Edgar Filing: TRANS ENERGY INC

Large Accelerated filer

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, 2012

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

For the transition period from to

Commission File Number 0-23530

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 number, 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 x 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, 2012) was $6,085,460 (based on price of $1.80 per share).

The number of shares outstanding of each of the issuer’s classes of common equity, as of April 15, 2013, was 13,236,228 shares.

EXPLANATORY NOTE

We are filing this amendment to our annual report on Form 10-K for the year ended December 31, 2012, filed on April 16, 2013, 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:

•

Included in Item 2. Properties

•

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

•

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

•

Drilling activity disclosure has been expanded to include 2010 activity

•

Revisions to Exhibits 31 and 32 to reflect 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		3

Item 1A Risk Factors		6

Item 1B Unresolved Staff Comments		13

Item 2 Properties		13

Item 3 Legal Proceedings		17

Item 4 Mine Safety Disclosures		18

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		23

Item 8 Consolidated Financial Statements and Supplementary Data		23

Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		23

Item 9A Controls and Procedures		23

Item 9B Other Information		24

PART III

Item 10 Directors, Executive Officers, and Corporate Governance		24

Item 11 Executive Compensation		24

Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		24

Item 13 Certain Relationships and Related Transactions and Director Independence		24

Item 14 Principal Accounting Fees and Services		24

PART IV

Item 15 Exhibits and Financial Statement Schedules		25

Signatures		26

EXPLANATORY NOTE

RESTATEMENT OF CERTAIN QUARTERLY UNAUDITED INFORMATION

Overview

On April 15, 2013, Trans Energy, Inc. (“Trans Energy”, or the “Company”) announced that it had identified an accounting error related to certain puttable warrants issued in conjunction with a Credit Agreement (the “ASD Credit Agreement”) that the Company’s wholly owned subsidiary, American Shale Development, Inc. (“American Shale” or “ASD”), entered into on February 29, 2012. The ASD Credit Agreement includes financing from several banks and other financial institutions, and Chambers Energy Management, LP, as administrative agent (“Chambers”).

For participation in the ASD Credit Agreement, American Shale, for and in consideration of $2 million, entered into a Warrant Agreement (“Warrant”) with Chambers. The Warrant provides Chambers the option to purchase up to 19.5% of the common shares of ASD at an exercise price of $5,137,000 for a period of three years ending on February 28, 2015. The Warrant also includes a feature under which Chambers has the option (the “Put Option”), at its sole discretion, to put (i.e., sell) the Warrant back to the Company at the three year anniversary date (if not earlier due to other factors), in return for a cash payment equal to the excess of i) the fair market value of an ASD common share over ii) the Warrant strike price of $263.44. In addition, the Warrant strike price will be reduced to equal the offering price of any common shares subsequently sold below $263.44 (the “Down-Round Provision”).

Trans Energy initially reported the cash consideration of $2 million received for issuing the Warrant as Additional Paid in Capital (“APIC”) within Stockholders’ Equity in the Quarterly Reports on Form 10-Q previously filed for the periods ended June 30, 2012 and September 30, 2012, respectively.

However, upon further analysis, the Company has determined that the Put Option and Down-Round Provision result in the Warrants qualifying as derivative liabilities, rather than equity instruments. The Company’s conclusion is based on the following: i) the Put Option embodies an obligation that permits Chambers to require the Company to repurchase the Warrants by transferring assets (cash), pursuant to Accounting Standards Codification (“ASC”) 480-10, “Distinguishing Liabilities from Equity”; and ii) the Down-Round Provision is not indexed to the Company’s own stock, as it could result in the exercise price of the Warrants being modified based upon a variable that is not an input to the fair value of a ‘fixed-for-fixed’ option, pursuant to ASC 815-40, “Derivatives and Hedging—Contracts in an Entity’s Own Stock”.

As such, the Company should have recorded the $2 million in cash consideration paid by Chambers, which represents the fair value of the Warrant on the issuance date, as a warrant derivative liability (rather than APIC). Subsequent to the issuance, the warrant liability should be recorded at fair value at each reporting date, with changes in such fair value being recorded through other income (expense) on the Company’s Statement of Operations. The Company determined the fair value of the Warrants at inception and each subsequent reporting date using a lattice model.

The aforementioned accounting error represents non-cash, items that result in the understatement of warrant derivative liabilities, overstatement of stockholders’ equity and under/overstatement of other income (expense) for the periods ended June 30, 2012 and September 30, 2012. The Company appropriately accounted for the Warrants as of, and for the period ended, December 31, 2012.

On April 10, 2013, the Audit Committee of the Company’s Board of Directors concluded that due to the error and failure of recognizing the Warrant as derivative liabilities, the Company’s previously issued unaudited consolidated financial statements as of, and for the periods ended June 30, 2012 and September 30, 2012 should no longer be relied upon. The Company intends to correct the effect of the accounting error described above by amending the previously filed the Form 10-Q for the periods ended June 30, 2012 and September 30, 2012.

As a result of the above described warrant derivative accounting errors, the Company examined and assessed the underlying internal control deficiencies that compromised the Company’s ability to prevent or detect such issues. Specifically, the Company has identified control deficiencies in the processes, procedures and controls related to derivative accounting.

Management reassessed its evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2012 based on the framework in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of Tradeway Commission (COSO). As a result of that assessment, management identified control deficiencies that constituted a material weakness and accordingly, has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2012. For a description of the material weakness identified by management and management’s plan to remediate the material weakness, see “Part II - Item 9A—Controls and Procedures”.

PART I

Item 1 Business

History

Trans Energy, Inc. (we,” “our,” “us” or the “Company”) is an independent energy company 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. As of December 31, 2012, we owned interests in and operate approximately 300 oil and gas wells in West Virginia, of which 127 are currently active and 22 were horizontal producing wells completed in the Marcellus Shale formation. 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 60,766 gross acres (23,176 net) 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 28, 2013, our wholly owned subsidiary, American Shale Development, Inc. amended and restated the credit agreement that was previously entered into on February 29, 2012 by and among American Shale, several banks and other financial institutions or entities that from time-to-time will be parties to the Credit Agreement, and Chambers Energy Management, LP as the administrative agent. The new credit agreement was entered into among the parties in order to facilitate an increase in the principal amount of the borrowings under the facility to $75 million from $50 million. The additional funds were received February 28, 2013.

On January 24, 2013, we closed the sale of our interests in certain non-core assets for approximately $2,625,000 of net cash proceeds. The interests sold consisted of our working interest in all existing shallow wells, but we retained an overriding royalty interest of approximately 2.5% on most of the wells. The purchaser assumed the role of operator with respect to approximately 300 wellbores, and intends to commence a workover program with respect to a number of the existing wells. The wells produced at a rate of approximately 800 mcfe per day as of December 31, 2012, which was the effective date for the transaction. As of the December 31, 2011 reserve report, these wells had proven reserves of 2.5 Bcfe.

