Edgar Filing: TRANS ENERGY INC

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Accelerated filer

Non-accelerated filer

¨ (Do not check if small reporting company)

Smaller reporting company

Form 10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

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

Commission File Number 0-23530

TRANS ENERGY, INC.

(Exact name of registrant as specified in its charter)

Nevada

93-0997412

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

210 Second Street, P.O. Box 393, St. Marys, West Virginia 26170

(Address of principal executive offices)

Registrant’s telephone no., including area code: (304) 684-7053

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 ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ 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 ¨

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate Website, 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 ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in the definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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 definitions of large accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act.

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2011) was $7,840,826 (based on price of $2.40 per share).

The number of shares outstanding of each of the issuer’s classes of common equity, as of March 30, 2012, was 12,979,828.

EXPLANATORY NOTE

We are filing this amendment to our annual report on Form 10-K for the year ended December 31, 2011, filed on April 16, 2012, to reflect changes made in response to comments we received from the staff of the Division of Corporation Finance of the Securities and Exchange Commission (“SEC”) in connection with the staff’s review of our annual report.

Significant changes include the following:

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Included in Item 2. Properties

•

Expanded disclosure to discuss technology used to establish appropriate level of certainty for material additions to our reserve estimates

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Expanded disclosure of our internal controls used reserve estimation process

•

Expanded disclosure on number of producing wells to include net number of wells

•

Revisions

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Exhibits 31.1 & 31.2- revised to include updated Small business issuer language, current management and the current date

•

Exhibit 32- revised to reflect current management and the current date

No attempt has been made in this Amendment No. 1 on Form 10-K/A to modify or update the other disclosures presented in the Form 10-K. This Amendment No. 1 on Form 10-K/A does not reflect events occurring after the filing of the Form 10-K or modify or update those disclosures. Accordingly, this Amendment No. 1 on Form 10-K/A should be read in conjunction with the Form 10-K and our other filings with the SEC.

TRANS ENERGY, INC.

Table of Contents


		Page

PART I
Item 1	Business		2
Item 1A	Risk Factors		5
Item 1B	Unresolved Staff Comments		14
Item 2	Properties		15
Item 3	Legal Proceedings		18
Item 4	Mine Safety Disclosures		19

PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		19
Item 6	Selected Financial Data		19
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 7A	Quantitative and Qualitative Disclosures About Market Risk		24
Item 8	Consolidated Financial Statements and Supplementary Data		24
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		24
Item 9A	Controls and Procedures		24
Item 9B	Other Information		25

PART III
Item 10	Directors, Executive Officers, and Corporate Governance		25
Item 11	Executive Compensation		26
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		26
Item 14	Principal Accounting Fees and Services		26

PART IV
Item 15	Exhibits and Financial Statement Schedules		26
	Signatures		27

PART I

Item 1 Business

History

Trans Energy, Inc. is engaged in the acquisition, exploration, development and production of natural gas and oil, and, to a lesser extent, the marketing and transportation of natural gas. We own interests in and operate approximately 300 oil and gas wells in West Virginia, of which 122 are currently active. We also own and operate an aggregate of 19 miles of 6-inch and 4-inch gas transmission lines located within West Virginia in the counties of Marion, Doddridge, Ritchie, Wetzel and Tyler. We also have 52,301 gross acres under lease in West Virginia primarily in the counties of Wetzel, Marshall, Marion, and Doddridge.

Our principal executive offices are located at 210 Second Street, P.O. Box 393, St. Marys, West Virginia 26170, and our telephone number is (304) 684-7053.

Recent Events

On February 22, 2012, we incorporated American Shale Development under the laws of the State of Delaware as our direct wholly owned subsidiary. American Shale was established in order to accommodate certain provisions related to the terms of the proposed credit agreement (the “Credit Agreement”) from Chambers Energy Management, LP (“the Chambers facility”). The proposed credit facility is in the aggregate amount of $50 million, the proceeds of which are to be used to refinance existing debt and accounts payable as well as to allow for continued development of the company’s Marcellus acreage (the “Marcellus Properties”). We expect to receive the proceeds of the Chambers facility prior to April 30, 2012.

On March 30, 2012 the Company and CIT entered into the Eighth Amendment to the CIT Credit Agreement. The Eighth Amendment and other related agreements extend the maturity date of the CIT Credit Agreement to April 30th, 2012. The Eighth Amendment also waves specific items of default.

Trans Energy drilled six wells in 2011. Four wells were drilled in a horizontal joint venture with Republic Partners and a farm out with an unaffiliated third party. A farm out agreement was entered into whereby the third party would purchase a working interest in the wellbores. Trans Energy retains a 5% working interest in the wellbores and the third party retains 45% working interest. Once the third party receives 100% of their investment; then Trans Energy’s working interest will increase to 10% and the third party’s working interest will be reduced to 40%. Republic Partners elected to retain 50% working interest in these wells as permitted by the terms of the joint venture. The wells drilled under these agreements are the Whipkey 3H, Lucey 2H, Goshorn 1H and Goshorn 2H.

The Whipkey 3H and the Lucey 2H were drilled and completed in 2011. The Goshorn 1H and Goshorn 2H were drilled in 2011 awaiting completion in 2012. These wells average a vertical total depth of 7,500 feet and an average lateral of 5,000 feet. The primary target of these wells is the Marcellus Shale.

The Dewhurst 110H and Dewhurst 111H were drilled in the fourth quarter of 2011. These wells will be completed by the second quarter of 2012. The wells were horizontal joint ventures with Republic Partners. Republic Partners elected to obtain 50% paid working interests in these wells as permitted by the terms of the joint venture. These wells average a vertical total depth of 7,500 feet and an average lateral of 5,000 feet. The primary target of these wells is the Marcellus Shale.

Business History

Our business strategy is to economically increase reserves, production and the sale of natural gas and oil from existing and acquired properties in the Appalachian Basin and elsewhere, in order to maximize shareholders’ return over the long term. Our strategic location in West Virginia enables us to actively pursue the acquisition and development of producing properties in that area that will enhance our revenue base without proportional increases in overhead costs.

The Company has been an oil and gas developer for more than twenty years, but began a more aggressive focus on development and growth in early 2006. We began an effort to leverage the company’s acreage and reserves to fund development, and have drilled more than 30 wells since early 2006 and significantly increased production and reserves. During late 2007, we redirected our focus from shallow drilling to drilling exclusively in the Marcellus Shale. Management intends to continue to develop and increase the production from oil and natural gas properties that we currently own. We will continue to transport and market natural gas through our pipelines.

Current Business Activities

We operate our oil and natural gas properties and transport and market natural gas through our transmission systems in West Virginia. Although management desires to acquire additional oil and natural gas properties and to become more involved in exploration and development, this can only be accomplished if we can secure future funding. Management intends to continue to develop and increase the production from the oil and natural gas properties that it currently owns.

Marketing

We operate exclusively in the oil and gas industry. Natural gas production from wells owned by us is generally sold to various intrastate and interstate pipeline companies and natural gas marketing companies. Sales are generally made under short-term delivery contracts at market prices. These prices fluctuate with natural gas contracts as posted in national publications and on the New York Mercantile Exchange.

The majority of our natural gas is sold to SEI Energy, LLC, Dominion and its subsidiaries or HG Energy, LLC.

Natural gas delivered through Trans Energy’s pipeline network is sold primarily to Dominion Gas, a local utility company, on an on-going basis at a variable price per month per Mcf, or to Sancho Oil and Gas Corporation (“Sancho”), a company controlled by the Vice President of Trans Energy, at the industrial facilities near Sistersville, West Virginia. Under its contract with Sancho, Trans Energy has the right to sell natural gas subject to the terms and conditions of a contract, as amended, that Sancho entered into with Dominion Gas in 1988. This agreement is a flexible volume supply agreement whereby Trans Energy receives the full price which Sancho charges the end user less a $0.05 per Mcf marketing fee paid to Sancho. The amount paid to Sancho under this agreement was approximately $135 in 2011 and approximately $3,000 in 2010. Approximately 98% is sold to Dominion and 2% is sold to Sancho.

We sell our oil production to third party purchasers under agreements at posted field prices. These third parties purchase the oil at the various locations where the oil is produced and haul it via truck. Trans Energy currently has two oil purchasers, BD Oil Gathering Corp. and Clearfield Appalachian.

Competition

We are in direct competition with numerous oil and natural gas companies, drilling and income programs and partnerships exploring various areas of the Appalachian Basin and elsewhere competing for customers. 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 personnel resources, sometimes enabling them to identify and acquire more economically desirable energy producing properties and drilling prospects than us. We are more of a regional operator, and have the traditional competitive strengths of one, including long established contacts and in-depth knowledge of the local geography. Additionally, there is increasing competition from other fuel choices to supply the energy needs of consumers and industry. There is also the possibility that future energy-related legislation and regulations may impact competitive conditions. Management believes that there exists a viable market place for smaller producers of natural gas and oil and for operators of smaller natural gas transmission systems. If that situation were to change, management believes the Company would command a competitive price if it became part of a larger company.

Government Regulation

The oil and gas industry is extensively regulated by federal, state and local authorities. The scope and applicability of legislation is constantly monitored for change and expansion. Numerous agencies, both federal and state, have issued rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for noncompliance. To date, these mandates have had no material effect on our capital expenditures, earnings or competitive position.

Legislation and implementing regulations adopted or proposed to be adopted by the Environmental Protection Agency and by comparable state agencies, directly and indirectly, affect our operations. We are required to operate in compliance with certain air quality standards, water pollution limitations, solid waste regulations and other controls related to the discharging of materials into, and otherwise protecting the environment. These regulations also relate to the rights of adjoining property owners and to the drilling and production operations and activities in connection with the storage and transportation of natural gas and oil.

There is a growing concern that future federal legislation may address emissions such as greenhouse gasses that are perceived to present an endangerment to human health and the environment. Such new legislation and regulations could result in the creation of additional costs in the form of taxes, restrictions of output and the investments of additional capital to maintain compliance with laws and regulations. Compliance with new laws and regulations could significantly increase operating costs, reduce demand for our products, impact the cost and availability of capital and increase our exposure to litigation. New legislation could also focus on increasing demand for less carbon intensive energy sources, which could adversely affect demand for the natural gas and oil we market. The implementation of new laws and regulations remains uncertain as do the ultimate impact to our operating costs and business.

We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed operations may have upon the environment. Requirements imposed by such authorities could be costly, time-consuming and could delay continuation of production or exploration activities. Further, the cooperation of other persons or entities may be required for us to comply with all environmental regulations. It is conceivable that future legislation or regulations may significantly increase environmental protection requirements and, as a consequence, our activities may be more closely regulated which could significantly increase operating costs. However, management is unable to predict the cost of future compliance with environmental legislation. As of the date hereof, management believes that we are in compliance with all present environmental regulations. Further, we believe that our oil and gas explorations do not pose a threat of introducing hazardous substances into the environment. If such event should occur, we could be liable under certain environmental protection statutes and laws. We presently carry insurance for environmental liability.

Our exploration and development operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes the requirement of permits for the drilling of wells, the regulation of the location and density of wells, limitations on the methods of casing wells, requirements for surface use and restoration of properties upon which wells are drilled, and governing the abandonment and plugging of wells. Exploration and production are also subject to property rights and other laws governing the correlative rights of surface and subsurface owners.

We are subject to the requirements of the Occupational Safety and Health Act, as well as other state and local labor laws, rules and regulations. The cost of compliance with the health and safety requirements is not expected to have a material impact on our aggregate production expenses. Nevertheless, we are unable to predict the ultimate cost of compliance.

Although past sales of natural gas and oil were subject to maximum price controls, such controls are no longer in effect. Other federal, state and local legislation, while not directly applicable to us, may have an indirect effect on the cost of, or the demand for, natural gas and oil.

Employees

As of the end of our fiscal year on December 31, 2011, we employed twenty-five full-time employees, consisting of eight executives and managers, nine marketing, lease acquisition and clerical persons, and eight field operations employees.

None of our employees are members of any union, nor have they entered into any collective bargaining agreements. We believe that our relationship with our employees is good. With the successful implementation of our business plan, we may seek additional employees in the next year to handle anticipated potential growth.

Industry Segments

We are presently engaged in the principal business of the exploration, development and, production of natural gas and oil. We are also involved in pipeline transportation and marketing of natural gas and oil. Reference is made to the statements of operations contained in the financial statements included herewith for a statement of our revenues and operating income for the past two fiscal years.

Item 1A Risk Factors

You should carefully consider the risks and uncertainties described below and other information in this report. If any of the following risks or uncertainties actually occur, our business, financial condition and operating results, would likely suffer. Additional risks and uncertainties, including those that are not yet identified or that we currently believe are immaterial, may also adversely affect our business, financial condition or operating results.

We have a history of losses and may realize future losses

Our revenues increased approximately 141% during the fiscal year ended December 31, 2011, primarily due to an increase in natural gas and natural gas liquid sales from additional Marcellus wells being put in line. However, we may not achieve, or subsequently maintain profitability if anticipated revenues do not

increase in the future. We have experienced operating losses, negative cash flow from operations and net losses in most quarterly and annual periods for the past several years. As of December 31, 2011, our net operating loss carryforward was approximately $6.2 million and our accumulated deficit was approximately $12 million. We expect to continue to incur significant costs in connection with exploration and development of new and existing properties.

Accordingly, we will need to generate significant revenues to achieve, attain, and eventually sustain profitability. If revenues do not increase, we may be unable to attain or sustain profitability on a quarterly or annual basis. Any of these factors could cause the price of our stock to decline.

As of December 31, 2011, we had a working capital deficit of approximately $18 million that makes it more difficult to obtain capital necessary for our operations and which may have an adverse effect on our future business. This deficit in working capital is primarily attributed to the reclassification of notes payable to current. If our business does not produce positive working capital in the future, our business and financial condition would most likely be materially and negatively impacted.

If we default on our revolving credit facility, our financial condition and future operations would be severely and negatively affected.

