of Principal Financial Officer of Periodic Report pursuant to 18 U.S.C. Section 1350
*99.1		Reserves and Economics Report – Vadda Energy Corporation as of December 31, 2011
**101.INS		XBRL Instances Document
**101.SCH		XBRL Taxonomy Extension Schema Document
**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB		XBRL Taxonomy Extension Label Linkbase Document
**101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	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: April 16, 2012	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	President and Chief Executive Officer	April 16, 2012
Daro Blankenship	(principal executive officer)

/s/ William J. Amdall	Chief Financial Officer	April 16, 2012
William J. Amdall	(principal financial officer)

/s/ Anita G. Blankenship	Chairwoman of the Board of Directors,	April 16, 2012
Anita G. Blankenship	Executive Vice President and Assistant Secretary

	Director
Verne Rainey

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, 2011 and 2010, 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, 2011 and 2010, 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.

WEAVER AND TIDWELL, L.L.P.

Dallas, Texas

April 16, 2012

F-1

VADDA ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2011 AND 2010

	December 31, 2011			December 31, 2010
Assets:
Cash	$	1,382,166		$	1,836,957
Accounts receivable - net		75,777			95,678
Deferred federal income tax - current		835,275			813,365
Prepaid drilling costs		699,836			—
Total current assets		2,993,054			2,746,000

Property and equipment:
Oil and gas properties, using successful efforts method of accounting:
Proved properties		2,130,500			2,130,500
Other property and equipment		287,561			248,342
Less: Accumulated depletion and depreciation		(498,484	)		(356,488	)
Property and equipment, net		1,919,577			2,022,354

Goodwill		2,740,171			2,740,171
Prepayment to operator, net of valuation allowance of $1,832,500 and $0, respectively		—			1,832,500
Investment in joint ventures		614,500			—
Other assets		187,936			120,573

Total Assets	$	8,455,238		$	9,461,598

Liabilities and Equity:
Accounts payable and accrued liabilities	$	336,670		$	294,319
Current portion of notes payable		13,797			—
Payable to affiliate		75,659			—
Income tax payable		—			19,179
Deferred revenue		6,528,474			3,923,974
Total current liabilities		6,954,600			4,237,472

Notes payable		7,838			—
Asset retirement obligation liability		212,664			160,162
Deferred federal income taxes - long-term		346,526			1,007,262
Total long-term liabilities		567,028			1,167,424

Preferred stock, $.001 par value; 10,000,000 shares authorized; none issued or outstanding as of December 31, 2011 and December 31, 2010		—			—
Common stock, $.001 par value; 150,000,000 shares authorized; 104,235,236 and 104,235,236 issued and outstanding as of December 31, 2011 and December 31, 2010		104,235			104,235
Additional paid-in capital		6,948,359			6,948,359
Accumulated deficit		(5,162,188	)		(2,224,116	)
Total Vadda stockholders’ equity		1,890,406			4,828,478
Deficit attributable to noncontrolling interest		(956,796	)		(771,776	)
Total Equity		933,610			4,056,702

Total Liabilities and Equity	$	8,455,238		$	9,461,598

See accompanying notes to consolidated financial statements

F-2

VADDA ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010

	For the year ended December 31,
	2011			2010
Revenues:
Turnkey drilling revenues	$	—		$	1,116,374
Natural gas and oil sales		419,023			536,809
		419,023			1,653,183
Costs and Expenses:
Turnkey drilling costs		—			1,537,082
Lease operating expense		147,051			178,110
General and administrative		3,916,117			2,035,390
Accretion expense		52,502			7,786
Depletion and depreciation		139,692			134,037
		4,255,362			3,892,405

Operating loss		(3,836,339	)		(2,239,222	)

Other income (expense):
Other		—			1,055

Loss before income taxes		(3,836,339	)		(2,238,167	)

Income tax benefit		(713,247	)		(549,571	)