Additionally, we granted the purchaser (the “shallow operator”) the right to drill wells in or above conventional shallow Devonian formations, for leases where we currently hold rights to such depths. We did not farm out any of our rights to drill in deeper formations such as the Rhinestreet, Marcellus or Utica. We retained up to a 5% overriding royalty interest on any such wells drilled, depending on the net revenue interest.

On March 30, 2012, the Company and CIT Capital USA Inc. (“CIT”) entered into the Eighth Amendment of an existing credit agreement (the “Eight Amendment”). The Eighth Amendment and other related agreements extended the maturity date of such credit agreement to April 30, 2012 and waved specific items of default.

On April 26, 2012 (“Funding Date”), our newly created, wholly owned subsidiary, American Shale Development, Inc. (“American Shale”), closed the ASD Credit Agreement transaction that was entered into on February 29, 2012 by and among American Shale, several banks and other financial institutions or entities that from time-to-time will be parties to the ASD Credit Agreement (the “Lenders”), and Chambers Energy Management, LP as the administrative agent (“Agent”). Trans Energy is a guarantor of the ASD Credit Agreement as is Prima Oil Company, Inc. (“Prima”), another of our 100% wholly owned subsidiaries. The ASD Credit Agreement provides that Lenders will lend American Shale up to $50 million, which funds will be used to develop wells and properties that we have transferred to American Shale. Trans Energy received a portion of the funds from the ASD Credit Agreement to repay debts outstanding under the CIT credit agreement.

In order to accommodate the terms of the ASD Credit Agreement we have transferred certain assets and properties to American Shale. Trans Energy is not a direct party to the ASD Credit Agreement, but is a guarantor of loans to be made thereunder and has received a portion of the loan proceeds to repay certain outstanding debts. The assets and properties transferred are referred to herein as the “Marcellus Properties.” These consist of working interests (“WI”) in 14 (6.11 net) producing wells and 5 (1.49 net) wells in the process of being drilled and completed in the Marcellus shale liquids-rich gas field and approximately 23,000 net acres of Marcellus shale leasehold rights, located in Northwestern West Virginia in the counties of Wetzel, Marshall, Marion, Tyler, and Doddridge.

We drilled five horizontal wells in 2012 and retained a 50% working interest in two of the wells and approximately a 39% working interest in the remaining three wells. In 2011 we drilled six horizontal wells in a joint venture with Republic Partners targeting the Marcellus Shale. Republic Partners retained a 50% working interest in these wells, as permitted by the terms of the joint venture. Of the six horizontal wells drilled in 2011, four were drilled through a farm out with Gastar Exploration USA, Inc. (“Gastar”), whereby Gastar would purchase a working interest in the wellbores. We retained a 5% working interest in the wellbores and Gastar retained a 45% working interest. Once Gastar receives 100% of their investment; then our working interest will increase to 10% and Gastar’s working interest will be reduced to 40%. Republic Partners retained 50% working interest in these wells as permitted by the terms of the joint venture.

The following table summarizes the status of the wells drilled under the joint venture with Republic Partners.


Name	Net WI	Spud Date	Completion Date	Status
Whipkey 3H	.05	May 2011	August 2011	Producing
Lucey 2H	.05	August 2011	November 2011	Producing
Goshorn 1H	.05	October 2011	April 2012	Producing
Goshorn 2H	.05	November 2011	June 2012	Producing
Dewhurst 110H	.38	December 2011	September 2012	Producing
Dewhurst 111H	.38	December 2011	September 2012	Producing
Anderson 5H	.36	January 2012	May 2012	Producing
Anderson 7H	.36	January 2012	May 2012	Producing
Doman 1H	.50	April 2012	October 2012	January 2013
Doman 2H	.50	May 2012	October 2012	January 2013
Martinez 1H	.42	June 2012	Est. 2 nd Q 2013	Est. 2 nd Q 2013

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, 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.

We have 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 35 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 Gas and its subsidiary, East Resources.

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 a director of Trans Energy, at the industrial facilities near Sistersville, West Virginia during 2011. Approximately 98% is sold to Dominion and 2% is sold to Sancho. Under its contract with Sancho, we have 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 we receive the full price that 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. During 2012, Sancho retained their marketing fee.

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. We currently sell to 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. 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. We are and have the traditional competitive strengths of a regional operator, including long established contacts and in-depth knowledge of the local geography. There is also the possibility that future energy-related legislation and regulations may impact competitive conditions. Management believes that a viable market place exists for regional producers of natural gas and oil and operators of regional natural gas transmission systems.

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 an 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, 2012, we employed twenty-four full-time employees, consisting of five executives and managers, nine marketing, lease acquisition and clerical persons, and ten 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.

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 decreased approximately 20% during the fiscal year ended December 31, 2012, primarily due to a decrease in the price for oil, natural gas and natural gas liquids. However, we may not achieve, or subsequently maintain profitability if our 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, 2012, our net operating loss carryforward was approximately $16.7 million and our accumulated deficit was approximately $33 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.

If we default on our revolving credit facility entered into on February 29, 2012, our financial condition and future operations would be severely and negatively affected.

Management has secured additional funding for 2013 capital expenditures though future capital requirements after 2013 may require additional capital borrowing, selling equity or equity-linked securities that would dilute the ownership percentage of our existing stockholders Such 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. 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, see 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:

•

delays imposed by or resulting from compliance with regulatory requirements;

•

unusual or unexpected geological formations;

•

pressure or irregularities in geological formations;

•

shortages of or delays in obtaining equipment and qualified personnel;

•

equipment malfunctions, failures or accidents;

•

unexpected operational events and drilling conditions;

•

pipe or cement failures;

•

casing collapses;

•

lost or damaged oilfield drilling and service tools;

•

loss of drilling fluid circulation;

•

uncontrollable flows of oil, natural gas and fluids;

•

fires and natural disasters;

•

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

•

adverse weather conditions;

•

reductions in oil and natural gas prices;

•

oil and natural gas property title problems; and

•

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 less experience in drilling wells to the Marcellus Shale (only 22 wells drilled since 2010) 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 drilled and completed only 22 Marcellus Shale wells since 2010, and as a result, have 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 are also 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. We cannot 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 discounted future net 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 thereof 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 those assumptions could result in material differences in the actual quantity of reserves and amount of future net cash flows from estimated oil and gas reserves.

Our estimates of proved reserves have been prepared under current rules of the Securities and Exchange Commission (“SEC”), 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, 2012 and 2011, which have been prepared and presented under current SEC rules. These rules require SEC registrants to prepare their reserves estimates using revised reserve definitions and pricing based on the unweighted first-day-of-the-month average pricing for the previous 12 months, rather than year-end pricing.