On June 15, 2010, our senior secured revolving credit facility became due in the principal amount of $30,000,000, plus accrued interest and fees. Subsequently, we sold certain assets, including oil and gas interests, to pay down the principal amount and have worked with the lender to restructure the credit arrangement. In March 2011, we amended our agreement with the lender that extends the maturity date of the credit arrangement to March 31, 2012. The total due under the agreement at March 31, 2011 was $18,184,978. If we are unable to successfully service and repay the debt, we would be in default under the amended agreement. In that event, the lender would have a first priority, continuing security interest in all of our properties and assets and any proceeds from sales and revenues generated from those assets. This would cause a severe, negative impact on our financial condition. Also, if it becomes necessary to sell off additional assets to service the debt, we may be forced to dispose of valuable assets that would cause additional financial hardship. In March 2012, we amended our agreement with the lender that extends the maturity date to April 30, 2012. It is anticipated that our new financing will be in place by April 30, 2012. On February 29, 2012, the Company’s subsidiary, American Shale Development, Inc., entered into a credit agreement, whereby, subject to the satisfaction of certain conditions to funding, certain lenders have committed to provide up to $50 million in funding to be used to refinance certain outstanding indebtedness of Trans Energy, to fund drilling and completion costs.

Management believes that we may need to seek additional funding in the future for capital expenditures if the $50 million is not received. If we cannot meet future capital requirements through realized revenues from our ongoing business, we may have to raise additional capital by borrowing or by selling equity or equity-linked securities, which would dilute the ownership percentage of our existing stockholders. Also, these securities could also have rights, preferences or privileges senior to those of our common stock. Similarly, if we raise additional capital by issuing debt securities, those securities may contain covenants that restrict us in terms of how we operate our business, which could also affect the value of our common stock. If we borrow more money, we will have to pay interest and may also have to agree to restrictions that limit operating flexibility. We may not be able to obtain funds needed to finance operations at all, or may be able to obtain funds only on very unattractive terms. Management may also explore other alternatives such as a joint venture with other oil and gas companies. There can be no assurances, however, that we will conclude any such transaction.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “Item 1A. Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves” below for a discussion of the uncertainties involved in these processes. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:

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delays imposed by or resulting from compliance with regulatory requirements;

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unusual or unexpected geological formations;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel;

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equipment malfunctions, failures or accidents;

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unexpected operational events and drilling conditions;

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pipe or cement failures;

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casing collapses;

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lost or damaged oilfield drilling and service tools;

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loss of drilling fluid circulation;

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uncontrollable flows of oil, natural gas and fluids;

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fires and natural disasters;

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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

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adverse weather conditions;

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reductions in oil and natural gas prices;

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oil and natural gas property title problems; and

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market limitations for oil and natural gas.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.

We have limited experience in drilling wells to the Marcellus Shale and limited information regarding reserves and decline rates in the Marcellus Shale. Wells drilled to this shale are more expensive and more susceptible to mechanical problems in drilling and completion techniques than wells in other conventional areas.

We have limited experience in the drilling and completion of Marcellus Shale wells, including limited horizontal drilling and completion experience. Other operators in the Marcellus Shale play may have significantly more experience in the drilling and completion of these wells, including the drilling and completion of horizontal wells. In addition, we have limited information with respect to the ultimate recoverable reserves and production decline rates in these areas. The wells drilled in the Marcellus Shale are primarily horizontal and require more stimulation, which makes them more expensive to drill and complete. The wells will also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore due to the length of the lateral portions of these unconventional wells. The fracturing of these shale formations will be more extensive and complicated than fracturing geological formations in conventional areas of operation.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable, particularly in light of the current economic environment. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

We may, from time to time, encounter difficulty in obtaining, or an increase in the cost of securing, drilling rigs, equipment, services and supplies. In addition, larger producers may be more likely to secure access to such equipment and services by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would adversely affect our financial condition and results of operations.

Revisions of oil and gas reserve estimates could adversely affect the trading price of our common stock. Oil and gas reserves and the standardized measure of cash flows represent estimates, which may vary materially over time due to many factors.

The market price of our common stock may be subject to significant decreases due to decreases in our estimated reserves, our estimated cash flows and other factors. Estimated reserves may be subject to downward revision based upon future production, results of future development, prevailing oil and gas prices, prevailing operating and development costs and other factors. There are numerous uncertainties and uncontrollable factors inherent in estimating quantities of oil and gas reserves, projecting future rates of production, and timing of development expenditures.

In addition, the estimates of future net cash flows from proved reserves and the present value of proved reserves are based upon various assumptions about prices and costs and future production levels that may prove to be incorrect over time. Any significant variance from the assumptions could result in material differences in the actual quantity of reserves and amount of estimated future net cash flows from estimated oil and gas reserves.

Our estimates of proved reserves have been prepared under current SEC rules, which went into effect for fiscal years ending on or after December 31, 2009, and may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.

This Form 10-K presents estimates of our proved reserves as of December 31, 2011 and 2010, which have been prepared and presented under current SEC rules. These rules require SEC reporting companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. The previous rules required that reserve estimates be calculated using year-end pricing. As a result of these changes, direct comparisons to our previously-reported reserves amounts may be more difficult.

Under current SEC requirements, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program, particularly as we develop our acreage in the Marcellus Shale in West Virginia. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill and develop those reserves within the required five-year timeframe.

Our operations require significant amounts of capital and additional financing may be necessary in order for us to continue our exploration activities, including meeting certain drilling obligations under our existing lease obligations.

Our cash flow from our reserves, if any, may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and gas acquisitions, exploration and development activities. Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain properties as a result of not fulfilling our existing drilling commitments. Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production is established or we meet certain capital expenditure and drilling requirements. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available to us on favorable terms.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

Congress has recently considered, is considering, and may continue to consider, legislation that, if adopted in its proposed or similar form, would deprive some companies involved in oil and natural gas exploration and production activities of certain U.S. federal income tax incentives and deductions currently available to such companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

Deficiencies of title to our leased interests could significantly affect our financial condition.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is not to incur the expense of retaining lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of lease brokers and others to perform the field work in examining records in the appropriate governmental or county clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to drilling an exploration well, the operator of the well will typically obtain a preliminary title review of the drillsite lease or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. It does happen, from time-to-time, that the examination made by the operator’s title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect, which could affect our financial condition and results of operations.

We are subject to complex federal, state and local laws and regulations, including environmental laws, which could adversely affect our business.

Exploration for and development, exploitation, production and sale of oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax laws and environmental laws and regulations. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws, regulations or incremental taxes and fees, could harm our business, results of operations and financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations.

It is possible that new taxes on our industry could be implemented and/or tax benefits could be eliminated or reduced, reducing our profitability and available cash flow. In addition to the short-term negative impact on our financial results, such additional burdens, if enacted, would reduce our funds available for reinvestment and thus ultimately reduce our growth and future oil and natural gas production.

Matters subject to regulation include oil and gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials, discharge permits for drilling operations, spacing of wells, environmental protection and taxation. We could incur significant costs as a result of violations of or liabilities under environmental or other laws, including third party claims for personal injuries and property damage, reclamation costs, remediation and clean-up costs resulting from oil spills and discharges of hazardous materials, fines and sanctions, and other environmental damages.

We must obtain governmental permits and approvals for our drilling operations, which can be a costly and time consuming process, which may result in delays and restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of natural gas or oil may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Further, various municipalities in West Virginia have passed ordinances which seek to prohibit hydraulic fracturing. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing

activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

The enactment of the Dodd–Frank Act could have an adverse impact on our ability to hedge risks associated with our business.

Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. The new legislation, known as the Dodd–Frank Wall Street Reform and Consumer Protection Act (the “Dodd–Frank Act”), was signed into law by the President on July 21, 2010 and requires CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Dodd–Frank Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.

We derive a significant amount of our revenue from a relatively small number of purchasers. Our inability to continue to provide services to key customers, if not offset by additional sales to our other customers, could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. The loss of all or a significant part of this revenue would adversely affect our financial condition and results of operations.

There are many competitors in the oil and gas industry

We encounter many competitors in the oil and gas industry including in the exploration and development of properties and the sale of oil and gas. Management expects competition to continue to intensify in the

future. Many existing and potential competitors have greater financial resources, larger market share and more customers than us, which may enable them to establish a stronger competitive position than we have. If we fail to address competitive developments quickly and effectively, we will not be able to grow and our business will be adversely affected.

Our operating results are likely to fluctuate significantly and cause our stock price to be volatile which could cause the value of your investment in our shares to decline.

Quarterly and annual operating results are likely to fluctuate significantly in the future due to a variety of factors, many of which are outside of our control. If operating results do not meet the expectations of securities analysts and investors, the trading price of our common stock could significantly decline which may cause the value of your investment to decline. Some of the factors that could affect quarterly or annual operating results or impact the market price of our common stock include:

•

our ability to develop properties and to market our oil and gas;

•

the timing and amount of, or cancellation or rescheduling of, orders for our oil and gas;

•

our ability to retain key management, sales and marketing and engineering personnel;

•

a decrease in the prices of oil and gas; and

•

changes in costs of exploration or marketing of oil and gas.

Due to these and other factors, quarterly and annual revenues, expenses and results of operations could vary significantly in the future, and period-to-period comparisons should not be relied upon as indications of future performance.

Our business could be adversely affected by any adverse economic developments in the oil and gas industry and/or the economy in general.

The oil and gas industry is susceptible to significant change that may influence our business development due to a variety of factors, many of which are outside our control. Some of these factors include:

•

varying demand for oil and gas;

•

fluctuations in price;

•

competitive factors that affect pricing;

•

attempts to expand into new markets;

•

the timing and magnitude of capital expenditures, including costs relating to the expansion of operations;

•

hiring and retention of key personnel;

•

changes in generally accepted accounting policies, especially those related to the oil and gas industry; and

•

new government legislation or regulation.

Any of the above factors or a significant downturn in the oil and gas industry or with economic conditions generally, could have a negative effect on our business and on the price of our common stock.

Our future success depends on retaining existing key employees and hiring and assimilating new key employees. The loss of key employees or the inability to attract new key employees could limit our ability to execute our growth strategy, resulting in lost profitability and a slower rate of growth.

Our future success depends, in part, on the ability to retain our key employees including executive officers. Also, we do not carry, nor do we anticipate obtaining, “key man” insurance on our executives. It would be difficult for us to replace any one of these individuals. In addition, as we grow we may need to hire additional key personnel. We may not be able to identify and attract high quality employees or successfully assimilate new employees into our existing management structure.

If we are unable to manage our growth effectively, our operations and financial performance could be adversely affected.

The ability to manage and operate our business as we execute our anticipated growth will require effective planning. Significant future growth could strain our internal resources, leading to a lower quality of service and other problems that could adversely affect our financial performance. Our ability to manage future growth effectively will also require us to successfully attract, train, motivate, retain and manage new employees and continue to update and improve our operational, financial and management controls and procedures. If we do not manage our growth effectively, our operations could be adversely affected, resulting in slower growth and a failure to achieve or sustain profitability.

Future environmental legislation related to climate change

Because of growing concern over risks related to climate change, Congress has adopted or is considering the adoption of regulatory frameworks to reduce greenhouse gas emissions. Prospective legislation includes possible cap and trade regimes, carbon taxes, increased efficiency standards and incentives or mandates for renewable energy. New laws and regulations could not only make our products more expensive, but also reduce demand for hydrocarbon products. Such current and pending regulations may also increase operating costs and our compliance costs, such as for enhanced monitoring of emissions.

Going concern issue

Our ability to continue as a going concern is dependent upon our ability to achieve a profitable level of operations. We may need, among other things, additional capital resources which we will seek through loans from banks or other forms of financing.

Risks relating to ownership of our common stock

The price of our common stock is extremely volatile and investors may not be able to sell their shares at or above their purchase price, or at all.

Our common stock is presently traded on the OTC Bulletin Board, although there is no assurance that a viable market will continue. The price of our shares in the public market is highly volatile and may fluctuate substantially because of:

•

actual or anticipated fluctuations in our operating results;

•

changes in or failure to meet market expectations;

•

conditions and trends in the oil and gas industry; and

•

fluctuations in stock market price and volume, which are particularly common among securities of small capitalization companies.

Future sales or the potential for sale of a substantial number of shares of our common stock could cause the market value to decline and could impair our ability to raise capital through subsequent equity offerings.

If we do not generate necessary cash from our operations to finance future business, we may need to raise additional funds through public or private financing opportunities. The issuance of a substantial number of our common shares to individuals or in the public markets, or the perception that these sales may occur, could cause the market price of our common stock to decline and could materially impair our ability to raise capital through the sale of additional equity securities. Any such issuances would dilute the equity interests of existing stockholders.

We do not intend to pay dividends

To date, we have never declared or paid a cash dividend on shares of our common stock. We currently intend to retain any future earnings for growth and development of business and, therefore, do not anticipate paying any dividends in the foreseeable future.

Possible “Penny Stock” Regulation

Trading of our common stock on the Bulletin Board may be subject to certain provisions of the Securities Exchange Act of 1934, commonly referred to as the “penny stock” rule. A penny stock is generally defined to be any equity security that has a market price less than $1.00 per share, subject to certain exceptions. If our stock is deemed to be a penny stock, trading in our stock will be subject to additional sales practice requirements on broker-dealers.

These may require a broker dealer to:

•

make a special suitability determination for purchasers of penny stocks;

•

receive the purchaser’s written consent to the transaction prior to the purchase; and

•

deliver to a prospective purchaser of a penny stock, prior to the first transaction, a risk disclosure document relating to the penny stock market.

Consequently, penny stock rules may restrict the ability of broker-dealers to trade and/or maintain a market in our common stock. Also, many prospective investors may not want to get involved with the additional administrative requirements, which may have a material adverse effect on the trading of our shares.

Item 1B Unresolved Staff Comments

The staff of the Securities and Exchange Commission (SEC Staff”) conducted a review of our Annual Report on Form 10-K for the years ended December 31, 2009 and 2010 and issued a letter commenting on certain aspects of these reports. We believe that all matters addressed in the comment letters and our subsequent responses to these letters and discussions with the SEC Staff have been resolved with the exception of certain disclosures related to our proved undeveloped reserves. Based on discussions with staff members at the SEC regarding the response, the remaining unresolved comment will require that the Company file an amendment to its Form 10-K for the years ended December 31, 2009 and 2010 to remove our proven undeveloped reserves that do not meet the criteria to be reported based on our financial situation.