Net loss		(3,123,092	)		(1,688,596	)

Net loss attributable to noncontrolling interests		(185,020	)		(808,115	)

Net loss attributable to Vadda common stockholders	$	(2,938,072	)	$	(880,481	)

Loss per share attributable to Vadda common stockholders:

Basic and diluted loss per common share	$	(0.03	)	$	(0.01	)

Weighted average number of common shares outstanding - basic and fully diluted		104,235,236			104,174,678

See accompanying notes to consolidated financial statements

F-3

VADDA ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010

	Common Stock				Additional Paid-in			Accumulated			Total Vadda Stockholders’			Equity (Deficit) Attributable to Noncontrolling
	Shares		Amount		Capital			Deficit			Equity			Interests			Total

Balance December 31, 2009		103,721,200	$	103,721	$	6,688,269		$	(1,343,635	)	$	5,448,355		$	36,339		$	5,484,694

Sale of common stock for cash		514,036		514		274,486			—			275,000			—			275,000
Offering costs		—		—		(14,396	)		—			(14,396	)		—			(14,396	)
Net loss		—		—		—			(880,481	)		(880,481	)		(808,115	)		(1,688,596	)

Balance December 31, 2010		104,235,236		104,235		6,948,359			(2,224,116	)		4,828,478			(771,776	)		4,056,702

Net loss		—		—		—			(2,938,072	)		(2,938,072	)		(185,020	)		(3,123,092	)

Balance December 31, 2011		104,235,236	$	104,235	$	6,948,359		$	(5,162,188	)	$	1,890,406		$	(956,796	)	$	933,610

See accompanying notes to consolidated financial statements

F-4

VADDA ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010

	For The Year Ended December 31,
	2011			2010
Cash flows from operating activities:
Net loss	$	(3,123,092	)	$	(1,688,596	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization		139,692			134,037
Accretion expense		52,502			7,786
Deferred tax benefit		(682,646	)		(496,550	)
Bad debt expense		1,832,500			—
Changes in operating assets and liabilities:
Account receivable		19,901			103,742
Prepaid drilling costs		(699,836	)		-
Other current assets		—			(85,073	)
Other assets		(67,364	)		-
Accounts payable and accrued liabilities		23,172			(428,127	)
Payable to affiliates		75,659			—
Deferred revenues		2,604,500			3,281,974
Net cash provided by operating activities		174,988			829,193

Cash flows from investing activities:
Investment in joint venture		(614,500	)		—
Additions to property and equipment		(36,914	)		(11,297	)
Net cash used in investing activities		(651,414	)		(11,297	)

Cash flows from financing activities:
Sale of common stock		—			275,000
Offering costs of private placement		—			(14,396	)
Note payable proceeds		30,000			—
Repayment of note payable		(8,365	)		—
Net cash provided by financing activities		21,635			260,604

Net change in cash		(454,791	)		1,078,500
Cash balance, beginning of year		1,836,957			758,457
Cash balance, end of year	$	1,382,166		$	1,836,957

See accompanying notes to consolidated financial statements

F-5

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, 2011 and 2010.

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.

F-6

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, 2011 and 2010.

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 other property and equipment by major categories as of December 31, 2011 and 2010 and the estimated useful lives.

	2011			2010

Natural gas and crude oil properties	$	2,130,500		$	2,130,500
Accumulated depletion		(261,235	)		(131,956	)
Net natural gas and crude oil properties		1,869,265			1,998,544

Other property and equipment
Transportation equipment		32,544			32,544
Office furniture and equipment		227,481			188,262
Leasehold improvements		27,536			27,536
Accumulated depreciation		(237,249	)		(224,532	)
Net other property and equipment		50,312			23,810

Total net property and equipment	$	1,919,577		$	2,022,354

		Years

Transportation equipment		5
Office furniture and equipment		5
Leasehold improvements		5 - 40

The Company recorded depletion, depreciation and amortization on its assets of $139,692 and $134,037 for the years ended December 31, 2011 and 2010, 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.