Current SEC requirements also state that proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of initial 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 and development activities, including meeting certain drilling obligations under our existing lease obligations.

Our cash flow from our reserves 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 production, 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, and 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.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the “Dodd-Frank Act”) provides for new statutory and regulatory requirements for swaps and other financial derivative transactions, including certain oil and gas hedging transactions. In its rulemaking under the Dodd–Frank Act, the Commodity Futures Trading Commission (“CFTC”) issued final 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. In September 2012, The U.S. District Court for the District of Columbia vacated and remanded the rules for position limits adopted by the CFTC in October 2011 based on a necessity finding. Position limits may be imposed upon certain derivative transactions, which may restrict our ability to utilize these products. 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 or curtail our dealings with that counterparty. 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.

The rulemaking process under the Act has not been completed, and the timeframes for compliance with rules under the Act that are effective remain uncertain. Consequently, it is not possible at this time to determine the full effect that the Act and the rules and regulations adopted under the Act will have on our ability to continue to use the derivative products we currently utilize.

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 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 possess. 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 also depends, in part, on the ability to retain our executive officers and other key employees. 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, we may need to hire additional key personnel as we grow. 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.

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 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 the business; therefore, we 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 year 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 year 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, 2012 and, 2011, are set forth below:


	As of December 31,
			2012								2011
	Oil and Condensates (BBL)		Natural Gas (MCF)		NGL (BBL)		MCFE		Oil and Condensates (BBL)		Natural Gas (MCF)		NGL (BBL)		MCFE
Developed Producing		126,995		23,716,531		839,524		29,515,645		163,316		16,695,133		559,389		21,031,363
Developed Non-Producing		2,473		4,356,390		198,053		5,559,546		—		—		—
Proved Undeveloped		4,267		15,866,084		612,296		19,565,462		590		679,280		33,209		882,074


Total Proved		133,735		43,939,005		1,649,873		54,640,653		163,906		17,374,413		592,598		21,913,437

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

Proved undeveloped reserves as of December 31, 2011 and 2012 reflect the Company’s net working interest in such reserves that we have the intent and ability to develop, within five years of initial booking, through existing farm-out agreements and our joint venture with Republic partners, which will be financed by cash flow from operations and additional financing received in 2012 and 2013 from Chambers.

A review of our reserves was conducted as of December 31, 2012 and 2011 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. We work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished to the 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.

All of our reserve estimates are reviewed and approved by the Company’s President, John Corp. Mr. Corp 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 and thereafter, 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 as of December 31, 2012 and 2011 used in the above table were as follows:


	Oil		Condensates		Natural Gas		NGL
	(BBL)		(BBL)		(MMBTU)		(BBL)
2012	$	94.71	$	81.27	$	2.76	$	34.00
2011	$	89.73	$	58.21	$	4.24	$	48.65

The company’s gas processing arrangement did not allow 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 that the SEC in 2012 and 2011. See Note 18, Supplementary Information on Oil and Gas Producing Activities (unaudited) included as part of our consolidated financial statements.

Productive 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. Wells are shown on a gross basis.


	Gross as of December 31,
	2012				2011
	Oil		Natural Gas		Oil		Natural Gas
Producing Wells		31		80		31		76
Non-Producing Wells		—		4		—		—
Undrilled Well Locations		—		6		—		2

Total Wells and Well Locations		31		90		31		78


	Net as of December 31,
	2012				2011
	Oil		Natural Gas		Oil		Natural Gas
Producing Wells		30		71		30		70
Non-Producing Wells				2		—		—
Undrilled Well Locations				2		—		—

Total Wells and Well Locations		30		75		30		70

We excluded all shallow wells with no or minimal production since we do not plan on a rework program at this time.

Drilling Activity

The following table summarizes completed and producing 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,
	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		8		3.4		2.0		0.1		2.0		1.0
Dry		—		—		—		—		—		—
Exploratory Wells
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total		8		3.4		2.0		0.1		2.0		1.0

The Dewhurst 110H, Dewhurst 111H, Goshorn 1H, and Goshorn 2H were drilled in the fourth quarter of 2011. These wells were completed by the second quarter of 2012, and are reflected in the table above.

The Anderson 5H, Anderson 7H, were completed in the first quarter of 2012. The Doman 1H and Doman 2H were drilled in the second quarter of 2012 and were completed in the third quarter of 2012. The Martinez 1H was drilled in the second quarter of 2012 but will not be completed until 2013 and is not reflected in the table above.

Oil and Gas Acreage

The following table summarizes our gross and net developed and undeveloped oil and gas acreage under lease in West Virginia as of December 31, 2012 and 2011.


	Developed Acres				Undeveloped Acres				Total
	Gross		Net		Gross		Net		Gross		Net
2012		34,800		15,946		25,966		7,230		60,766		23,176
2011		27,550		13,997		24,751		7,039		52,301		21,036

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
2013		9,170		2,325
2014		2,513		686
2015		2,926		853
2016		6,284		1,811
2017		4,571		1,420


2018		322		55
2019		—		—
2020		180		80


Total		25,966		7,230

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,
	2012		2011
Net Production:
Oil (Bbl)		11,006		15,876
Natural Gas (Mcf)		2,118,350		2,769,410
NGL (Bbl)		83,574		42,691


Natural Gas Equivalent (Mcfe)		2,685,830		3,120,812


Oil and Natural Gas Sales:
Oil	$	1,012,918	$	1,554,923
Natural Gas		7,754,107		10,214,728
NGL		2,589,601		2,527,232


Total	$	11,356,626	$	14,293,883


Average Sales Price:
Oil ($ per Bbl)	$	92.03	$	97.94
Natural Gas ($ per Mcf)	$	3.66	$	3.69
NGL ($ per Bbl)	$	30.99	$	59.20
Natural Gas Equivalent ($ per Mcfe)	$	4.23	$	4.58
Oil and Natural Gas Costs:
Lease operating expenses	$	6,169,198	$	3,314,707
Average production cost per Mcfe	$	2.30	$	1.06

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 wholly-owned subsidiaries, Prima Oil Company, Inc., Ritchie County Gathering Systems, Inc., Tyler Construction Company, Inc., American Shale Development, Inc., and Tyler Energy, Inc. 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 September 5, 2012, the parties filed competing motions seeking summary judgment in this case. On November 26, 2012, the Court granted our motion for summary judgment and denied the defendant’s motions for declaratory judgment and summary judgment. At this time, the defendant has appealed the Court’s decision.

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.