Item 2 Properties

Our properties consist of working and royalty interests owned by us in various oil and gas wells and leases located in West Virginia. Our proved reserves as of December 31, 2011, 2010, and 2009 are set forth below:


	As of December 31,
	2011						2010				2009
	Oil and Condensates (BBL)		Natural Gas (MCF)		NGL (BBL)		Oil (BBL)		Natural Gas (MCF)		Oil (BBL)		Natural Gas (MCF)
Developed Producing		163,316		16,695,133		559,389		148,567		7,795,932		158,545		5,002,524
Developed Non-Producing		—		—		—		35,175		4,995,712		—		1,562,532
Proved Undeveloped		590		679,280		33,209		—		—		—		—


Total Proved		163,906		17,374,413		592,598		183,742		12,791,644		158,545		6,565,056

The increase in reserves is from drilling in the Marcellus Shale formation and not in the typical traditional shallow well formations. The development of the Marcellus Shale has transformed the Appalachian Basin into one of the country’s premier natural gas plays. In recent years, the application of lateral well drilling and completion technology has led to the development of the Marcellus Shale. The horizontal lateral exceeds 2,000 feet in length and typically involves multistage fracturing completions.

The 2009 reserves have been restated to remove the proved undeveloped reserves. Proved undeveloped reserves are also not reported for 2010 even though we had wells in process of being drilled. Proved undeveloped reserves have been reported for 2011 since the Company has a farm out interest in two wells and therefore did not have to finance them.

A review of our reserves was conducted at year-end 2011, 2010 and 2009 by Wright and Company, Inc., our independent petroleum consultants. The engineer was selected for their geographic expertise and their historical experience in engineering certain properties. The technical person responsible for reviewing the reserve estimates meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The Vice President of Operations works closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished to our independent petroleum consultants for their reserves review process. Throughout the year, our technical team meets periodically with representatives from our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any internally estimated significant changes to our proved reserves. We provide historical information to our consultants for all of our producing properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed.

The preparation of our proved reserve estimates is completed in accordance with our internal control procedures, which include the verification of input data used by Wright and Company, Inc., as well as extensive management review and approval. All of our reserve estimates are reviewed and approved by our President. He is a graduate of Marietta College with a Bachelor of Science in Petroleum Engineering and has over thirty years experience in the oil & gas industry.

The general calculations pertaining to the estimate of reserves, both developed and undeveloped, include but are not limited to; 1) extrapolation of historical production trends; 2) log analysis and volumetric calculations; 3) log cross-sections to confirm continuity of certain formations and/or; 4) analogy to similar producing properties producing from the same formation.

The estimates of reserves were based on reliable technologies that have been field tested and have demonstrated consistency and repeatability in the formation being evaluated.

The economic producibility of these reserves assignments has been established by reliable technology to be reasonably certain in the continuous accumulation in the geographic area to which the reserves are assigned.

Effective for the year end 2009, SEC reporting rules require that year-end reserve calculations and future cash inflows be based on the simple average of the first day of the month price for the previous twelve month period. The benchmark prices for 2011 used in the above table were $4.24 per MMBTU, $89.73 and $58.21 per BBL for the oil and condensates, respectively, and $48.65 per BBL for Natural Gas Liquids (NGL). The benchmark prices for 2010 used in the above table were $5.29 per MMBTU and $70.60 per BBL. The benchmark prices used for 2009 were $4.13 per MMBTU and $61.18 per BBL. The company’s gas processing arrangement did not provide for the separation of condensates or NGL prior to 2011. The separation of the liquid from the gas stream commenced April, 2011 with the opening of the Fort Beeler Operating Facility.

Such reports are, by their very nature, inexact and subject to changes and revisions. Proved developed reserves are reserves expected to be recovered from existing wells with existing equipment and operating

methods. Proved undeveloped reserves are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. No estimates of reserves have been included in any reports to any federal agency other than the SEC in 2011, 2010 and 2009. See Note 18, Supplementary Information on Oil and Gas Producing Activities included as part of our consolidated financial statements.

Productive Gas Wells

The following table summarizes the total number of wells and undrilled locations to which proved developed reserves and proved undeveloped reserves, respectively, are attributed.


	Gross as of December 31,
	2011				2010				2009
	Oil		Natural Gas		Oil		Natural Gas		Oil		Natural Gas
Producing Wells		31		76		71		84		5		183

Non-Producing Wells		—		—		6		12		1		117

Undrilled Well Locations		—		2		—		—		—		—


Total Wells and Well Locations		31		78		77		96		6		300


	Net as of December 31,
	2011				2010				2009
	Oil		Natural Gas		Oil		Natural Gas		Oil		Natural Gas
Producing Wells		30		70		67		75		5		181
Non-Producing Wells		—		—		6		11		1		117
Undrilled Well Locations		—		—		—		—		—

Total Wells and Well Locations		30		70		73		86		6		298

We have removed unproved drilling locations for the year ended December 31, 2009, as well as excluding them for the year ended December 31, 2010 based on our discussions with the SEC (See Item 1B). Furthermore, we excluded all shallow wells with no or minimal production since we do not plan on a rework program at this time. In addition, we have reclassed certain wells for 2010 and 2011 that are now primarily producing oil.

Drilling Activity

The following table summarizes completed drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.


	During the Year Ended, December 31,
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		2.0		0.1		2.0		1.0		2.0		1.0
Dry		—		—		—		—		—		—

Exploratory Wells
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—


Total		2.0		0.1		2.0		1.0		2.0		1.0

The Dewhurst 110H, Dewhurst 111H, Goshorn 1H, and Goshorn 2H were drilled in the fourth quarter of 2011 as discussed under recent events. These wells will be completed by the second quarter of 2012, and are not reflected in the table above. The net wells drilled for 2011 reflect our farm out interest in the Whipkey 3H and Lucey 2H.

Oil and Gas Acreage

The following table summarizes our gross and net developed and undeveloped oil and gas acreage under lease as of December 31, 2011 and 2010.


	Developed Acres				Undeveloped Acres				Total
	Gross		Net		Gross		Net		Gross		Net
West Virginia:
2011		27,550		13,997		24,751		7,039		52,301		21,036
2010		24,779		14,925		24,432		11,629		49,211		26,554

Net acreage decreased due to the sale of acreage to Republic and leases expiring in Tyler County.

The following table sets forth, for our continuing operations, the gross and net acres of undeveloped acreage that will expire during the periods indicated if not ultimately held by production by drilling efforts:


	Expiring Acreage
Year Ending December 31,	Gross		Net
2012		2,313		1,072
2013		10,859		2,837
2014		2,250		449
2015		2,776		722
2016		6,087		1,855
2017		—		—
2018		322		55
2019		—		—
2020		151		50


Total		24,758		7,040

The following table sets forth certain information regarding production volumes, revenue, average prices received and average production costs associated with our sales of oil and natural gas for the periods noted.


	Year Ended December 31,
	2011		2010
Net Production:
Oil (Bbl)		15,876		16,578
Natural Gas (Mcf)		2,769,410		995,101
NGL (Bbl)		42,691		—


Natural Gas Equivalent (Mcfe)		3,120,812		1,094,569


Oil and Natural Gas Sales:
Oil	$	1,554,923	$	878,090
Natural Gas	$	10,214,728	$	4,803,589
NGL	$	2,527,232		—


Total	$	14,293,883	$	5,681,679


Average Sales Price:
Oil ($ per Bbl)	$	97.94	$	52.97
Natural Gas ($ per Mcf)	$	3.69	$	4.83
NGL ($ per Bbl)	$	59.20	$	—
Natural Gas Equivalent ($ per Mcfe)	$	4.58	$	5.19

Oil and Natural Gas Costs:
Lease operating expenses	$	3,314,707	$	1,841,788

Average production cost per Mcfe	$	1.06	$	1.68

It is our intention to purchase assets and/or property for the purpose of enhancing our primary business operations. We are not limited as to the percentage amount of our assets we may use to purchase any additional assets or properties.

Facilities

We currently occupy approximately 4,000 square feet of office space in St. Marys, West Virginia, which we share with our subsidiaries, Tyler Construction Company and Ritchie County Gathering Systems. We lease this space from an unaffiliated third party under a verbal arrangement for $1,800 per month, inclusive of utilities.

Item 3 Legal Proceedings

Certain material pending legal proceedings to which we are a party or to which any of our property is subject, is set forth below:

On May 11, 2011, we filed an action in the U.S. District Court for the Northern District of West Virginia against EQT Corporation, a Pennsylvania corporation (Trans Energy, Inc., et al. v. EQT Corporation). The action relates to our attempt to quiet title to certain oil and gas properties referred to as the Blackshere Lease, consisting of approximately 22 oil and/or gas wells on the Blackshere Lease. The defendant, EQT Corporation, has filed with the Court an answer and counterclaim wherein it claims it holds title to the natural gas within and underlying the Blackshere Lease. We believe that we will ultimately prevail in the action, but it is too early in the proceedings to accurately assess the final outcome. Currently the Company has no plans to drill on this acreage.

On March 6, 2012, James K. Abcouwer (“Abcouwer”), former Chief Executive Officer of the Company, filed an action in the Circuit Court of Kanawha County, West Virginia against the Company (James K. Abcouwer vs. Trans Energy, Inc). The action relates to the Stock Option Agreement (the “Agreement”) entered into between the Company and Abcouwer on February 7, 2008. By his complaint, Abcouwer alleges that the Company has breached the Agreement by not permitting Abcouwer to exercise options that are the subject of the Agreement. The Company believes that per the terms of the Agreement all options and other rights described in the Agreement terminated ninety (90) days after the termination of Abcouwer’s employment with the Company. Mr. Abcouwer is requesting an amount for his loss of the value of the stock options that are subject to the Agreement. Said amount has not been determined.

We may be engaged in various lawsuits and claims, either as plaintiff or defendant, in the normal course of business. In the opinion of management, based upon advice of counsel, the ultimate outcome of these lawsuits will not have a material impact on our financial position or results of operations.

Item 4 Mine Safety Disclosures

Not Applicable

PART II

Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Our common stock is quoted on the OTC Bulletin Board under the symbol TENG. Set forth in the table below are the quarterly high and low prices of our common stock as obtained from the OTC Bulletin Board for the past two fiscal years.


	High		Low
2011
First Quarter	$	3.05	$	2.70
Second Quarter	$	3.00	$	2.30
Third Quarter	$	3.02	$	2.30
Fourth Quarter	$	3.10	$	2.40
2010
First Quarter	$	5.10	$	2.10
Second Quarter	$	4.75	$	2.50
Third Quarter	$	4.00	$	2.75
Fourth Quarter	$	3.25	$	2.80

As of March 31, 2011, there were approximately 420 holders of record of our common stock, which figure does not take into account those shareholders whose certificates are held in the name of broker-dealers or other nominee accounts. We estimate there to be approximately 1,600 such shareholders.

Dividend Policy

We have not declared or paid cash dividends or made distributions in the past, and we do not anticipate that we will pay cash dividends or make distributions in the foreseeable future. We currently intend to retain and reinvest future earnings to finance operations.

Item 6 Selected Financial Data

Not applicable.

Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in conjunction with the consolidated financial statements and notes thereto appearing elsewhere in this Form 10-K.

Business Strategy

Trans Energy is an independent energy company engaged in the acquisition, exploration, development, and production of natural gas and crude oil properties, with interests in West Virginia. The Company executed a major increase in development activity and leasehold acquisitions during the years ended December 31, 2011 and 2010. The Company has had asset sales in 2011 and 2010 to pay down debt and

to finance the drilling program. In addition, we had good success in our drilling program, adding both natural gas and crude oil reserves to the Company’s proved reserve base. Furthermore, the Company established major interconnects with interstate pipelines to allow increased access to the market. The Company’s significant overall increase in reserves has greatly increased the present value of our forecasted cash flows.

We intend to focus our development and exploration efforts in our West Virginia properties and utilize our attractive opportunities to expand our reserve base through continuing to drill higher risk/higher reward exploratory and development drilling in the Marcellus Shale for 2012 and beyond with our new financing as discussed under item 1. Management intends to use a portion of the proceeds from the Chambers facility financing to fund this drilling program. We will evaluate our properties on a continuous basis in order to optimize our existing asset base. We plan to employ the latest drilling, completion and fracturing technology in all of our wells to enhance recoverability and accelerate cash flows associated with these wells. We believe that our extensive acreage position will allow us to grow through high risk drilling in the near term.

In summary, our strategy is to increase our oil and gas reserves and production while keeping our development costs and operating costs as low as possible. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential. The success of this strategy is contingent on various risk factors, as discussed elsewhere in this Form 10-K.

The implementation of our strategy requires that we continually incur significant capital expenditures in order to replace current production and find and develop new oil and gas reserves. In order to finance our capital and exploration program, we depend on cash flow from operations or bank debt and equity offerings as discussed below in Liquidity and Capital Resources.

Results of Operations

The most significant event in 2011 was the sale of 2,950 net acres to Republic Energy Ventures, LLC at $4,750 per net acre for total pretax proceeds of $14,012,500. Proceeds from this transaction were used to repay $5 million to CIT in April, with the remainder being used to partially fund the drilling and completion expenses for certain wells. The reduction of debt reduced our interest expense. The new wells, including the two gross JV wells (one net) and the two farm-out wells (0.1 net) that are expected to be completed during the second quarter of 2012, will increase our revenue and related expenses in the future just as our 2009 and 2010 wells increased this year’s revenue and expenses.

The following table sets forth the percentage relationship to total revenues of principal items contained in our consolidated statements of operations for the two most recent fiscal years ended December 31, 2011 and 2010. It should be noted that percentages discussed throughout this analysis are stated on an approximate basis.


	Fiscal Year Ended December 31,
	2011			2010
Total revenues		100	%		100	%
Total costs and expenses		(113	%)		(154	%)
Gain on sale of assets		86	%		406	%


Income from operations		73	%		352	%
Other expenses		(11	%)		(51	%)
Income Taxes		(1	%)		(7	%)


Net income		61	%		294	%

Total revenues of $14,721,233 for the year ended December 31, 2011 increased $8,621,280 or 141% compared to $6,099,953 for the year ended December 31, 2010. The increase in revenue is due to an increase in production as a result of new drilling, as well as enhanced processing of the natural gas liquids in our production stream, which sell at a higher price per MMBTU than if they were left in the production stream. We focused our efforts during 2011 and 2010 on the implementation of our drilling program in Marshall County, West Virginia. We expect more production increases from the drilling program throughout 2012.

Production costs increased $1,834,136 or 83% for 2011 as compared to 2010, primarily due to an increase in transportation fees and natural gas liquid processing fees associated with the increased production in 2011.

Depreciation, depletion, amortization and accretion expense increased $2,479,148 or 80% for 2011 as compared to 2010, primarily due to the depletion associated with our Marcellus drilling and related increased well cost and production.