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, 2011.

F-7

Vadda Energy Corporation and Subsidiaries

Notes to Consolidated Financial Statements

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. As of December 31, 2011 and 2010 the Company had $6,528,474 and $3,923,974, respectively, in deferred turnkey drilling revenue.

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. No management fee income has been earned from the three new joint ventures through December 31, 2011.

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 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.

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, 2011 or 2010. 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, 2011 and 2010, the Company had no amount recorded as an allowance for doubtful accounts for accounts receivable.

F-8

Vadda Energy Corporation and Subsidiaries

Notes to Consolidated Financial Statements

Recently Issued Accounting Standards

Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The guidance requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods and retrospectively for all comparative periods presented. Under U.S. generally accepted accounting principles (“GAAP”), derivative assets and liabilities can be offset under certain conditions. The guidance requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on its financial position or results of operations.

Common Fair Value Measurement and Disclosure

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs.” The guidance amends previously issued authoritative guidance and requires new disclosures, clarifies existing disclosures and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the guidance clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing fair value measurements guidance. The Company is currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on its financial position or results of operations.

Comprehensive Income

In June 2011, authoritative guidance was issued on the presentation of comprehensive income. Specifically, the guidance allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. The new guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This guidance will be applied retrospectively and will be effective for the Company’s interim and annual reporting periods beginning after December 15, 2011. The changes in presentation of comprehensive income will have no effect on the calculation of net income, comprehensive income or earnings per share.

Impairment

Goodwill

At December 31, 2011 and 2010, the Company had $2,740,171 of goodwill related to the acquisition of certain oil and gas joint ventures on December 1, 2009, as described in Note 1.

Goodwill represents the excess of the purchase price over the fair value of the net assets acquired. The Company follows ASC Topic 350, “Goodwill and Intangible Asset Impairment Testing.” The Company’s analysis consists of two steps. Step 1 tests the company for impairment by comparing the fair value of equity to the book value of equity. If the fair value is less than the book value, then a Step 2 analysis must be performed. If the fair value of goodwill is less than its carrying amount, impairment is recorded based on the difference. The Company annually assesses the carrying value of goodwill for impairment. No impairment loss was recorded for the years ended December 31, 2011 and 2010.

F-9

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

Earnings or 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, 2011 and 2010.

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 an interest in the Mieka/Jefferson-Cattargus Oil & Gas Project A in the amount of $614,500. This investment represents the Company’s cost in the venture as of December 31, 2011 as the investment was still raising capital and had no operations as of December 31, 2011.

NOTE 3– STOCKHOLDERS’ EQUITY

In February 2010, the Company completed the sale of 514,036 shares in a private offering that commenced during 2009 for aggregate proceeds of $275,000. Proceeds from the offering were used (1) to pay legal fees, accounting and other expenses associated with the offering, (2) to update and audit the Company’s financial statements, (3) to complete acquisition of oil and gas assets owned by certain joint ventures managed by Mieka, (4) to complete the merger with Mieka and (5) for working capital and general corporate purposes. In connection with the private offering, the Company incurred $14,396 in offering costs, which have been recorded as a reduction of additional paid-in capital. No capital transactions occurred during the year ended December 31, 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 $309,920 and $0 as of December 31, 2011 and 2010, 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, 2010, 2009 and 2008 for Vadda and tax years ended June 30, 2011, 2010 and 2009 for Mieka. The Company has no material uncertain tax positions at December 31, 2011 and 2010.

While the Company is reporting consolidated financial statements for Vadda and Mieka for the twelve months ended December 31, 2011 and 2010, 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.