On January 14, 2013, Abcouwer filed an action in the Circuit Court of Kanawha County, West Virginia against the Company, and two individual defendants currently on the Board of Directors of the Company – William F. Woodburn (“Woodburn”) and Loren E. Bagley (“Bagley”). The matter is identified as Civil Action No. 13-C-56 and was assigned to the Honorable Carrie L. Webster. In his complaint, Abcouwer alleges that Plaintiff and Defendants entered into a verbal agreement that required the Company to enter into a third party sales transaction which would have allegedly caused Abcouwer to make significant profit as the result of his ownership of Company stock. Abcouwer alleges that he lost approximately $30 million as a result of the fact that no sale of the Company ever took place. The Company believes that no such agreement existed and that Abcouwer’s claims are wholly without merit. On March 25, 2013, the Company filed an answer denying the existence of any liability and asserting, in the alternative, counterclaims for fraud and breach of fiduciary duty. The Company’s counterclaims allege that, to the extent a binding agreement between Abcouwer and the Company existed, Abcouwer failed to disclose such agreement to the Company and the SEC despite a duty to do so.

On September 28 and December 17, 2012, the U.S. Environmental Protection Agency (“EPA”) issued to the company seven administrative compliance orders and a request for information. The orders and request relate to our compliance with Clean Water Act (“CWA”) permitting requirements at seven pond and/or well site locations in Marshall and Wetzel Counties, West Virginia and concern the alleged discharge of dredged and/or fill material into waters of the United States. The company is actively cooperating with the EPA to resolve these matters in a timely manner. The CWA provides authority for significant civil and criminal penalties for the placement of fill in a jurisdictional stream or wetland without a permit from the Army Corps of Engineers, including for civil penalties as high as $37,500 per day per violation. Monetary civil and/or criminal penalties can be substantial for non-compliance with CWA requirements. The CWA sets forth criteria, including degree of fault and history of prior violations, which may influence CWA penalty assessments. The EPA may also seek to recover any economic benefit derived from non-compliance with the CWA.

Resolution of the EPA’s compliance orders may include monetary sanctions. However, we presently do not have sufficient information to determine whether the potential liability with respect to these matters will have a material effect on our financial position, on the results of operations, or on cash flow.

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
2012
First Quarter	$	2.95	$	1.26
Second Quarter	$	2.30	$	1.60
Third Quarter	$	2.25	$	1.51
Fourth Quarter	$	3.00	$	1.67
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

As of March 31, 2013, 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 Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to help the reader understand Trans Energy’s financial position, changes in financial condition, and results of operations. MD&A is provided as a supplement to the Company’s Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements (“Footnote” or “Notes”) and should be read in conjunction with the Consolidated Financial Statements and Notes.

Certain statements in this report including, without limitation, statements regarding future financial results and performance, plans and objectives, capital expenditures and the Company’s or management’s beliefs, expectations or opinions, are forward-looking statements, and as such, Trans Energy desires to take advantage of the “safe harbor” which is afforded such statements under the Private Securities Litigation Reform Act of 1995. The Company’s forward-looking statements should be read in conjunction with the Company’s comments in this report under the heading, “Disclosure Regarding Forward-Looking Statements.” Actual results may differ materially from those statements as a result of factors, risks and uncertainties over which the Company has no control. For a list of these factors, risks and uncertainties, refer to Item 1A—Risk Factors.

Business Strategy

Trans Energy is an independent energy company primarily engaged in the acquisition, exploration, development, and production of natural gas and crude oil properties, with interests targeting the Marcellus Shale in West Virginia. We successfully increased our drilling program in 2012 and 2011, adding both natural gas and natural gas liquids reserves to the Company’s 2012 proved reserve base and natural gas and crude oil reserves to the Company’s 2011 proved reserves base. Furthermore, the Company established major interconnects with interstate pipelines to allow increased access to the market.

We intend to focus our development and exploration efforts in our Marcellus Properties and utilize our acreage position to expand our reserve base through continued exploratory and development drilling in the Marcellus Shale for 2013 and beyond. 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 acreage position will allow us to grow through horizontal 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


	Fiscal Year Ended December 31,
	2012			2011
Total revenues	$	11,755,421		$	14,721,233
Total costs and expenses		(26,602,269	)		(16,579,163	)
Gain on sale of assets		112,898			12,627,896


(Loss) income from operations		(14,733,950	)		10,769,966
Other expenses		(6,527,667	)		(1,629,290	)
Income tax benefit (expense)		58,013			(214,000	)


Net (loss) income		(21,203,604	)		8,926,676

Total revenues of $11,755,421 for the year ended December 31, 2012 decreased $2,965,812 or 20% compared to $14,721,233 for the year ended December 31, 2011. The decrease in revenue is due to a decrease in pricing on oil, natural gas, natural gas liquids, and production volumes. We focused our efforts during 2012 and 2011 on the implementation of our drilling program in Marshall and Wetzel Counties, West Virginia. We expect an increase in production from the drilling program throughout 2013.

Production costs increased $2,719,627 or 67% for 2012 as compared to 2011, primarily due to an increase in transportation fees and natural gas liquid processing fees, associated with the increased production in NGLs. In lieu of constructing and maintaining a pipeline, the Company has agreed to pay the transporter $0.35 per MCF to transport a contractual amount of production on the first well drilled on the pad. After the contractual amount is transported, the price reduces to $0.15 per MCF to transport gas. Any future wells drilled are charged $0.15 per MCF for transporting the gas produced. We are contractually obligated to provide 2,000,000 MMBTU/mile of lateral extension that must be fulfilled within the first five years in order to reduce our transportation fee per MCF. If the volumes are not met the transportation fee remains at $0.35 per MCF.

Depreciation, depletion, amortization and accretion expense decreased $1,787,116 or 32% for 2012 as compared to 2011, primarily due to lower production volumes and higher year end reserves.

Impairment of oil and gas properties for 2012 increased by $8,844,653 due to the write down of shallow producing properties. The shallow oil and gas properties were written down to the net cash proceeds to be received from the shallow well sale in January 2013, plus a value for the ORRI retained by the company.

Selling, general and administrative expense increased $245,942 or 4% for 2012 as compared to 2011, due to increased legal fees, and an increase in share based compensation, including related one-time employment separation agreements, which was partially offset by a decrease in consulting fees for debt restructuring during the year.

Gain on sale of assets decreased by $12,514,998 in 2012 as compared to 2011. During 2011 2,950 net acres were sold 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 2011, with the remainder being used to partially fund the drilling and completion expenses for certain wells.

Our loss from operations for 2012 was $14,733,950 compared to income of $10,769,966 for 2011. This change is primarily due to the large sale of acreage in 2011 and the decrease in production revenue as well as the oil and gas property impairment recorded for 2012.

Interest expense increased $4,059,527 or 242% for 2012, as compared to 2011 due to a significantly higher loan balance after the refinancing. The average loan balances for 2012 and 2011 were $38,699,144 and $14,545,338, respectively.

(Loss) on derivative for 2012 was $807,639 compared to a gain of $48,943 in 2011. The loss for 2012 was the result of recording the change in the value of the put option associated with our warrant derivative liability.