Impairment of oil and gas properties increased by $1,071,619 or 495% primarily due to the write down of producing properties in Doddridge County.

Selling, general and administrative expenses increased $1,778,860 or 46% for 2011 as compared to 2010, primarily due to increased legal and consulting fees associated with our debt restructuring and share based compensation.

Gain on sale of assets decreased by $12,163,133 in 2011 as compared to 2010. We sold certain acreage to Republic Ventures, LLC (“Republic”) for $24.8 million during the third quarter of 2010, and we sold additional acreage to Republic for $14.0 million in the first quarter of 2011. The 2010 sale included more acreage than the 2011 sale and included a sale of certain overriding royalty interests.

Our income from operations for 2011 was $10,769,966 compared to $21,475,582 for 2010. This change is primarily due to the larger sale of acreage in 2010 which was offset by higher production income from wells in 2011.

Interest expense decreased $1,552,950 or 48% for 2011 as compared to 2010, due to a lower principal balance in 2011, as well as a reduction in forbearance fees, which were included in interest expense in both periods.

We have accumulated approximately $6.2 million of net operating loss carryforwards as of December 31, 2011, which may be offset against future tax obligations through 2030. The use of these losses to reduce future income taxes will depend on the generation of sufficient taxable income prior to the expiration of the net operating loss carryforwards based on the anticipated funding event as described in recent events. In the event of certain changes in control, there would be an annual limitation on the amount of net operating loss carryforwards which can be used. We recorded $214,000 and $450,000 in income tax expense in 2011 and 2010, respectively. No tax benefit has been reported in the financial statements for the year ended December 31, 2011 because the potential tax benefit of the loss carryforward is offset by a valuation allowance of the same amount.

Off Balance Sheet Arrangements

None.

Liquidity and Capital Resources

Historically, we have satisfied our working capital needs with operating revenues, borrowed funds and the proceeds of acreage sales. At December 31, 2011, we had a working capital deficit of $18,362,177 compared to a working capital deficit of $19,699,824 at December 31, 2010. This decrease in deficit is primarily attributed to an increase in cash and a reduction of the current portion of notes payable, offset in part by an increase in accounts payable. The company intends to repay both the funded debt as well as payables that are outstanding upon the expected closing of the Chambers financing.

During 2011, net cash provided by operating activities was $16,531,927 compared to net cash used of $728,961 in 2010. This increase in cash flow from operating activities is primarily due to a significant increase in deferring cash payments and increasing liabilities such as accounts payable, adding interest to debt principle, as well as an increase in production income.

We expect our cash flow provided by operations for 2012 to increase because of higher projected production from the drilling program, combined with steady operating, general and administrative, interest and financing costs per Mcfe.

Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices, or changes in working capital accounts and actual well performance. In addition, our oil and gas production may be curtailed due to factors beyond our control, such as downstream activities on major pipelines causing us to shut-in production for various lengths of time.

During 2011, net cash used for investing activities was $3,848,414 compared to net cash provided of $12,175,704 in 2010. The reason for the change was a decrease in cash proceeds from acreage sales and increased expenditures for oil and gas properties during 2011 compared to 2010. See notes 6 and 7 to the financial statements for additional information.

During 2011, net cash used by financing activities was $5,835,802 compared to $15,010,972 in 2010. The decrease in the cash used by financing activities was primarily the result of paying down debt to CIT by $5,000,000 in 2011 compared to $15,000,000 in 2010.

We anticipate meeting our working capital needs with revenues from our ongoing operations, and subsequent to the anticipated funding of the Chambers facility, with proceeds from that facility.

Because of our continued losses, working capital deficit, and need for additional funding, there exists substantial doubt about our ability to continue as a going concern. Historically, our revenues have not been sufficient to cover operating costs. We will need to rely on increased operating revenues from new development or proceeds from debt or equity financings to allow us to continue as a going concern. There can be no assurance that we can or will be able to complete any debt or equity financing.

Inflation

In the opinion of our management, inflation has not had a material overall effect on our operations of Trans Energy.

Recent Events

On February 22, 2012, we incorporated American Shale Development under the laws of the State of Delaware as our direct wholly owned subsidiary. American Shale was established in order to accommodate certain provisions related to the terms of the proposed Credit Agreement from Chambers Energy Management, LP (“the Chambers facility”). The proposed credit facility is in the aggregate amount of $50 million, the proceeds of which are to be used to refinance existing debt and accounts payable as well as to allow for continued development of the Marcellus Properties. We expect to receive the proceeds of the Chambers facility prior to April 30, 2012.

On March 30, 2012 the Company and CIT entered into the Eighth Amendment to the Credit Agreement. The Eighth Amendment and other related agreements extend the maturity date of the Credit Agreement to April 30th, 2012. The Eighth Amendment also waves specific items of default.

Forward-looking and Cautionary Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements may relate to such matters as anticipated financial performance, future revenues or earnings, business prospects, projected ventures, new products and services, anticipated market performance and similar matters. When used in this report, the words “may,” “will,” “expect,” “anticipate,” “continue,” “estimate,” “project,” “intend,” and similar expressions are intended to identify forward-looking statements regarding events, conditions, and financial trends that may affect our future plans of operations, business strategy, operating results, and our future plans of operations, business strategy, operating results, and financial position. We caution readers that a variety of factors could cause our actual results to differ materially from the anticipated results or other matters expressed in forward-looking statements. These risks and uncertainties, many of which are beyond our control, include:

•

the sufficiency of existing capital resources and our ability to raise additional capital to fund cash requirements for future operations;

•

uncertainties involved in the rate of growth of our business and acceptance of any products or services;

•

success of our drilling activities;

•

volatility of the stock market, particularly within the energy sector; and

•

general economic conditions.

Although we believe the expectations reflected in these forward-looking statements are reasonable, such expectations cannot guarantee future results, levels of activity, performance or achievements.

Critical accounting policies

We consider accounting policies related to our estimates of proved reserves, accounting for derivatives, share-based payments, accounting for oil and natural gas properties, asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Note 1 of Notes to Consolidated Financial Statements.

New Accounting Standards

Accounting Standards Update No. 2010-20 “Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses” (“ASU No. 2010-20”)

In July 2010, the FASB issued ASU 2010-20. ASU 2010-20 amends disclosure requirements with respect to the credit quality of financing receivables and the related allowance for credit losses. Entities will be required to disaggregate by portfolio segment or class certain existing disclosures and provide certain new disclosures about its financing receivables and related allowance for credit losses. The disclosures will be effective for financial statements issued for fiscal years ending on or after December 15, 2010. Since ASU 2010-20 only amended disclosure requirements, not current accounting practice, this ASU did not have any impact on the Company’s balance sheets, statements of income or statements of cash flows.

Trans Energy reviewed all other recently issued, but not yet effective, accounting pronouncements and does not believe any such pronouncement will have a material impact on the financial statements.

Item 7A Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 8 Consolidated Financial Statements and Supplementary Data

Our consolidated financial statements as of December 31, 2011 and 2010 and for the fiscal years ended December 31, 2011 and 2010 have been audited to the extent indicated in their report by Maloney + Novotny, LLC, independent registered public accounting firm, and have been prepared in accordance with generally accepted accounting principles. The aforementioned financial statements are included herein starting with page F-1.

Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A Controls and Procedures

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.

Evaluation of Controls and Procedures

In connection with the preparation of this Annual Report on Form 10-K, our management, with the participation of our Principle Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of our disclosure controls and procedures as of December 31, 2011, as required by Rule 13a-15 of the Exchange Act. Based on the evaluation described above, our management, including our principal executive officer and principal financial officer, has concluded that, as of December 31, 2011, our disclosure controls and procedures were effective.

We concluded that the consolidated financial statements in this Annual Report on Form 10-K present fairly, in all material respects, the Company’s financial condition, results of its operations and cash flows for the year ended December 31, 2011 in conformity with U.S. generally accepted accounting principles (“GAAP”).

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed under the supervision of our principal executive and principal financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

Due to inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable, not absolute, assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate as a result of changes in conditions or deterioration in the degree of compliance.

Under the supervision and with the participation of our management, including our Principle Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2011 based on the criteria framework established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Based on the assessment, our management has concluded that our internal control over financial reporting was effective as of December 31, 2011, and provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles. The results of management’s assessment were reviewed with our Board of Directors.

Changes in Internal Control over Financial Reporting

During the period ended, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B Other Information

None.

PART III

Item 10 Directors, Executive Officers, and Corporate Governance

Information as to Item 10 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 11 Executive Compensation

Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 13 Certain Relationships and Related Transactions and Director Independence

Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 14 Principal Accounting Fees and Services

Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

PART IV

Item 15 Exhibits and Financial Statement Schedules


Exhibit No.		Exhibit Name

3.1(1)		Articles of Incorporation and all amendments pertaining thereto, for Apple Corp., an Idaho corporation

3.2(1)		Articles of Incorporation for Trans Energy, Inc., a Nevada corporation

3.3(1)		Articles of Merger for the States of Nevada and Idaho

3.4(1)		By-Laws

4.1(1)		Specimen Stock Certificate

10.1(1)		Marketing Agreement with Sancho Oil and Gas Corporation

21.1(6)		Subsidiaries of Registrant (Revised)

31.1		Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification of Principal Accounting Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification of CEO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Principal Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.1		Independent Engineer Resource Report for the year ended December 31, 2011.

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.


TRANS ENERGY, INC.

By:		/s/ JOHN G. CORP
		John G. Corp,
		President and Principal Executive Officer

Dated: April 14, 2012

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ JOHN G. CORP	President and Director	April 14, 2012
John G. Corp	(Principal Executive Officer)

/s/ JOHN S. TUMIS	Chief Financial Officer	April 14, 2012
John S. Tumis

/s/ LOREN E. BAGLEY	Vice President and Director	April 14, 2012
Loren E. Bagley

/s/ WILLIAM F. WOODBURN	Secretary, Treasurer, C.O.O. and Director	April 14, 2012
William F. Woodburn

/s/ BENJAMIN H. THOMAS	Director	April 14, 2012
Benjamin H. Thomas

/s/ RICHARD L. STARKEY	Director	April 14, 2012
Richard L. Starkey

/s/ STEPHEN P. LUCADO	Director	April 14, 2012
Stephen P. Lucado

/s/ ROBERT L. RICHARDS	Director	April 14, 2012
Robert L. Richards

TRANS ENERGY, INC. AND SUBSIDIARIES

CONTENTS



Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets		F-3

Consolidated Statements of Operations		F-5

Consolidated Statements of Stockholders’ Equity		F-6

Consolidated Statements of Cash Flows		F-7

Notes to Consolidated Financial Statements		F-9

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Trans Energy, Inc.

St. Marys, West Virginia

We have audited the accompanying consolidated balance sheets of Trans Energy, Inc. 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 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 audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Trans Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the 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.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has generated significant losses from operations and has a working capital deficit of $18,362,177 at December 31, 2011, which together raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Maloney + Novotny, LLC

Maloney + Novotny, LLC

Cleveland, Ohio

April 14, 2012

F-2

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets


	December 31,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS

Cash	$	7,885,652		$	1,037,941
Accounts receivable, trade		2,074,851			1,195,259
Accounts receivable, related parties		18,500			18,500
Advance royalties		114,099			99,381
Prepaid drilling expenses		73,098			825,646
Accounts receivable due from non-operators, net		1,754,020			82,964
Note receivable		—			27,295
Deferred financing costs, net		237,500			—
Derivative assets		—			187,590


Total Current Assets		12,157,720			3,474,576

PROPERTY AND EQUIPMENT, net of accumulated depreciation of $762,132 and $612,047, respectively		1,081,378			1,148,500

OIL AND GAS PROPERTIES, USING SUCCESSFUL EFFORTS ACCOUNTING
Proved properties		48,335,664			36,579,636
Unproved properties		9,507,789			6,156,188
Pipelines		1,387,440			1,387,440
Accumulated depreciation, depletion and amortization		(14,545,126	)		(7,909,714	)


Oil and gas properties, net		44,685,767			36,213,550

OTHER ASSETS

Other assets		300,952			50,952


Total Other Assets		300,952			50,952


TOTAL ASSETS	$	58,225,817		$	40,887,578

See notes to consolidated financial statements.

F-3

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (continued)


	December 31,			December 31,
	2011			2010
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES

Accounts payable, trade	$	14,333,750		$	4,116,510
Accounts and notes payable, related party		2,150			2,150
Accrued expenses		1,152,885			1,228,261
Revenue Payable		451,825			—
Income Tax Payable		270,708			450,000
Notes payable – current, net of unamortized discount of $0 and $145,677, respectively		14,308,579			17,377,479


Total Current Liabilities		30,519,897			23,174,400

LONG-TERM LIABILITIES

Notes payable		5,612			20,818
Asset retirement obligations		256,651			219,478


Total Long-Term Liabilities		262,263			240,296


Total Liabilities		30,782,160			23,414,696


COMMITMENTS AND CONTINGENCIES		—			—

STOCKHOLDERS’ EQUITY

Preferred stock 10,000,000 shares authorized at $0.001 par value; -0- shares issued and outstanding		—			—
Common stock 500,000,000 shares authorized at $0.001 par value; 12,981,828 and 12,737,328 shares issued, and 12,979,828 and 12,735,328 shares outstanding, respectively		12,982			12,737
Additional paid-in capital		39,300,194			38,256,340
Treasury stock, at cost, 2,000 shares		(1,950	)		(1,950	)
Accumulated deficit		(11,867,569	)		(20,794,245	)


Total Stockholders’ Equity		27,443,657			17,472,882


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	58,225,817		$	40,887,578

See notes to consolidated financial statements.

F-4

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations


	For the Year Ended
	December 31,
	2011			2010
REVENUES	$	14,721,233		$	6,099,953

COSTS AND EXPENSES

Production costs		4,051,496			2,217,360
Depreciation, depletion, amortization and accretion		5,565,679			3,086,531
Impairment of oil and gas properties		1,288,049			216,430
Selling, general and administrative		5,673,939			3,895,079


Total Costs and Expenses		16,579,163			9,415,400

Gain on sale of assets		12,627,896			24,791,029


INCOME FROM OPERATIONS		10,769,966			21,475,582


OTHER INCOME (EXPENSES)

Interest income		1,043			14,452
Interest expense		(1,679,276	)		(3,232,226	)
Gain on derivative contracts		48,943			118,042


Total Other Income (Expenses)		(1,629,290	)		(3,099,732	)


NET INCOME BEFORE INCOME TAXES		9,140,676			18,375,850

INCOME TAX		214,000			450,000


NET INCOME	$	8,926,676		$	17,925,850


EARNINGS PER SHARE – BASIC	$	0.70		$	1.44

EARNINGS PER SHARE – DILUTED	$	0.66		$	1.40

WEIGHTED AVERAGE SHARES OUTSTANDING – BASIC		12,807,964			12,426,252

WEIGHTED AVERAGE SHARES OUTSTANDING – DILUTED		13,552,221			12,837,551

See notes to consolidated financial statements.