F-10

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:

	2011			2010
Provision (benefit) for income taxes:
Current	$	(30,601	)	$	(53,021	)
Deferred		(682,646	)		(496,550	)
Income tax provision (benefit)	$	(713,247	)	$	(549,571	)

A reconciliation between the statutory federal income tax rate and the Company’s effective income tax rate is as follows:

	2011			2010

Statutory tax rate (34%)	$	(1,237,565	)	$	(479,019	)
Change in valuation allowance		309,920			—
Other, net		214,398			(70,552	)
	$	(713,247	)	$	(549,571	)
Effective tax rate		20	%		25	%

The components of the Company’s net deferred tax asset and liability are as follows at the dates indicated:

	December 31,
	2011			2010
Deferred tax asset accounts:
Deferred revenue	$	—		$	1 ,115,327
Accounts payable		66,849			58,507
Asset retirement obligation		72,306			—
Net operating loss carryforward		1,104,110			—
Total gross deferred tax asset accounts		1,243,265		$	1,173,834

Less: Valuation allowance (current)		(309,920	)		—
Net deferred tax assets	$	933,345		$	1,173,834

Deferred tax liability accounts:
Accounts receivable	$	(25,765	)	$	(32,530	)
Prepaid drilling costs		—			(327,939	)
Natural gas and crude oil properties		(418,831	)		(1,007,262	)
Total deferred tax liability accounts		(444,596	)		(1,367,731	)

Net deferred tax asset (liability)	$	(488,749	)	$	(193,897	)

F-11

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:

	December 31,
	2011			2010

Current deferred tax asset	$	835,275		$	813,365
Non-current deferred tax liability (asset)		(346,526	)		(1,007,262	)
	$	488,749		$	(193,897	)

The Company had net operating loss (“NOL”) carryforwards of approximately $3,200,000 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 these NOLs of approximately $900,000 equal to the entire potential tax benefit related to the NOL carryforwards of Vadda. 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 2006. 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 OBLIGATION

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 reconciliation of the Company’s liability for well plugging and abandonment costs for the years ended December 31, 2011 and 2010 are as follows:

	2011		2010

Asset retirement obligation, beginning of year	$	160,162	$	152,376
Accretion expense		52,502		7,786
Asset retirement obligation, end of year	$	212,664	$	160,162

The above asset retirement obligations were included in long-term liabilities in the Company’s consolidated balance sheets.

F-12

Vadda Energy Corporation and Subsidiaries

Notes to Consolidated Financial Statements

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:

·	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.

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, 2011 and 2010, the Company incurred drilling costs associated with turnkey drilling contracts with Mieka LLC of $699,836 and $963,154, respectively. As of December 31, 2011 and 2010, the Company was obligated to pay $662,292 and $207,564, respectively, to Mieka LLC.

During the years ended December 31, 2011 and 2010, Daro and Anita Blankenship, principal shareholders of the Company, received aggregate compensation from the Company of $238,500 and $349,025, respectively.

NOTE 8 – LEASES

The Company leases office space on a month-to-month basis under the terms of an office lease that expired in June 2011 and currently pays $13,073 per month for rent expense.

NOTE 9 – VARIABLE INTERESTS ENTITIES (VIE)

In June 2009, the FASB amended its guidance on accounting for variable interest entities. The new accounting guidance resulted in a change in the Company’s 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.

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.

F-13

Vadda Energy Corporation and Subsidiaries

Notes to Consolidated Financial Statements

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 2011 and 2010 and the VIE has been included in the consolidated financial statements as of and for the years ended December 31, 2011 and 2010.

The table below reflects the amount of assets and liabilities from the VIE included in the consolidated balance sheets as of December 31, 2011 and 2010.