We have accumulated approximately $16.7 million of net operating loss carryforwards as of December 31, 2012, which may be offset against future tax obligations through 2031. 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. 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 in income tax expense in 2011, for alternative minimum tax related to our gain on sale. No tax benefit has been reported in the financial statements for the year ended December 31, 2012 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, 2012, we have positive working capital of $2,487,924 compared to a working capital deficit of $18,362,177 at December 31, 2011. This increase in working capital is primarily attributed to an increase in cash to pay off accounts payable and a reduction of the current portion of notes payable due to obtaining the Chambers financing.

During 2012, net cash used by operating activities was $14,707,856 compared to net cash provided of $16,531,927 in 2011. This decrease in cash flow from operating activities is primarily due to a significant decrease in accounts payable and a decrease in net income.

We expect our cash flow provided by operations for 2013 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 2012, net cash used for investing activities was $24,845,110 compared to net cash used of $3,848,414 in 2011. The reason for the change was a decrease in cash proceeds from acreage sales and increased expenditures for oil and gas properties during 2012 compared to 2011. See notes 6 and 8 to the financial statements for additional information.

During 2012, net cash provided by financing activities was $32,676,398 compared to net cash used of $5,832,802 in 2011. This change reflects the refinancing of the Company’s debt. We anticipate meeting our working capital needs with revenues from our ongoing operations and the $25 million in additional funding received from Chambers in 2013.

Inflation

In the opinion of our management, inflation has not had a material overall effect on our operations of Trans Energy. However, our credit facility is indexed to LIBOR and any increase in LIBOR would affect our interest costs.

Subsequent Events

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

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 our financial position, results of operations or cash flows.

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, 2012 and 2011 and for the fiscal years ended December 31, 2012 and 2011 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, 2012, 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, 2012, our disclosure controls and procedures were not effective because of the material weakness described below.

Material Weakness in Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act). Internal control over financial reporting is a process designed by, or under the supervision of, our principal executive officer and principal financial officer, and affected by our board of directors, management and other personnel, to provide reasonable assurance regarding the financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement in the reporting company’s annual or interim financial statements will not be prevented or detected on a timely basis.

The Company did not maintain an effective financial reporting process to prepare financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). Specifically, the Company did not properly report the fair value of its warrant derivative as a liability and the change in the liability’s fair value in its Consolidated Statements of Operations. This matter was discovered subsequent to December 31, 2012, and as a result, the Company restated its previously issued interim financial statements for periods ended June 30 and September 30, 2012.

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, 2012 in conformity with U.S. 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, 2012 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 not effective as of December 31, 2012, and did not provide 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

We are committed to continuing to improve our internal control processes and will continue to review our financial reporting controls and procedures. As we continue to evaluate and work to improve our internal control over financial reporting, we will identify measures to address the material weakness. Our management, with the oversight of the audit committee of our board of directors, will continue to assess and take steps to enhance the overall design and capability of our control environment in the future. More specifically, the Company intends to remediate the material weakness in the internal control over financial reporting identified above by adding additional controls over derivative accounting and the application of relevant accounting guidance.

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, 2012.

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 16, 2013

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 John G. Corp	President and Director (Principal Executive Officer)	April 16, 2013

/s/ John S. Tumis John S. Tumis	Chief Financial Officer	April 16, 2013

/s/ Loren E. Bagley Loren E. Bagley	Director	April 16, 2013

/s/ William F. Woodburn William F. Woodburn	Director	April 16, 2013

/s/ Josh L. Sherman Josh L. Sherman	Director	April 16, 2013

/s/ Richard L. Starkey Richard L. Starkey	Director	April 16, 2013

/s/ Stephen P. Lucado Stephen P. Lucado	Director	April 16, 2013

/s/ Robert L. Richards Robert L. Richards	Director	April 16, 2013

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, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with 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, 2012 and 2011, 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.

/s/ Maloney + Novotny LLC

Maloney + Novotny LLC

Cleveland, Ohio

April 15, 2013

F-2

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets


	December 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS
Cash	$	1,009,084		$	7,885,652
Accounts receivable, trade		3,143,766			2,074,851
Accounts receivable, related parties		18,500			18,500
Advance royalties		221,452			114,099
Prepaid expenses		407,596			73,098
Accounts receivable due from non-operator, net		—			1,754,020
Deferred financing costs, net of amortization of $402,525 and $712,500		603,788			237,500


Total Current Assets		5,404,186			12,157,720
OIL AND GAS PROPERTIES, USING SUCCESSFUL EFFORTS ACCOUNTING
Proved properties		47,730,848			28,114,329
Unproved properties		12,008,550			7,752,858
Pipelines		1,387,440			1,387,440
Accumulated depreciation, depletion and amortization		(8,809,022	)		(4,537,522	)


Oil and gas properties, net		52,317,816			32,717,105
PROPERTY AND EQUIPMENT, net of accumulated depreciation of $239,277 and $201,214, respectively		665,874			656,064
OTHER ASSETS
Assets held for sale		3,013,000			12,393,976
Deferred financing costs		735,662			—
Other assets		301,923			300,952


Total Other Assets		4,050,585			12,694,928


TOTAL ASSETS	$	62,438,461		$	58,225,817

See notes to consolidated financial statements.

F-3

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (continued)


	December 31, 2012			December 31, 2011
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	187,089		$	14,333,750
Accounts payable due to drilling operator		839,456			—
Accounts payable, related party		1,500			2,150
Accrued expenses		1,642,718			1,152,885
Revenue Payable		225,674			451,825
Taxes Payable		—			270,708
Notes payable – current		19,825			14,308,579


Total Current Liabilities		2,916,262			30,519,897
LONG-TERM LIABILITIES
Notes payable, net		48,225,848			5,612
Asset retirement obligations		28,317			31,568
Liabilities held for sale		388,005			225,083
Warrant derivative liability		2,808,278			—


Total Long-Term Liabilities		51,450,448			262,263


Total Liabilities		54,366,710			30,782,160


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; 13,238,228 and 12,981,828 shares issued, and 13,236,228 and 12,979,828 shares outstanding, respectively		13,238			12,982
Additional paid-in capital		41,131,636			39,300,194
Treasury stock, at cost, 2,000 shares		(1,950	)		(1,950	)
Accumulated deficit		(33,071,173	)		(11,867,569	)


Total Stockholders’ Equity		8,071,751			27,443,657


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	62,438,461		$	58,225,817

See notes to consolidated financial statements.