F-5

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity

For the years ended December 31, 2011 and 2010


					Additional
	Common Stock				Paid in		Treasury			Accumulated
	Shares		Amount		Capital		Stock			Deficit			Total
Balance, December 31, 2009		11,628,027	$	11,628	$	36,734,675	$	(1,950	)	$	(38,720,095	)	$	(1,975,742	)

Stock issued for note conversion		890,551		891		577,967		—			—			578,858

Shares issued for services		218,750		218		499,636		—			—			499,854

Stock Option Compensation expense		—		—		444,062		—			—			444,062

Net income		—		—		—		—			17,925,850			17,925,850


Balance, December 31, 2010		12,737,328		12,737		38,256,340		(1,950	)		(20,794,245	)		17,472,882

Issuance of common stock		60,000		60		68,940		—			—			69,000

Shares issued for services		184,500		185		506,916		—			—			507,101

Stock Option Compensation expense		—		—		467,998		—			—			467,998

Net income		—		—		—		—			8,926,676			8,926,676


Balance, December 31, 2011		12,981,828	$	12,982	$	39,300,194	$	(1,950	)	$	(11,867,569	)	$	27,443,657

See notes to consolidated financial statements.

F-6

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows


	For the Year Ended
	December 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	8,926,676		$	17,925,850
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Depreciation, depletion, amortization, and accretion		5,565,679			3,086,511
Impairment of oil and gas properties		1,288,049			216,430
Amortization of financing cost and debt discount		712,500			251,090
Share-based compensation		975,099			943,916
Gain on sale of assets and oil and gas properties		(12,627,896	)		(24,791,029	)
Unrealized loss on derivative contracts		187,590			207,076
Interest expense added to principal		1,245,698			539,835
Changes in operating assets and liabilities:
Accounts receivable, trade		(879,592	)		174,770
Accounts receivable due from non-operator, net		(1,671,056	)		604,551
Advance royalties and other assets		(14,718	)		(3,854	)
Prepaid drilling costs		752,548			(825,646	)
Accounts payable and accrued expenses		11,798,817			491,519
Revenue payable		451,825			—
Income tax payable		(179,292	)		450,000


Net cash provided (used) by operating activities		16,531,927			(728,961	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Collections on note receivable		27,295			316,298
Proceeds from sale of assets		13,785,812			23,508,044
Expenditures for oil and gas properties		(17,531,269	)		(11,435,045	)
Expenditures for property and equipment		(130,252	)		(213,593	)


Net cash (used) provided by investing activities		(3,848,414	)		12,175,704


CASH FLOWS FROM FINANCING ACTIVITIES:
Financing Fees		(850,000	)		—
Issuance common stock		69,000			—
Proceeds from notes payable		—			76,215
Payments on notes payable		(5,054,802	)		(15,087,187	)


Net cash used by financing activities		(5,835,802	)		(15,010,972	)


NET CHANGE IN CASH		6,847,711			(3,564,229	)
CASH, BEGINNING OF YEAR		1,037,941			4,602,170


CASH, END OF YEAR	$	7,885,652		$	1,037,941

See notes to consolidated financial statements.

F-7

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows


SUPPLEMENTAL DISCLOSURES FOR CASH FLOW INFORMATION

CASH PAID FOR:
Interest	$	434,056	$	2,517,839
Income Taxes	$	212,272	$	—


Non-cash investing and financing activities
Accrued expenditures for oil and gas properties	$	1,235,881	$	2,477,868

Conversion of related party debt to common stock	$	—	$	578,858

Increase in asset retirement obligation	$	16,229	$	4,637
Increase in note payable for oil and gas property purchase	$	—	$	1,780,404
Reclass from accrued expense to notes payable	$	725,000	$	—
Accrued expenditures for debt refinancing	$	350,000	$	—
Interest added to loan	$	1,245,696	$	539,835
Purchase of oil and gas properties with drilling credit	$	—	$	3,459,448

See notes to consolidated financial statements.

F-8

TRANS ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Organization

Trans Energy is an independent energy company engaged in the acquisition, exploration, development, exploitation and production of oil and natural gas. Its operations are presently focused in the State of West Virginia.

Principles of Consolidation

The consolidated financial statements include Trans Energy and its wholly-owned subsidiaries, Prima Oil Company, Inc., Ritchie County Gathering Systems, Inc., Tyler Construction Company, Inc, and Tyler Energy, Inc., and interest with joint venture partners, which are accounted for under the proportioned consolidation method. All significant inter-company balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company’s financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion, amortization, and impairment of oil and gas properties and timing and costs associated with its asset retirement obligations. Reserve estimates are by their nature inherently imprecise.

Cash

Financial instruments that potentially subject the Company to a concentration of credit risk include cash. At times, amounts may exceed federally insured limits and may exceed reported balances due to outstanding checks. Management does not believe it is exposed to any significant credit risk on cash.

Receivables

Accounts receivable and notes receivable are carried at their expected net realizable value. The allowance for doubtful accounts is based on management’s assessment of the collectability of specific customer accounts and the aging of the accounts receivables. If there were a deterioration of a major customer’s creditworthiness, or actual defaults were higher than historical experience, estimates of the recoverability of the amounts due could be overstated, which could have a negative impact on operations. No allowance for doubtful accounts is deemed necessary at December 31, 2011 and December 31, 2010 by management and no bad debt expense was incurred during the years ended December 31, 2011 and 2010.

F-9

Property and Equipment

Property and equipment are recorded at cost. Depreciation on vehicles, machinery and equipment is computed using the straight-line method over expected useful lives of three to ten years. Depreciation on buildings is computed using the straight-line method over an expected useful life of 39 years. Additions are capitalized and maintenance and repairs are charged to expense as incurred.

Oil and Gas Properties

Trans Energy uses the successful efforts method of accounting for oil and gas producing activities. Under the successful efforts method, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells and asset retirement costs are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized based on Trans Energy’s experience of successful drilling and average holding period. Capitalized costs of producing oil and gas properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are depreciated and depleted by the unit-of-production method. Depreciation on pipelines and related equipment, including compressors, is computed using the straight-line method over the expected useful lives of fifteen to twenty-five years.

On the sale or retirement of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually.

If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Long-Lived Assets

Generally accepted accounting principles require that long- lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicated that the carrying amount of an asset may not be recoverable. The Company, at least annually, reviews its proved oil and gas properties for impairment by comparing the carrying value of its properties to the properties’ undiscounted estimated future net cash flows. Estimates of future oil and gas prices, operating costs, and production are utilized in determining undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company’s independent reserve engineer’s estimate of proved reserves, which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties. The Company determines fair market value using the income approach based on the properties’ discounted estimated future net cash flows, which is considered to be a level 3 input. The Company wrote down oil and gas properties by $1,288,049 in 2011 due to a sharper decline than anticipated. In 2010, if wrote down oil and gas properties by $61,180 and unproved lease costs by $155,250.

F-10

Derivatives

Derivative financial instruments, utilized to manage or reduce commodity price risk related to Trans Energy’s production, are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income or loss and are recognized in the statement of operations when the hedged item affects earnings. If the derivative is not designated as a hedge, changes in the fair value are recognized in other expense. Ineffective portions of changes in the fair value of cash flow hedges are also recognized in loss on derivative liabilities.

Notes Payable

Trans Energy records notes payable at fair value and recognizes interest expense for accrued interest payable under the terms of the agreements. Principal and interest payments due within one year are classified as current, whereas principal and interest payments for periods beyond one year are classified as long term.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include dismantlement, plugging and abandonment of oil and gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset.

The following is a description of the changes to Trans Energy’s asset retirement obligations for the twelve months ended December 31:


	2011		2010
Asset retirement obligations at beginning of period	$	219,478	$	202,366
Liabilities incurred during the period		16,229		4,637
Accretion expense		20,944		17,076
Liabilities settled		—		(4,601	)


Asset retirement obligations at end of period	$	256,651	$	219,478

At December 31, 2011 and 2010, the Company’s current portion of the asset retirement obligation was $0.

Income Taxes

At December 31, 2011, the Company had net operating loss carry forwards (NOLs) for future years of approximately $6.2 million. These NOLS will expire at various dates through 2030. The current tax provision of $214,000 and $450,000 for the years ended December 31, 2011 and 2010, respectively, is an estimate of the alternative minimum tax that will not be offset by the NOLs. No tax benefit has been recorded in the consolidated financial statements for the remaining NOLs or AMT credit since the potential tax benefit is offset by a valuation allowance of the same amount. Utilization of the NOLs could be limited if there is a substantial change in ownership of the Company and is contingent on future earnings.

The Company has provided a valuation allowance equal to 100% of the total net deferred asset in recognition of the uncertainty regarding the ultimate amount of the net deferred tax asset that will be realized.

F-11

The Company has no material unrecognized tax benefits. No tax penalties or interest expense were accrued as of December 31, 2011 or 2010 or paid during the periods then ended. Trans Energy files tax returns in the United States and states in which it has operations and is subject to taxation. Tax years subsequent to 2007 remain open to examination by U.S. federal and state tax jurisdictions, however prior year net operating losses remain open for examination.

Commitments and Contingencies

The Company operated exclusively in the United States, entirely in West Virginia, in the business of oil and gas acquisition, exploration, development, exploitation, and production. The Company operates in an environment with many financial risks, including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, the volatility and seasonality of oil and gas production and prices, and the highly competitive and, at times, seasonal nature of the industry and worldwide economic conditions. The Company’s ability to expand its reserve base and diversify its operations is also dependent upon the Company’s ability to obtain the necessary capital though operating cash flow, borrowings or equity offerings. Various federal, state, and local governmental agencies are considering, and some have adopted, laws and regulations regarding environmental protection which could adversely affect the proposed business activities of the Company. The Company cannot predict what effect, if any, current and future regulations may have on the results of operations of the Company. See Note 10 for gas purchase contract information.

Revenue and Cost Recognition

Trans Energy recognizes gas revenues upon delivery of the gas to the customers’ pipeline from Trans Energy’s pipelines when recorded as received by the customers’ meter. Trans Energy recognizes oil revenues when pumped and metered by the customer. Trans Energy recognized $14,293,883 and $5,681,679 in oil and gas revenues in 2011 and 2010, respectively. Trans Energy uses the sales method to account for sales and imbalances of natural gas. Under this method, revenues are recognized based on actual volumes sold to purchasers. The volumes sold may differ from the volumes to which Trans Energy is entitled based on our interest in the properties. These differences create imbalances which are recognized as a liability only when the imbalance exceeds the estimate of remaining reserves. Trans Energy had no material imbalances as of December 31, 2011 and December 31, 2010. Costs associated with production are expensed in the period incurred.

Revenue payable represents cash received but not yet distributed to third parties.

Transportation revenue is recognized at the time it is earned and we have a contractual right to receive payment. We recognized $360,358 and $336,463 of transportation revenue in 2011 and 2010, respectively.

Share-Based Compensation

Trans Energy estimates the fair value of each stock option award at the grant date by using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We have utilized historical data and analyzed current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of the grant.

F-12

We recognize share-based compensation expense on a straight-line basis over the requisite service period for the entire award. Compensation expense related to options granted was $467,998 and $444,062 for the years ended December 31, 2011 and 2010, respectively. Compensation expense related to stock awarded was $507,101 and $499,804 for the years ended December 31, 2011 and 2010, respectively.

Earnings per Share of Common Stock

Basic earnings per share are calculated based on the weighted average number of shares of common stock outstanding during each period. Diluted income per share assumes issuance of stock compensation awards, provided the effect is not anti-dilutive. Certain stock options were dilutive for 2011 and 2010. For the years ended December 31, 2011 and 2010, assumed exercise of stock options had the effect of adding 744,257 and 411,299 shares to the denominator.

Dilutive options that are issued during a period or that expire or are canceled during a period are reflected in the computations for the time they were outstanding during the periods being reported.


	For the Years Ended
	December 31,
	2011		2010
Numerator:
Net income (loss) applicable to common shareholders	$	8,926,676	$	17,925,850


Denominator:
Weighted average shares - basic		12,807,964		12,426,252


Weighted average shares - diluted		13,552,221		12,837,551


Total earnings per share - basic	$	0.70	$	1.44


Total earnings per share - diluted	$	0.66	$	1.40

Fair Value of Financial Instruments

The Financial Accounting Standards Board (“FASB”) established a framework for measuring fair value and expands disclosures about fair value measurements by establishing a fair value hierarchy that prioritizes the inputs and defines valuation techniques used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs and lowest priority to Level 3 inputs. The three levels of the fair value hierarchy are described below:

Basis of Fair Value Measurement

Level 1

Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2

Inputs reflect quoted prices for identical assets or liabilities in markets that are not active; quoted prices for similar assets or liabilities in active markets; inputs other than quoted prices that are observable for the asset or the liability; or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3

Unobservable inputs reflecting the Company’s own assumptions incorporated in valuation techniques used to determine fair value. These assumptions are required to be consistent with market participant assumptions that are reasonably available.

F-13

Trans Energy believes that the fair value of its financial instruments comprising cash, certificate of deposit, accounts receivable, note receivable, accounts payable and notes payable approximate their carrying amounts. The interest rates payable by Trans Energy on its note payable approximate market rates. The fair value of Trans Energy’s level 2 financial assets consist of derivative assets, which are based on quoted commodity prices of the underlying commodity market approach. The following tables summarize fair value measurement information for Trans Energy financial assets.