	December 31, 2011			December 31, 2010
Assets:
Cash	$	1,232,252		$	26,088
Accounts receivable from affiliates		662,292			207,564
Prepaid drilling cost		699,836			—
Investment in joint ventures		614,500			—
Other assets		64,971			36,700
Total assets	$	3,273,851		$	270,352

Liabilities and Equity:
Accounts payable and accrued liabilities	$	38,233		$	78,974
Deferred revenue		4,192,414			963,154
Total liabilities	$	4,230,647		$	1,042,128

Retained earnings (accumulated deficit)		(956,796	)	$	(771,776	)
Total stockholders’ equity deficit		(956,796	)		(771,776	)

Total Liabilities and Equity	$	3,273,851		$	270,352

F-14

Vadda Energy Corporation and Subsidiaries

Notes to Consolidated Financial Statements

NOTE 10 – SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Natural Gas and Oil Operations

The following table sets for the revenue and direct cost information relating to the Company’s oil and gas exploration and production activities:

	2011		2010

Crude oil and natural gas production revenues	$	419,023	$	536,809
Operating cost:
Depreciation, depletion and amortization
Recurring (1)		129,279		119,031
Lease operating expenses (2)		147,051		178,110

Income before taxes	$	142,693		239,668
Income tax expense		48,516		81,487
Results of operations	$	94,177	$	158,181
Equivalent units of production (Mcf)		88,253		94,450
Recurring DD&A per equivalent unit Mcf)	$	1.46	$	1.26

(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.

Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

	2011		2010

Acquisitions
Proved	$	—	$	—
Unproved		—		—
Exploration		—		—
Development		—		—
Costs incurred	$	—	$	—

Capitalized Costs

	2011			2010

Proved properties	$	2,130,500		$	2,130,500
Unproved properties		—			—
	$	2,130,500		$	2,130,500
Accumulated DD&A		(261,235	)		(131,956	)
	$	1,869,265		$	1,998,544

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.

F-15

Vadda Energy Corporation and Subsidiaries

Notes to Consolidated Financial Statements

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, 2011 and 2010. 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 William J. Amdall) 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.

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, 2011 and 2010 follows:

	Natural Gas (Mcf)			Oil (Bbls)

Balance January 1, 2010		1,564,030			7,881
Purchase of reserves in place		102,290			1,219
Production	(89,410		)		(840	)
Revision of previous estimate		—			—
Balance December 31, 2010		1,576,910			8,260
Extensions, discoveries and other additions		15,930			-
Production		(84,653	)		(600	)
Revision of previous estimate		(248,757	)		(630	)
Proved reserves – December 31, 2011		1,259,430			7,030

Proved natural gas reserves as of December 31, 2011 include undeveloped reserves of 15,930 Mcf.

Future Net Cash Flows

Future cash inflows as of December 31, 2011 and 2010 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 2011 and 2010, 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.

	2011			2010
Future cash inflows	$	5,985,250		$	7,473,221
Future production costs		(3,321,510	)		(3,822,500	)
Future income tax expense		(905,672	)		(1,241,245	)
Future net cash flows		1,758,068			2,409,476
10% annual discount for estimated timing of cash flows		(962,781	)		(1,240,807	)
Standardized measure of discounted future cash flows	$	795,287		$	1,168,669

F-16

Vadda Energy Corporation and Subsidiaries

Notes to Consolidated Financial Statements

The changes in the standardized measure of future net cash flows for the years ended December 31, 2011 and 2010 are as follows:

	2011			2010
Standardized measure of discounted cash flows:
Balance at beginning of year	$	1,168,669		$	1,005,299
Changes in value of previous year reserves due to:
Value of reserves added due to extensions and discoveries		—			137,920
Accretion of discount		10,092			124,081
Sales of oil and gas produced, net of production costs		(179,501	)		(358,698	)
Revision of reserve quantities		(85,863	)		—
Net change in prices		(148,372	)		(123,400	)
Net change in income taxes		50,446			41,956
Timing and other		(20,184	)		341,511
Balance at end of year	$	795,287		$	1,168,669

F-17

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Legalese
Litigious
Readability	H.S. freshman Avg

Vadda Energy (BMVH) Inactive 10-K2011 FY Annual report

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