F-4

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations


	For the Year Ended December 31,
	2012			2011
REVENUES	$	11,755,421		$	14,721,233
COSTS AND EXPENSES
Production costs		6,771,123			4,051,496
Depreciation, depletion, amortization and accretion		3,778,563			5,565,679
Impairment of oil and gas properties		10,132,702			1,288,049
Selling, general and administrative		5,919,881			5,673,939


Total Costs and Expenses		26,602,269			16,579,163
Gain on sale of assets		112,898			12,627,896


(LOSS) INCOME FROM OPERATIONS		(14,733,950	)		10,769,966


OTHER INCOME (EXPENSES)
Interest income		18,774			1,043
Interest expense		(5,738,803	)		(1,679,276	)
(Loss) Gain on derivatives		(807,639	)		48,943


Total Other Income (Expenses)		(6,527,667	)		(1,629,290	)


NET (LOSS) INCOME BEFORE INCOME TAXES		(21,261,617	)		9,140,676
INCOME TAX BENEFIT (EXPENSE)		58,013			(214,000	)


NET (LOSS) INCOME	$	(21,203,604	)	$	8,926,676


(LOSS) EARNINGS PER SHARE—BASIC	$	(1.62	)	$	0.70
(LOSS) EARNINGS PER SHARE—DILUTED	$	(1.62	)	$	0.66
WEIGHTED AVERAGE SHARES OUTSTANDING – BASIC		13,074,208			12,807,964
WEIGHTED AVERAGE SHARES OUTSTANDING – DILUTED		13,074,208			13,552,221

See notes to consolidated financial statements.

F-5

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity

For the years ended December 31, 2012 and 2011


					Additional
	Common Stock				Paid in		Treasury			Accumulated
	Shares		Amount		Capital		Stock			Deficit			Total
Balance, December 31, 2010		12,737,328	$	12,737	$	38,256,340	$	(1,950	)	$	(20,794,245	)	$	17,472,882
Stock issued for note conversion		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
Shares issued for services		256,400		256		687,454		—			—			687,710
Stock Option Compensation expense		—		—		1,143,988		—			—			1,143,988
Net loss		—		—		—		—			(21,203,604	)		(21,203,604	)


Balance, December 31, 2012		13,238,228	$	13,238	$	41,131,636	$	(1,950	)	$	(33,071,173	)	$	8,071,751

See notes to consolidated financial statements.

F-6

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows


	For the Year Ended December 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(21,203,604	)	$	8,926,676
Adjustments to reconcile net (loss) income to net cash (used) provided by operating activities:
Depreciation, depletion, amortization, and accretion		3,778,563			5,565,679
Impairment of fixed assets		10,132,702			1,288,049
Amortization of deferred financing cost and debt discount		1,345,908			712,500
Share-based compensation		1,831,698			975,099
Gain on sale of assets		(112,898	)		(12,627,896	)
Unrealized loss on derivatives		808,278			187,590
Interest and legal expense added to principal		1,057,226			1,245,698
Changes in operating assets and liabilities:
Accounts receivable, trade		(1,068,915	)		(879,592	)
Accounts receivable due from non-operator, net		1,754,020			(1,671,056	)
Advance royalties and other assets		(250,971	)		(14,718	)
Prepaid expenses and other current assets		(441,851	)		752,548
Accounts payable and accrued expenses		(12,679,959	)		11,798,817
Accounts payable drilling operator		839,456			—
Accounts payable related party		(650	)		—
Revenue payable		(226,151	)		451,825
Income tax payable		(270,708	)		(179,292	)


Net cash (used) provided by operating activities		(14,707,856	)		16,531,927


CASH FLOWS FROM INVESTING ACTIVITIES:
Collections on note receivable		—			27,295
Proceeds from sale of assets		328,466			13,785,812
Expenditures for oil and gas properties		(25,080,332	)		(17,531,269	)
Expenditures for property and equipment		(93,244	)		(130,252	)


Net cash used for investing activities		(24,845,110	)		(3,848,414	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		—			69,000
Deferred financing cost		—			(850,000	)
Financing costs paid		(1,491,976	)
Proceeds from issuance of warrant derivative liability		2,000,000
Proceeds from notes payable		47,043,307			—
Payments on notes payable		(14,874,933	)		(5,054,802	)


Net cash provided (used) by financing activities		32,676,398			(5,835,802	)


NET CHANGE IN CASH		(6,876,568	)		6,847,711
CASH, BEGINNING OF YEAR		7,885,652			1,037,941


CASH, END OF YEAR	$	1,009,084		$	7,885,652

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	$	4,044,987	$	434,056
Income Taxes		212,396		212,272


Non-cash investing and financing activities
Accrued expenditures for oil and gas properties		259,017		1,235,881
Increase in asset retirement obligation		112,667		16,229
Reclass from accrued expenses to notes payable		—		725,000
Accrued expenditures for debt refinancing		—		350,000
Interest added to loan		—		1,245,696

See notes to consolidated financial statements.

F-8

TRANS ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

NOTE 1 – RESTATEMENT TO CERTAIN QUARTERLY UNAUDITED INFORMATION

The aforementioned accounting error represent non-cash, items that result in the understatement of warrant derivative liabilities, overstatement of stockholders’ equity and under/overstatement of other income (expense) for the periods ended June 30, 2012 and September 30, 2012, as noted in the table below. The Company appropriately accounted for the Warrants as of, and for the period ended, December 31, 2012.

F-9

Summary effects of restatement on unaudited quarterly periods

The following tables set forth the effects of the restatement on the Company’s previously reported Unaudited Quarterly Consolidated Financial Statements for the period ended June 30, 2012 and September 30, 2012.


	As of
	June 30, 2012						September 30, 2012
Unaudited Quarterly Information	As Previously Reported			As Restated			As Previously Reported			As Restated
Consolidated Balance Sheets
Warrant Derivative Liability	$	0		$	1,156,660		$	0		$	1,219,683
Total Liabilities		50,768,194			51,924,854			50,528,447			51,748,130
Shareholders’ Equity		26,249,913			25,093,253			23,260,533			22,040,850

	Three Months Ended
	June 30, 2012						September 30, 2012
Unaudited Quarterly Information	As Previously Reported			As Restated			As Previously Reported			As Restated
Consolidated Statements of Operations
Gain (Loss) on Derivatives	$	0		$	843,340		$	0		$	(63,023	)
Total Other Income (Expenses)		(1,426,154	)		(582,814	)		(1,655,966	)		(1,718,989	)
Net (loss)		(2,713,761	)		(1,870,421	)		(3,506,749	)		(3,569,772	)
Per share amounts:
Basic earnings (loss) per share	$	(0.21	)	$	(0.14	)	$	(0.27	)	$	(0.27	)
Diluted earnings (loss) per share		(0.21	)		(0.14	)		(0.27	)		(0.27	)

	Six Months Ended						Nine Months Ended
	June 30, 2012						September 30, 2012
Unaudited Quarterly Information	As Previously Reported			As Restated			As Previously Reported			As Restated
Consolidated Statements of Operations
Gain on Derivatives	$	639		$	843,979		$	639		$	780,956
Total Other Income (Expenses)		(1,857,066	)		(1,013,726	)		(3,513,033	)		(2,732,716	)
Net (loss)		(4,210,229	)		(3,366,889	)		(7,716,979	)		(6,936,662	)
Per share amounts:
Basic earnings (loss) per share	$	(0.32	)	$	(0.26	)	$	(0.59	)	$	(0.53	)
Diluted earnings (loss) per share		(0.32	)		(0.26	)		(0.59	)		(0.53	)

F-10

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Organization

Trans Energy is an independent energy company engaged in the acquisition, exploration, development, 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, American Shale Development, 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 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, 2012 and December 31, 2011 by management and no bad debt expense was incurred during the years ended December 31, 2012 and 2011.