As of December 31, 2011

Fair Value Measurements Using:

Carrying
Amount

Total
Fair Value

Quoted
Prices
In Active
Markets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Financial Assets:

Derivative Assets

—


	As of December 31, 2010
					Fair Value Measurements Using:
	Carrying Amount		Total Fair Value		Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Financial Assets:
Derivative Assets	$	187,590	$	187,590	$	—	$	187,590	$	—

New Accounting Standards

Accounting Standards Update No. 2010-20 “Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses” (“ASU No. 2010-20”)

In July 2010, the FASB issued ASU 2010-20. ASU 2010-20 amends disclosure requirements with respect to the credit quality of financing receivables and the related allowance for credit losses. Entities will be required to disaggregate by portfolio segment or class certain existing disclosures and provide certain new disclosures about its financing receivables and related allowance for credit losses. The disclosures will be effective for financial statements issued for fiscal years ending on or after December 15, 2010. Since ASU 2010-20 only amended disclosure requirements, not current accounting practice, this did not have any impact on the Company’s balance sheets, statements of income or statements of cash flows.

F-14

Trans Energy reviewed all other recently issued, but not yet effective, accounting pronouncements and does not believe any such pronouncement will have a material impact on the financial statements.

NOTE 2 - GOING CONCERN

Trans Energy’s consolidated financial statements are prepared using United States generally accepted accounting principles applicable to a going concern which contemplates the realization of assets and liquidation of liabilities in the normal course of business. Trans Energy has incurred cumulative operating losses through December 31, 2011 of $11,867,569 and has a working capital deficit at December 31, 2011 of $18,362,177, including its note payable.

Revenues have not been sufficient to cover its operating costs and interest expense to allow it to continue as a going concern. The potential proceeds from the sale of common stock, sale of drilling programs, and other contemplated debt and equity financing, and increases in operating revenues from new development and business acquisitions would enable Trans Energy to continue as a going concern. There can be no assurance that Trans Energy can or will be able to complete any debt or equity financing to fund operations in the future. Trans Energy’s consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

NOTE 3 - NOTE RECEIVABLE

Trans Energy held a promissory note agreement with Warren Drilling Co., Inc, an Ohio Corporation. The purpose of the promissory note was to fund certain drilling equipment necessary to equip the rig for horizontal drilling. An initial advance in the amount of $302,280 was made on December 22, 2008, with a second advance in the amount of $311,440 made on February 4, 2009. The note bears interest in the amount of 6.5% per annum, payable in monthly installments of $27,443 for 24 months. As of December 31, 2011 and 2010, the outstanding balance was $-0- and $27,295, respectively. The note was secured by equipment of Warren Drilling Co., for which an executed security agreement was filed with the promissory note. Trans Energy has evaluated their relationship with Warren Drilling and has determined that Trans Energy does not have a controlling financial interest in Warren Drilling which would require consolidation.

NOTE 4 - ACCOUNTS RECEIVABLE DUE FROM NON-OPERATORS

Trans Energy is the drilling operator for wells drilled on behalf of other companies in which Trans Energy owns a working interest. Due to timing of drilling charges and collections from the other companies, Trans Energy could have a net receivable or liability from non operators. Trans Energy was owed by third parties for drilling cost to be reimbursed in the amt of 1,754,020 and 82,964 as of December 31, 2011 and 2010.

F-15

NOTE 5 - PROPERTY AND EQUIPMENT

At December 31, 2011 and 2010, property and equipment consisted of:


	2011			2010
Buildings	$	175,000		$	175,000
Vehicles		404,557			439,030
Machinery and equipment		593,741			586,160
Roadways		53,969			53,969
Furniture and fixtures		195,521			85,666
Leasehold improvements		37,771			37,771
Land		382,951			382,951
Accumulated depreciation		(762,132	)		(612,047	)


Total fixed assets	$	1,081,378		$	1,148,500

Total additions for property, plant and equipment for the years ended December 31, 2011 and 2010 were $130,252 and $213,593, respectively. Depreciation, depletion and amortization expenses for property and equipment were $197,374 and $191,514 for the years ended December 31, 2011 and 2010, respectively.

NOTE 6 - OIL AND GAS PROPERTIES

Total additions for oil and gas properties for the year ended December 31, 2011 and 2010 were $16,265,545 and $19,161,765, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $5,347,361 and $2,877,941 for the years ended December 31, 2011 and 2010, respectively.

NOTE 7 - SALE OF OIL AND GAS ACREAGE

On March 31, 2011, the Company sold 2,950 net acres to Republic Energy Ventures, LLC (“Republic”) at $4,750 per net acre for total pretax proceeds of $13,767,281. Acreage sold to Republic was distributed across the Company’s undeveloped acreage. Proceeds from this transaction were used to repay $5 million to CIT in April, with the remainder being used to partially fund the drilling and completion expenses for certain wells.

On July 16, 2010, Trans Energy expanded its joint venture with Republic Energy Ventures, LLC into Marion and Tyler Counties in West Virginia, building upon its already successful operating areas in Wetzel and Marshall Counties.

As part of this expansion, the Company sold to Republic a 50% interest in certain Marion County, West Virginia acreage. The total acreage consists of 2,539.25 acres, of which 284 acres are subject to pooling provisions, and 2,545.25 acres of undeveloped leases and 189.56 acres of other mineral leases. For the 50% interest, Republic paid the Company $5,500 per net acre. Republic required that all the Marion leases have pooling provision included, but because it was not possible to secure the necessary pooling amendments prior to the closing, Republic withheld 20% of the proceeds of the sale until the pooling provisions are secured. Accordingly, the total purchase price paid by Republic, less the 20% holdback, was $13,263,284.

The Company also sold to Republic a 50% interest in 2,613.28 acres located in Tyler County for $4,000 per net acre. Republic also withheld 20% of the purchase price on 1,325.97 acres not subject to pooling provisions to ensure that pooling provisions will be added to the leases. The total purchase price paid by Republic, less the 20% holdback, was $4,696,164.

In addition, Republic purchased all overriding royalty interests previously reserved by the Company in a prior assignment of leasehold working interests in Wetzel County, West Virginia under a Farm-Out and Area of Joint Development Agreement with Republic entered in April 2007. The purchase price paid by Republic was $9,000,000. As a result of this transaction, both the Company and Republic now have the same net revenue interest in the Wetzel County property.

F-16

Finally, the Company assigned to Republic, certain production purchase or sale agreements, net profits agreements, farm out agreements, operating agreements, pooling and other agreements relating to properties being sold. Republic also received an undivided 50% interest in all of the Company’s surface interests, rights-of-way, easements, leases, permits, licenses and other similar rights and interests in connection with the properties being sold.

The total purchase price for the above properties was $26,959,448. Republic paid to the Company $23,500,000 in cash and the balance of $3,459,448 was deemed a drilling credit. The Company applied $15,000,000 of the cash proceeds to reduce its credit facility with CIT Capital USA Inc. (See Note 9 for additional discussion) and retained approximately $5,000,000. Any receipt of Republic’s 20% holdback for the leases will be recognized as gain at that time.

The balance of the proceeds of $3,500,000 was used to satisfy a certain option agreement with Sancho Oil and Gas Corporation. Previously, the Company acquired an option to purchase from Sancho 2,613.28 net acres located in Tyler County, West Virginia. Under the terms of the Agreement, Republic agreed to pay to Sancho $3,500,000 to acquire the acreage and satisfy the option. Loren E. Bagley, a director of the Company, is the President of Sancho Oil & Gas.

NOTE 8 - PROVISION FOR TAXES

The Company’s income tax provision is as follows:


	2011			2010
Current:	$	214,000		$	450,000

Deferred:
Change in Depreciation, depletion and amortization	$	(1,645,000	)	$	(816,000	)

Change in other items		49,000			(390,000	)
Reduction of NOL		2,478,000			11,054,000
Increase in AMT credit		(214,000	)		(450,000	)
Change in valuation allowance		(668,000	)		(9,398,000	)


Total	$	214,000		$	450,000

The income tax provisions of $214,000 for 2011 and $450,000 for 2010 represent a current tax that is for the alternative minimum tax (AMT) that will not be offset by the NOL, but will create a deferred tax credit carried forward indefinitely. The income tax provision differs from the amount of income tax determined by applying the U.S. federal and state income tax rates to pretax income from continuing operations for the years ended December 31, 2011 and 2010 primarily due to the utilization of NOL carryforwards, expense related to stock and options issued for services, intangible drilling costs, availability of AMT credit carryforward, and the valuation allowance.

At December 31, 2011, Trans Energy had net operating loss carryforwards of approximately $6.2 million that may be offset against future taxable income from 2012 through 2030. No deferred tax benefit has been reported in the December 31, 2011 and 2010 consolidated financial statements since the potential tax benefit is offset by a valuation allowance of the same amount.

F-17

Due to the change in ownership provisions of the Tax Reform Act of 1986, net operating loss carryforwards for Federal income tax reporting purposes are subject to annual limitations. Should a change in ownership occur, net operating loss carryforwards may be limited as to use in future years.

Net deferred tax assets and liabilities consist of the following components as of December 31, 2011 and 2010:


	2011			2010
Deferred tax assets:
NOL carryover	$	2,118,000		$	4,596,000
AMT Credit		664,000			450,000
Unrealized loss on derivative contract		—			63,000
Other		113,000			99,000


Total deferred tax assets		2,895,000			5,208,000

Deferred tax liabilities:
Depreciation, depletion and amortization		(2,289,000	)		(3,934,000	)


Total deferred tax liabilities		(2,289,000	)		(3,934,000	)

Valuation allowance		(606,000	)		(1,274,000	)


Net deferred taxes	$	—		$	—

NOTE 9 - NOTES PAYABLE

On June 22, 2007, Trans Energy finalized a financing agreement with CIT Capital USA Inc. (“CIT”) Under the terms of the agreement, CIT would lend up to $18,000,000 to Trans Energy in the form of a senior secured revolving credit facility with the ability to increase the credit facility to $30,000,000 with increased oil and gas reserves. During the quarter ended September 30, 2008, CIT increased the credit facility to $30,000,000 due to increased reserves.

During the year ended December 31, 2009, Trans Energy borrowed $2,000,000 from CIT which increased the total outstanding credit balance to $30,000,000, leaving no available credit facility.

Interest payment due dates are elected at the time of borrowing and range from monthly to six months. Principal payments were due at maturity on June 15, 2010 for all borrowings outstanding on that date.

The Company has been working with its financial advisor and investment banker in an effort to restructure the credit agreement since its maturity date. In July 2010, the Company repaid $15,000,000 from its proceeds of certain assets. Then the Company repurchased its net profits interest from CIT with the $1,780,404 purchase price added to the outstanding balance. Between June and December 2010, the Company was charged $725,000 in forbearance fees by CIT, to be paid in cash or five year warrants. Warrants for 142,715 shares were originally issued with a fair value of $310,444 related to $375,000 of fees. The warrants were cancelled and the entire balance of $725,000 was added to the principal balance of the new credit agreement signed in 2011. The $725,000 of forbearance fees are included in accounts payable at December 31, 2010. The specifics of these activities are as follows.

On June 15, 2010 the Company received a written notice of maturity / reservation of rights from CIT with respect to the Company’s credit agreement in the form of a senior secured revolving credit facility. The credit facility matured on June 15, 2010 and CIT advised the Company that no further loans will be made under the agreement and that all indebtedness under the agreement is due and payable.

F-18

On June 18, 2010, CIT and the Company executed a forbearance letter agreement whereby CIT rescinded its June 15, 2010 notice of maturity. CIT agreed to forebear from exercising its rights and remedies against the Company and its property until June 25, 2010. The forbearance is subject to the conditions that the Company engages a financial restructuring consultant, reasonably acceptable to CIT, and pays to CIT an initial forbearance fee of $150,000 on or before June 25, 2010.

On June 18, 2010, the Company entered into an agreement with Oppenheimer & Co. Inc. whereby Oppenheimer will act as the Company’s financial advisor and investment banker to assist in a possible restructuring plan and/or refinancing of the CIT credit agreement. On June 25, 2010, CIT and the Company executed a second forbearance agreement that extended the forbearance until July 2, 2010 and postpones the initial forbearance fee for one week. Under the extended forbearance agreement, the Company is obligated to pay the initial forbearance fee and an additional forbearance fee of $50,000 on or before July 2, 2010. The extended forbearance agreement expressly reserves CIT’s right to exercise any and all rights and remedies available to it under the credit agreement. If the Company is unable to restructure the credit agreement or arrange for alternative financing, the agreement will be in default and the principal amount and accrued interest and fees would become immediately due.

On July 9, 2010, the Company and CIT entered into a forbearance letter agreement (the “July Forbearance Letter”) whereby CIT agreed to forebear from exercising its rights and remedies against the Company and its property until October 29, 2010. The July Forbearance Letter provides as follows: 1) The Company must submit to CIT an operating budget on a weekly basis and conduct bi-weekly status calls with CIT to review its operating budget and discuss any variances therefrom; 2) The Company must provide CIT with an updated monthly budget for calendar year 2010 on or before July 15, 2010 and an updated reserve report by July 31, 2010; 3) All outstanding forbearance fees, including outstanding delinquency charges payable pursuant to the forbearance letters of June 18, 2010 and June 25, 2010 and an additional delinquency charge of $100,000, are payable on the earlier of (i) July 31, 2010 or (ii) upon the closing of the sale of certain assets by the Company. At the election of CIT, the forbearance fees are payable in either cash or five-year warrants to purchase shares of the Company’s common stock; 4) The Company shall retain Oppenheimer & Co. Inc. as its restructuring advisor during the forbearance period; 5) If the Company sells assets, it shall be permitted to retain the first $5 million of cash proceeds and all additional amounts realized would be applied to the outstanding debt to CIT; 6) If any portion of the debt remains outstanding, the Company will be obligated to pay an additional forbearance fee of $150,000 on September 15, 2010 and $150,000 on October 29, 2010, payable in either cash or five-year warrants to purchase shares of the Company’s common stock; 7) The outstanding debt will continue to accrue interest until paid. The aggregate indebtedness, including accrued interest, fees and expenses, was $32,320,239.

On July 16, 2010, Trans Energy expanded its joint venture with Republic Energy Ventures, LLC into Marion and Tyler counties in West Virginia, building upon its already successful operating areas in Wetzel and Marshall counties. As part of this expansion, the Company sold Republic a 50% working interest in approximately 5,000 net acres in Marion County and approximately 2,600 net acres in Tyler County and a small overriding royalty position on over 6,000 net acres in Wetzel County for cash proceeds of $23,500,000 and drilling credits of approximately $3,500,000. The Company repaid $15,000,000 on its senior credit facility and retained $5,000,000 for working capital to develop its position in the Marcellus shale and for general corporate purposes. The remaining $3,500,000 was paid to Sancho Oil & Gas Corporation (“Sancho”) to satisfy the Company’s option to purchase approximately 2,600 acres in Tyler County, West Virginia. Loren E. Bagley, a director of the Company, is the President of Sancho.