F-11

Financing Cost

In connection with obtaining new financing in April 2012, the Company incurred $1,741,975 in fees during the second and third quarter of 2012. These fees were recorded as financing costs and are being amortized over the life of the loan using the straight-line method, which approximates the effective interest method. Amortization of financing cost for the twelve months ended December 31, 2012 and 2011 were $640,024 and $712,500, respectively. Deferred financing costs related to the CIT debt have been fully amortized.

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.

In 2012, the Company determined fair market value of the assets held in American Shale Development, Inc. using the income approach based upon the properties’ discounted estimated future net cash flows, which is considered a level 3 input. We determined the fair market value of other assets held in Trans Energy, Inc. to be the sales price negotiated with an independent buyer because the sale was completed in January 2013. The Company wrote down oil and gas properties by $10,132,702 in 2012 based upon the sales price.

F-12

In 2011, the Company determined 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 in prices than anticipated.

Derivatives

Derivatives and embedded derivatives, if applicable, are measured at fair value and recognized in the consolidated balance sheet as an asset or a liability. Derivatives are classified in the balance sheet as current or non-current based on whether net-cash settlement is expected to be required within 12 months of the balance sheet. The changes in the fair value of the derivatives are included in other income (expense) on the consolidated statement of operations. The pricing models used for valuation often incorporate significant estimates and assumptions, which may impact the level of precision in the financial statements.

The Company has determined that the warrant and related put option issued for one of its wholly-owned subsidiaries is a derivative liability. The Company also enters into derivative commodity contracts at times to manage or reduce commodity price risk related to its production. Usually these commodity contracts are not designated as a hedge, so changes in the fair value are recognized in other expense.

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:


	2012		2011
Asset retirement obligations at beginning of period		256,651	$	219,478
Liabilities incurred during the period		3,849		16,229
Accretion expense		47,004		20,944
Liability revisions		108,818		—


Asset retirement obligations at end of period		416,322	$	256,651

F-13

At December 31, 2012 and 2011, the Company’s current portion of the asset retirement obligation was $0. In addition, $388,005 and $225,083 of asset retirement obligations are reported as liabilities held for sale as of December 31, 2012 and 2011, respectively (see Note 7).

The revisions in the 2012 estimated liabilities is the result of changes in numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, and timing of retirement.

Income Taxes

At December 31, 2012, the Company had net operating loss carry forwards (NOLs) for future years of approximately $16.7 million. These NOLS will expire at various dates through 2032. The current tax provision of $214,000 for the year ended December 31, 2011 was an estimate of the alternative minimum tax that will not be offset by the NOLs. The current tax benefit of $58,013 for the year ended December 31, 2012, was based on the actual alternative minimum tax paid for 2011. 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.

The Company has no material unrecognized tax benefits. No tax penalties or interest expense were accrued as of December 31, 2012 or 2011 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 2008 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 11 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 customer’s meter. Trans Energy recognizes oil revenues when pumped and metered by the customer. Trans Energy recognized $11,356,626 and $14,293,883 in oil and gas revenues in 2012 and 2011, 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, 2012 and December 31, 2011. Costs associated with production are expensed in the period incurred.

F-14

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 $323,395 and $360,358 of transportation revenue in 2012 and 2011, 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.

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 $1,143,988 and $467,988 for the years ended December 31, 2012 and 2011, respectively. Compensation expense related to stock awarded was $687,710 and $507,101 for the years ended December 31, 2012 and 2011, 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. All stock options were anti-dilutive for 2012 and portions of 2011. For the year ended December 31, 2011, assumed exercise of stock options had the effect of adding 744,257 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,
	2012			2011
Numerator:
Net (loss) income applicable to common shareholders	$	(21,203,604	)	$	8,926,676


Denominator:
Weighted average shares—basic		13,074,208			12,807,964


Weighted average shares—diluted		13,074,208			13,552,221


Total earnings per share—basic	$	(1.62	)	$	0.70


Total earnings per share—diluted	$	(1.62	)	$	0.66

F-15

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.

Trans Energy believes that the fair value of its financial instruments comprising cash, certificates of deposit, accounts receivable, note receivable, accounts payable and notes payable approximate their carrying amounts. The interest rates payable by Trans Energy on its notes payable approximate market rates. The fair value of Trans Energy’s level 3 financial assets consist of derivative assets, which are based on quoted commodity prices of the underlying commodity market approach.

The following table summarizes fair value measurement information for Trans Energy financial assets and liabilities:


	As of December 31, 2012
					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)

Derivative Assets	$	—	$	—	$	—	$	—	$	—

Derivative Liability	$	2,808,278	$	2,808,278	$	—	$	—	$	2,808,278

Derivative Fair Value (Loss) Income

The following table presents a summary of changes in the fair value of the Company’s Level 3 liabilities for 2012.


	As of December 31, 2012
Beginning balance	$	—
Sale of puttable warrant		2,000,000
Change in fair value		808,278


Ending balance	$	2,808,278

New Accounting Standards

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.

F-16

NOTE 3 – OPERATIONS

Trans Energy has incurred cumulative operating losses through December 31, 2012, of $33,071,173. Although the prior year revenues have not been sufficient to cover our operating costs and interest expense, we are focusing on increasing operating revenues by selling the shallow wells owned by the Company in January 2013. The Company is focusing on drilling Marcellus Shale wells which based upon projections, are expected to increase cash flow. Also in February 2013, the company obtained additional financing in the amount of $25 million to be used for capital expenditures.

NOTE 4 – ACCOUNTS RECEIVABLE DUE FROM NON-OPERATORS AND ACCOUNTS PAYABLE DUE TO DRILLING OPERATOR

Trans Energy was the drilling operator for wells drilled on behalf of other companies in which Trans Energy owns a working interest. As of December 31, 2011, Trans Energy was owed by third parties for drilling costs to be reimbursed in the amount of $1,754,020.

In 2012, another owner became the drilling operator for wells in which Trans Energy owns a working interest. As of December 31, 2012, Trans Energy owed the drilling operator $839,456 for charges incurred, but not paid.