F-19

On July 16, 2010, in order to settle the forbearance fees with CIT, the Company issued a warrant to CIT to purchase up to 96,138 shares of the Company’s common stock at $3.12 per share. The warrant is immediately exercisable.

On September 15, 2010, in order to settle the forbearance fees with CIT, the Company issued a warrant to CIT to purchase up to 46,577 shares of the Company’s common stock at $3.22 per share. The warrant is immediately exercisable.

On October 29, 2010, the Company and CIT entered into a forbearance letter agreement (the “October Forbearance Letter”), whereby CIT agreed to forebear from exercising its rights and remedies against the Company and its property until December 31, 2010. The October Forbearance Letter extends the terms and provisions of the earlier forbearance agreement between the parties entered into on July 9, 2010 (the “July Forbearance Letter”) that extended the forbearance period to October 29, 2010.

In addition, the October Forbearance Letter requires the Company to pay CIT a deferral fee of $50,000 on November 15, 2010, November 30, 2010, December 15, 2010 and December 31, 2010 if, on any such date, any of the principal of and interest on the Credit Agreement have not been repaid in full. In the event the Company enters into a firm commitment for financing with a third party to repay the debt under the Credit Agreement, each deferral fee not then due will be reduced to $25,000. Any deferral fee paid prior to receiving such firm commitment for financing will not be reduced retroactively. At the option of CIT, each deferral fee is payable in either cash or five-year warrants to purchase shares of the Company’s common stock. The Company did enter into a firm commitment for financing reducing the November and December forbearance fees to a total of $125,000. However, the financing was not executed.

On March 31, 2011, the Company and CIT entered into the Sixth Amendment to Credit Agreement. The Sixth Amendment and other related agreements extend the maturity date of the Credit Agreement to March 31, 2012. The Sixth Amendment confirms that the principal amount due under the Credit Agreement prior to the application of a portion of the proceeds from the acreage sale to Republic under the March 31, 2011 Purchase and Sale Agreement (the “PSA”) was $17,320,239, plus accrued interest of $139,748, plus past delinquency charges. The Sixth Amendment provides that all past delinquency charges owed by the Company, whether in shares of Company stock (or options or warrants therefore) or to be paid in cash, are unwound and the delinquency charges of $725,000 are to be added to the principal balance plus interest. Thus, the total amount owed under the Credit Agreement, as per the Sixth Amendment, was $18,184,978, which was reduced to $13,184,978 upon the payment from the PSA.

After the payment of accrued interest and a principal payment of $5,000,000 on April 2, 2011 and the accrued interest of $1,245,697 for the period April 1, 2011 thru December 31, 2011 being added to the loan, the Company owed $14,290,936 as of December 31, 2011, with interest at 12%.

As part of the Sixth Amendment, the Company also granted to CIT a 1.5% overriding royalty interest in each of the Stout #2H, Groves #1H, Keaton #1H and Lucey #1H wells, as well as a 1.5% overriding royalty interest in the next six horizontal wells drilled in the Marcellus Shale, which have commercial production for a period of at least 30 consecutive days and in which the Company, or any of its subsidiaries, has an interest. Each 1.5% overriding royalty interest is to be proportionately reduced to the extent the Company or its subsidiary owns less than the full working interest in the leases, or to the extent such oil and gas leases cover less than the full mineral interest.

As of December 31, 2011 and December 31, 2010, the Company owed $23,255 and $78,058, respectively, for other loans, primarily for vehicles.

The Company issued a Convertible Promissory Note to Republic dated February 21, 2011 in the amount of $2,914,442. As of December 31, 2011, the balance of the note was $-0-.

F-20

On February 29, 2012, the Company’s subsidiary, American Shale Development, Inc., entered into a credit agreement, whereby, subject to the satisfaction of certain conditions to funding, certain lenders have committed to provide up to $50 million in funding to be used to refinance certain outstanding indebtedness of Trans Energy as well as to fund drilling and completion costs. See Note 17 Subsequent Events for additional detail.

NOTE 10 - DERIVATIVE AND HEDGING FINANCIAL INSTRUMENTS

Effective July 13, 2007, as required by the CIT Creditor Agreement, Trans Energy purchased a commodity put option for $310,000 in cash. The terms of the option establish a floor price of $7.35/MMBTU, Settlement Date Henry Hub price of Natural Gas as quoted by the NYMEX, for volumes ranging from 8,241 MMBTU per month to 5,244 MMBTU per month, beginning settlement on August 2, 2007 and ending settlement on December 1, 2011. This put option places no limit on the upside price for Trans Energy’s gas production. If the monthly closing price of Henry Hub gas index is below the floor price then Trans Energy receives proceeds equal to the difference between the floor price and the closing price. The cost of the put option and proceeds, if any, as well as changes in the fair market value of the put options, are charged to other income (expense) as gain (loss) on derivative instruments. In addition on May 22, 2008, Trans Energy entered into a participating commodity put and call option on oil as a costless collar.

Trans Energy entered into these derivative commodity contracts to provide a measure of stability in the cash flows associated with Trans Energy’s oil and gas production and to manage exposure to commodity price fluctuations. Trans Energy does not designate its derivative financial instruments as hedging instruments for financial accounting purposes, and as a result, recognizes the change in the respective instruments’ fair value in earnings. Trans Energy recorded an unrealized loss of $187,590 and $207,076 for the years ended December 31, 2011 and 2010, respectively. Trans Energy received proceeds of $236,533 and $325,118 relating to settlements of its derivative instruments for the years ended December 31, 2011 and 2010, respectively.

These natural gas and oil derivative contracts were completed as of December 31, 2011.

Gas Purchase Agreements

Trans Energy has various agreements with Dominion Field Services, Inc. for fixed prices for gas transported through its pipeline. The monthly volume ranges from 10,000 to 20,000 decatherm (“Dth”) per month, and fixed prices vary from $6.11 to $10.81/Dth through April 2012. A decatherm is equal to one MMBTU.

NOTE 11 - STOCKHOLDERS’ EQUITY

Preferred Stock - Trans Energy has authorized 10,000,000 shares of $.001 par value preferred stock. The preferred stock shall have preference as to dividends and to liquidation of Trans Energy.

Common Stock - Trans Energy has authorized 500,000,000 shares of $.001 par value common stock.

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On April 8, 2009, Trans Energy granted 375,000 common stock options to four key employees under the long term incentive bonus program. These options are being amortized to share-based compensation expense quarterly over the vesting period, for which $70,534 of the share-based compensation expense was recorded during the three month period ended March 31, 2010. As of March 31, 2010, these options have been fully expensed. 50,000 of the options were exercised in June 2011.

On May 14, 2009, Trans Energy granted 50,000 shares of common stock and 50,000 common stock options to one key employee under the long term incentive bonus program. The 50,000 shares are not performance based and vest quarterly over one year, subject to ongoing employment. These shares were valued at $57,500 using the fair market value of the common stock at the date of grant and will be amortized to compensation expense quarterly over one year. During the year ended December 31, 2010, Trans Energy recorded $14,375 of share-based compensation related to these shares. As of March 31, 2010, this award has been fully expensed. These options are being amortized to share-based compensation expense quarterly over the vesting period, for which $9,405 of share-based compensation expense was recorded during the year ended December 31, 2010. These options have been fully expensed in 2010.

On October 6, 2009, our Board of Directors approved a plan to satisfy an immediate cash need of $1,250,000 to settle a disputed invoice for drilling services. The invoice had been held without payment for several months due to a dispute over its amount. Management negotiated a settlement at what it considered a reasonable level and less than the amount previously accrued on October 8, 2009. In order to raise the necessary funds to immediately settle the dispute, the company sold for $321,192 an interest in five shallow wells, which management determined to be non-strategic to the company, to Sancho Oil & Gas Corporation that is principally owned by Loren E. Bagley, a director. In addition, three members of the Board of Directors extended 60-day bridge loans to the company in the aggregate amount of $928,858, evidenced by three secured convertible promissory notes.

The promissory notes, payable on demand, were issued to James K. Abcouwer ($350,000), Robert L. Richards ($100,000), and Loren E. Bagley in the name of Sancho Oil & Gas ($478,858). Each note was secured by shares of the Company’s common stock equal to the value of the principle of the note based on the price of $0.65 per share. Interest on each note would be paid at the rate of 1.5% per month if the note were not paid within five days of demand. Each note is also convertible into shares of the Company’s common stock, commencing 30 days after issuance, entitling the holder to convert the note into shares of the Company’s common stock at the conversion price of $0.65 per share, based on the closing price of $0.60 for the Company’s shares in the public market on the date the notes were issued. As provided by the terms of the promissory notes, Mr. Abcouwer converted his note for 538,462 shares of common stock on December 30, 2009, Mr. Richards converted his note for 153,846 shares on January 29, 2010 and Sancho Oil & Gas converted its note for 736,705 shares on February 16, 2010.

On June 23, 2010, Trans Energy issued 125,000 shares to one officer under an employment agreement. These shares vested immediately and were valued at $343,750.

On June 23, 2010, Trans Energy granted 125,000 common stock options to one officer under an employment agreement. These options vested immediately and were valued at $237,488. The stock options were granted at an exercise price of $2.75 per common share, which was equal to the fair market value of the common stock at the date of the grant. The following are the assumptions made in computing the option fair value:


Average risk-free interest rate	1.0	%
Dividend yield	0	%
Expected term	5 years
Average expected volatility	89.46	%

F-22

In December 2010, Trans Energy issued 8,500 shares of common stock for employee bonuses valued at $24,480. These shares vested immediately and were expensed in 2010.

In December 2010, Trans Energy issued 50,000 shares of common stock to outside board members valued at $49,000. These shares vested immediately and were expensed in 2010.

In December 2010, Trans Energy granted 136,500 shares of common stock to nine employees under the long-term incentive bonus program. The 136,500 shares are not performance based and vest semi-annually over three years, subject to ongoing employment. These shares were valued at $409,500 using the fair market value of the common stock at the date of grant and will be amortized to compensation expense semi-annually over three years. During 2011 and 2010, we recorded $100,500 and $68,250, respectively, of share-based compensation expense related to these shares.

In December 2010, Trans Energy granted 368,000 common stock options to nine employees and one outside board member. These options vest semi-annually over three years and have a five year term. These stock options were granted at an exercise price of $3.00 per common share, which was equal to the fair market value of the common stock at the date of grant and were valued using the Black Scholes valuation model. The options are being amortized to share-based compensation expense semi-annually over the vesting period. During 2011 and 2010, we recorded $228,494 and $126,635, respectively, of share-based compensation expense related to these options. 36,000 of the options were cancelled in June 2011. The following are the assumptions made in computing the option fair value:


Average risk-free interest rate	1.0	%
Dividend yield	0	%
Expected term	5 years
Average expected volatility	89.96	%

In May 2011, Trans Energy granted 420,000 shares of stock to eight employees and three outside board members under the long-term incentive bonus program. The 420,000 shares are not performance based and vest semi-annually over a three year period, subject to ongoing employment. These shares were valued at $1,125,600 using fair market value of the common stock at the date of grant and will be amortized to compensation expense semi-annually over three years. During 2011, we recorded $375,200 of share-based compensation expense related to these shares.

In May 2011, Trans Energy granted 378,000 common stock options to eight employees and four outside board members. These options vest semi-annually over three years and have a five year term. These stock options were granted at an exercise price of $2.68 per common share, which was equal to the fair market value of the common stock at the date of grant and were valued using the Black Scholes valuation model. The options are being amortized to share-based compensation expense semi-annually over the vesting period. During 2011, we recorded $217,324 of share-based compensation expense related to these options. The following are the assumptions made in computing the option fair value:


Average risk-free interest rate	1.72	%
Dividend yield	0	%
Expected term	5 years
Average expected volatility	89.96	%

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In December, 2011, Trans Energy granted 12,000 shares of common stock and 36,000 common stock options to an employee with the same vesting and terms as the May 2011 issuances. These shares were valued at $5,360 using fair market value of common stock at the date of grant. The stock options were granted at an exercise price of $2.68 per common share and were valued using the stock holders valuation model and similar assumptions as the May 2011 options. During 2011, $5,360 and $10,349 were expensed for these common shares and stock options, respectively. Another employee purchased 10,000 shares of common stock at $2 per common share. The discount of $2,100 was rewarded as stock-based compensation.

Also in December 2011, Trans Energy granted 9,000 shares of stock to 1 employee, these shares were valued at $23,940 using the fair market value of the common stock at the date of grant, which was all included in 2011.

In August 2006, Trans Energy granted 800,000 common stock options to two employees with an expiration date of August 16, 2011. Trans Energy has extended those options to August 16, 2012. Trans Energy recorded $11,831 of additional share-based compensation during 2011 related to the one year extension. The following are the assumptions made in computing the option fair value:


Average risk-free interest rate	5.0	%
Dividend yield	0	%
Expected term	1 year
Average expected volatility	68.35	%

As a result of the above stock and option transactions, Trans Energy recorded total share-based compensation of $975,099 and $943,916 for the twelve months ended December 31, 2011 and 2010, respectively.

A summary of the status of the options granted under various agreements at December 31, 2011 and 2010, and changes during the years then ended is presented below:


	December 31, 2011					December 31, 2010
	Weighted Average Exercise					Weighted Average Exercise
	Shares			Price		Shares			Price
Outstanding at beginning of year		2,318,000			1.23		2,378,324		$	1.03
Granted		414,000			2.68		493,000			2.94
Exercised		(50,000	)		0.98		—			—
Forfeited		(411,000	)		1.06		—			—
Expired		(150,000	)		0.65		(533,324	)		1.95


Outstanding at end of year		2,121,000			1.59		2,318,000		$	1.23

A summary of the status of the options granted under various agreements at December 31, 2011 is presented below:


Range of Exercise Prices		Number Outstanding		Options Outstanding Weighted- Average Remaining Contractual Life	Weighted- Average Exercise Price		Number Exercisable		Options Exercisable Weighted- Average Exercise Price
$	3.00		332,000	3.77 years	$	3.00		166,000	$	3.00
$	2.75		125,000	3.48 years	$	2.75		125,000	$	2.75
$	0.98		250,000	2.27 years	$	0.98		200,000	$	0.98
$	0.82		200,000	1.01 years	$	0.82		200,000	$	0.82
$	0.65		800,000	0.62 years	$	0.65		800,000	$	0.65
$	2.68		414,000	4.50 years	$	2.68		132,000	$	2.86


			2,121,000					1,673,000

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NOTE 13 - BUSINESS SEGMENTS

Trans Energy’s principal operations consist of oil and gas sales with Trans Energy, and pipeline transmission with Ritchie County Gathering Systems and Tyler Construction Company.

Certain financial information concerning Trans Energy’s operations in different segments is as follows:


	For the Year Ended December 31,		Oil and Gas Sales		Pipeline Transmission			Corporate			Total
Revenue		2011	$	14,293,883	$	360,358		$	66,992		$	14,721,233
		2010	$	5,758,075	$	336,463		$	5,415		$	6,099,953
Income (Loss) from operations		2011		16,025,801		351,020			(5,606,851	)		10,769,966
		2010		25,635,280		(266,417	)		(3,893,281	)		21,475,582
Interest expense		2011		1,679,276		—			—			1,679,276
		2010		3,232,226		—			—			3,232,226
Depreciation, depletion, amortization and accretion		2011		5,556,434		9,244			—			5,565,679
		2010		3,075,762		10,769			—			3,086,531
Property and equipment acquisitions, including oil and gas properties		2011		16,395,797		—			—			16,395,797
		2010		19,366,358		—			—			19,366,358

Total assets, net of intercompany accounts:

December 31, 2011				57,994,415		231,202			—			58,225,817
December 31, 2010			$	40,530,099	$	357,479			—		$	40,887,578

NOTE 14 - RELATED PARTY TRANSACTIONS

Natural gas delivered through Trans Energy’s pipeline network is sold either to Sancho Oil and Gas Corporation (“Sancho”), a company controlled by the Vice President of Trans Energy, at the industrial facilities near Sistersville, West Virginia, or to Dominion Gas, a local utility company, on an on-going basis at a variable price per month per Mcf. Under its contract with Sancho, Trans Energy has the right to sell natural gas subject to the terms and conditions of a 20-year contract, as amended, that Sancho entered

F-25

into with Dominion Gas in 1988. This agreement is a flexible volume supply agreement whereby Trans Energy receives the full price which Sancho charges the end user less a $0.05 per Mcf marketing fee paid to Sancho. The amount paid to Sancho under this agreement was approximately $135 in 2011 and approximately $3,000 in 2010.

On October 6, 2009, our Board of Directors approved a plan to satisfy an immediate cash need of $1,250,000 to settle a disputed invoice for drilling services. The invoice had been held without payment for several months due to a dispute over its amount. Management negotiated a settlement at what it considered a reasonable level and less than the amount previously accrued. In order to raise the necessary funds to immediately settle the dispute, the company sold an interest in five shallow wells, which management determined to be non-strategic to the company, to Sancho for $321,192. In addition, three members of the Board of Directors extended 60-day bridge loans to the Company in the aggregate amount of $928,858, evidenced by three secured convertible promissory notes.

The promissory notes, payable on demand, were issued to James K. Abcouwer ($350,000), Robert L. Richards ($100,000), and Loren E. Bagley in the name of Sancho Oil & Gas ($478,858). Each note was secured by shares of the Company’s common stock equal to the value of the principal of the note based on the price of $0.65 per share. Interest on each note would be paid at the rate of 1.5% per month if the note were not paid within five days of demand. Each note was also convertible into shares of the Company’s common stock, commencing 30 days after issuance, entitling the holder to convert the note into shares of the Company’s common stock at the conversion price of $0.65 per share, based on the closing price of $0.60 for the Company’s shares in the public market on the date the notes were issued. As provided by the terms of the promissory notes, Mr. Abcouwer converted his note for 538,462 shares of common stock on December 30, 2009, Mr. Richards converted his note for 153,846 shares on January 29, 2010 and Sancho Oil & Gas converted its note for 736,705 shares on February 16, 2010.

NOTE 15 - ECONOMIC DEPENDENCE AND MAJOR CUSTOMERS

Trans Energy, Inc. has nine customers for the year ended December 31, 2011 and eight customers for the year ended December 31, 2010 that represent 100% of its gross oil and gas sales.

NOTE 16 - COMMITMENTS AND CONTINGENCIES

Effective July 1, 2007, Trans Energy implemented an employee 401(k) plan whereby Trans Energy will make basic safe-harbor matching contributions to those employees electing to participate in the plan. Matching contributions totaled $60,701 for 2011 and $41,619 for 2010.

As described in Note 10, Trans Energy has gas delivery commitments to Dominion Field Services. We believe that we can meet the delivery commitments based on our estimated production. If, however, Trans Energy can not meet such commitments, it will purchase natural gas at market prices to meet such commitments which will result in a gain or loss for the difference between the delivery commitment price and the price that Trans Energy is able to purchase the gas for redelivery (resale) to its customers.

NOTE 17 - SUBSEQUENT EVENTS

On February 29, 2012, American Shale entered into the Credit Agreement by and among American Shale as the borrower, certain banks and other financial institutions or entities that from time-to-time will be

F-26

parties thereto (“Lenders”), and Chambers Energy Management, LP as the administrative agent (“Agent”). Trans Energy and Prima will be “Guarantors” and, together with American Shale, will grant security interests over substantially all of the company’s assets in favor of the Agent for the benefit of the Lenders.

The principal amount of loans to be advanced under the Credit Agreement is $50 million, which loans will bear interest at a per annum rate equal to the greater of LIBOR or 1%, for a three month interest period, plus 10%. An additional 4% per annum for any quarter, may be charged if American Shale exceeds the maximum Consolidated Leverage Ratio, as defined in the Credit Agreement, for any fiscal quarter as provided in the Credit Agreement. This additional interest will be paid in kind. Upon the occurrence of any event of default as defined in the Credit Agreement, the loans will bear interest at an additional 2% per annum. Interest will be due and payable monthly in arrears, on the maturity date and on the date of any prepayment of principal.

The loans will be advanced as a single funding of $50 million less a 6% fee on the funding date of the Credit Agreement, once all conditions precedent have been satisfied. There will be no scheduled amortization of the principal amount of the loans and all principal will be due on February 28, 2015 (the “Maturity Date”), if not accelerated before that date. The principal amount of the loans may be prepaid, but not reborrowed. If the loans are prepaid on or prior to the second anniversary of the funding date, a makewhole amount will be charged equal to the sum of the remaining scheduled payments of interest with respect to the loans from the prepayment date through the second anniversary of the funding date.

Also on the funding date of the Credit Agreement, Trans Energy and Prima will execute a Guarantee and Security Agreement (the “Guarantee Agreement”). The Guarantee Agreement provides that Trans Energy and Prima will guarantee the indebtedness of American Shale under the terms of the Credit Agreement.

A portion of the loans will be funded on the funding date directly to an account controlled by American Shale to be applied to refinance certain debts of Trans Energy under its existing credit facility with CIT, and to pay expenses of Trans Energy and American Shale. The remaining proceeds of the loans will be funded on the funding date to an account of American Shale controlled by the Agent (the “Funding Account”). These funds are to be used to develop the Marcellus Properties.

As part of the Credit Agreement with Chambers, American Shale, for and in consideration of $2 million dollars, entered into a Warrant Agreement (“Warrant”) that allows for a period of five years, ending February 28, 2017, Chambers has the option to purchase up to 19.5% of the common shares of American Shale at an exercise price of $5,137,000. Such Warrant contains customary provisions that are common in such agreements.

The Warrant contains a provision that, under certain circumstances, Chambers may elect, but shall not be obligated, to cause American Shale to repurchase the Warrant for cash (the “Put Option”) prior to the maturity of the Credit Agreement. The Put Option will arise upon the earliest to occur of (i) a sale, farm-out, assignment or other disposition by Republic of all or substantially all of Republic’s working interest in the Joint Development Area, (ii) the third anniversary of the closing date of the Credit Agreement and (iii) an acceleration of the payment obligations under the Credit Agreement. The repurchase price will be an amount determined by terms stated in the Warrant, which could be for a sum exceeding the exercise price of the Warrant. Also, upon the occurrence of certain events affecting the contractual relationships among Trans Energy, American Shale, REO, and certain affiliates of the Trans Energy, Chambers would be able to exert voting control of American Shale until it receives adequate consideration for the Put Option

On March 30, 2012 the Company and CIT entered into the Eighth Amendment to the Credit Agreement.

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The Eighth Amendment and other related agreements extend the maturity date of the Credit Agreement to April 30, 2012. The Eighth Amendment also waves specific items of default.

NOTE 18 - SUPPLEMENTARY INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

Trans Energy retained Wright & Company, Inc., independent third-party reserve engineers, to perform an independent evaluation of proved reserves as of December 31, 2011 and 2010, respectively. Results of drilling, testing and production subsequent to the date of the estimates may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. All of Trans Energy’s reserves are located in the United States.

The following supplemental unaudited information regarding Trans Energy’s oil and gas activities is presented pursuant to the disclosure requirements of generally accepted accounting principles in the United States. In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. In addition, in January 2010 the FASB issued an accounting standard update to provide consistency with the SEC rules. See Note 1. Summary of Significant Accounting Policies – Recently issued Accounting Pronouncements. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, which are included in our reserves estimates.

The standardized measure of discounted future net cash flows is computed by applying the required prices of oil and gas to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on fiscal year-end cost estimates assuming continuation of existing economic conditions) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on fiscal year-end statutory tax rates) to be incurred on pre-tax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

Aggregate capitalized costs relating to Trans Energy’s crude oil and natural gas producing activities, including asset retirement costs and related accumulated depreciation, depletion, and amortization are as follows:


	As of December 31,
	2011			2010
Proved oil and gas producing properties and related lease, wells and equipment	$	49,723,104		$	37,967,076
Unproved Oil and Gas Properties		9,507,789			6,156,188
Accumulated Depreciation, Depletion and Amortization		(14,545,126	)		(7,909,714	)


Net Capitalized Costs	$	44,685,767		$	36,213,550

F-28

All of Trans Energy’s operations are in the United States.

Costs Incurred in Oil and Gas Activities

Costs incurred in connection with Trans Energy’s crude oil and natural gas acquisition, exploration and development activities for each of the periods shown below:


	For the Year Ended December 31,
	2011		2010
Acquisition of Properties
Proved	$	—	$	—
Unproved		5,023,409		5,265,912
Exploration Costs		—		—
Development Costs		11,242,136		13,895,853


Total Costs Incurred	$	16,265,545	$	19,161,765

Results of Operations for Oil and Gas Producing Activities

Aggregate results of operations, in connection with Trans Energy’s crude oil and natural gas producing activities, for each of the periods shown below:


	For the Year Ended December 31,
	2011			2010
Sales	$	14,293,883		$	5,681,679
Production Costs (a)		(5,339,544	)		(1,841,788	)
Depreciation, Depletion and Amortization		(5,556,434	)		(3,075,762	)
Income Tax Expense		(214,000	)		(450,000	)


Total Results of Operations for Producing Activities (b)	$	3,183,904		$	324,129

(a)	Production costs consist of oil and gas operations expense, production and ad valorem taxes, plus general and administrative expense supporting Trans Energy’s oil and gas operations.

(b)	Excludes the activities of pipeline transmission operations, corporate overhead and interest costs, gain on sale of oil and gas assets and related income taxes

Estimated Quantities of Proved Oil and Gas Reserves

Trans Energy’s proved oil and natural gas reserves have been estimated by independent petroleum engineers. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors.

F-29

The following schedule sets forth the proved reserves of Trans Energy during each of the periods presented:


	As of December 31,
	2011									2010
	Oil (BBL)			Gas (MCF)			NGL (BBL)			Oil (BBL)			Gas (MCF)
Proved Reserves:
Beginning of the period		372,769			12,791,642						158,545			6,565,058
Revisions of previous estimates		(198,659	)		4,559,552						—			(1,937,955	)
Extensions and discoveries		5,672			2,713,069			595,505			230,802			9,159,640
Improved recovery											—			—
Production		(15,876	)		(3,369,131	)		(36,116	)		(16,578	)		(995,101	)
Purchases of minerals in place											—			—
Sales of minerals in place											—			—


End of period		163,906			16,695,132			559,388			372,769			12,791,642


Proved Developed Reserves, End of Year		163,906			16,695,133			559,389			372,769			12,791,642

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information is based on Trans Energy’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2011 and 2010 in accordance with GAAP which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of Trans Energy’s proved oil and gas reserves.


	As of December 31,
	2011			2010
Future Cash Inflows	$	124,209,995		$	90,438,260
Future Production Costs (a)		(35,128,834	)		(28,149,581	)
Future Development Costs		—			(5,550,000	)
Future Income Tax Expense		(17,816,232	)		(11,347,736	)
Future Net Cash Flows	$	71,264,929		$	45,390,943
Discounted for Estimated Timing of Cash Flows	$	38,262,929		$	(23,800,943	)


Standardized Measure of Discounted Future Net Cash Flows	$	33,002,000		$	21,590,000

(a)	Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and general and administrative expense supporting Trans Energy’s oil and gas operations and are based

Effective for the year end 2009, SEC reporting rules require that year-end reserve calculations and future cash inflows be based on the weighted average of the first day of the month price for the previous twelve month period. The prices for 2011 used in the above table were $4.65 per MMBTU, $89.23 per BBL for oil and 48.65 per BBL for natural gas liquids. The prices used for 2010 were $5.29 per MMBTU and $70.60 per BBL.

F-30

Summary of Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to Trans Energy’s proved crude oil and natural gas reserves at year end are set forth in the table below:


	For the Year Ended December 31,
	2011			2010
Standardized Measure, Beginning of Year	$	21,590,000		$	12,775,526
Oil gas and NGL sales, net of production costs		(10,979,176	)		(3,839,891	)
Changes in prices and future production		145,458			1,344,478
Extensions, discoveries and improved recovery, net of costs		5,920,873			16,744,699
Purchases and Sales of Minerals in place		—			—
Change in estimated future development costs		(5,550,000	)		(4,500,000	)
Previously estimated development costs incurred		5,550,000			1,050,000
Revisions of previous quantity estimates		14,742,791			4,880,308
Accretion of Discount		2,159,000			1,277,553
Net change in income taxes		(6,468,496	)		(5,043,085	)
Timing and Other		5,891,550			(3,049,588	)


Standardized Measure, End of Year	$	33,002,000		$	21,590,000

F-31