NOTE 5 – PROPERTY AND EQUIPMENT

At December 31, 2012 and 2011, property and equipment consisted of:


	2012			2011
Buildings	$	—		$	—
Vehicles		140,768			136,090
Machinery and equipment		123,402			123,402
Roadways		—			—
Furniture and fixtures		227,334			184,139
Leasehold improvements		30,696			30,696
Land		382,951			382,951
Accumulated depreciation		(239,277	)		(201,214	)


Total fixed assets	$	665,874		$	656,064

Total additions for property, plant and equipment for the years ended December 31, 2012 and 2011 were $93,244 and $130,252, respectively. Depreciation, depletion and amortization expenses for property and equipment were $214,964 and $197,374 for the years ended December 31, 2012 and 2011, respectively. As noted below, certain property and equipment met the requirements to be classified as assets held for sale as of December 31, 2012: therefore, $986,232 of cost and $694,923 of accumulated depreciation related to the property sold was reclassified to the Other Asset section of the Balance Sheet (See note 7).

F-17

NOTE 6 – OIL AND GAS PROPERTIES

Total additions for oil and gas properties for the year ended December 31, 2012 and 2011 were $24,216,129 and $16,124,574, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $3,563,599 and $5,368,176 for the years ended December 31, 2012 and 2011, respectively. For 2012, the Company recorded an impairment of $10,132,702 to write down oil and gas properties related to its shallow wells to the fair market value of approximately $2,625,000 of net cash proceeds. As noted below, the shallow wells met the requirements to be classified as assets held for sale as of December 31, 2012; therefore, $22,107,091 of cost and $19,385,400 of accumulated depletion was reclassified to the Other Asset section of the Balance Sheet (See note 7).

NOTE 7 – ASSETS AND LIABILITIES HELD FOR SALE

The $3,013,000 of assets held for sale relate to the shallow well properties located in West Virginia. This amount includes property and equipment sold which was used to maintain the shallow wells. These wells were sold because we are redirecting our focus from the operation of shallow wells to drilling deep wells in the Marcellus Shale. Assets held for sale are measured at the lower of their carrying amount prior to classification of the group of assets as held for sale and the fair value less costs to sell.

Liabilities held for sale are the asset retirement obligations associated with the shallow wells that are being sold.

NOTE 8 – 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 pro rata across the Company’s acreage. Proceeds from this transaction were used to repay $5 million to CIT in April 2011, with the remainder being used to partially fund the drilling and completion expenses for certain wells.

NOTE 9 – PROVISION FOR TAXES

The Company’s income tax (benefit) provision is as follows:


	2012			2011
Current:	$	(58,013	)	$	214,000
Deferred:
Change in Depreciation, depletion and amortization	$	(1,737,000	)	$	(1,645,000	)
Unrealized loss on derivative		(275,000	)		—
Change in other items		(29,000	)		49,000
Change in NOL		(3,564,000	)		2,478,000
Increase in AMT credit		58,000			(214,000	)
Change in valuation allowance		5,547,000			(668,000	)


Total	$	(58,013	)	$	214,000

The income tax benefit of $58,013 for 2012 and provision of $214,000 for 2011 represents a current tax that is for alternative minimum tax (AMT) related to the 2011 sale 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, 2012 and 2011 primarily due to the utilization of NOL carryforwards, expense related to stock options, intangible drilling costs, availability of AMT credit carryforwards, and the valuation allowance.

F-18

At December 31, 2012, Trans Energy had net operating loss carryforwards of approximately $16.7 million that may be offset against future taxable income from 2013 through 2032. Except for an over accrual adjustment, no tax benefit has been reported in the December 31, 2012 and 2011 consolidated financial statements since the potential tax benefit is offset by a valuation allowance of the same amount.

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, 2012 and 2011:


	2012			2011
Deferred tax assets:
NOL carryover	$	5,682,000		$	2,118,000
AMT Credit		606,000			664,000
Unrealized loss on derivative contract		275,000			—
Other		142,000			113,000


Total deferred tax assets		6,705,000			2,895,000
Deferred tax liabilities:
Depreciation, depletion and amortization		(552,000	)		(2,289,000	)


Total deferred tax liabilities		(552,000	)		(2,289,000	)
Valuation allowance		(6,153,000	)		(606,000	)


Net deferred taxes	$	—		$	—

NOTE 10 – NOTES PAYABLE

On September 22, 2007, Trans Energy finalized a financing agreement with CIT Capital USA Inc. (“CIT”) for $30,000,000.

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

The Company worked 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 the sale of certain assets. Then the Company repurchased its net profit interest from CIT with the $1,780,404 purchase price added to the outstanding balance. Amendment fees and interest totaling $539,835 were added to the principal in 2010, resulting in a balance of $17,320,239 due to CIT as of December 31, 2010. 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. The $725,000 of forbearance fees were included in accrued expenses at December 31, 2010.

On March 31, 2011, the Company and CIT entered into the Sixth Amendment to the Credit Agreement. The Sixth Amendment and other related agreements extended the maturity date of the Credit Agreement to March 31, 2012. The Sixth Amendment confirmed 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 forbearance fees of $725,000 were

F-19

added to the principal balance. Thus, the total amount owed under the Credit Agreement, as per the Sixth Amendment, was $18,184,978. 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. During the first quarter of 2012, the Company added $557,226 of interest, legal and administrative expense to the loan balance. On April 2, the Company paid $125,000 on the principal amount outstanding and the remainder of the principal was paid with proceeds received from the American Shale Development, Inc. Credit Agreement.

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 and Lucey #1H wells, as well as a 1.5% overriding royalty interest in the next three 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. CIT still retains ownership of the 1.5% overriding royalty interest after the payoff.

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

On April 26, 2012, (“Funding Date”), our newly created, wholly owned subsidiary, American Shale Development, Inc. (“American Shale or ASD”), closed a Credit Agreement transaction (hereafter the “ASD Credit Agreement”) that was entered into by and among American Shale, several banks and other financial institutions or entities that from time-to-time will be parties to the ASD Credit Agreement (the “Lenders”), and Chambers Energy Management, LP as the administrative agent (“Agent”). Trans Energy is a guarantor of the ASD Credit Agreement, as is Prima Oil Company, Inc. (“Prima”), another of our 100% wholly owned subsidiaries. The ASD Credit Agreement provides that Lenders will lend American Shale up to $50 million, which funds will be used to develop wells and properties that we have transferred to American Shale. Trans Energy received a portion of the funds from the ASD Credit Agreement to repay CIT and certain outstanding debts.

In order to accommodate the terms of the ASD Credit Agreement we have transferred certain assets and properties to American Shale. Trans Energy is not a direct party to the ASD Credit Agreement, but is a guarantor of loans to be made thereunder and has received a portion of the loan proceeds to repay certain outstanding debts. The assets and properties transferred are referred to herein as the “Marcellus Properties,” which consist of working interests in 13 gross (7.60 net) producing Marcellus shale liquids-rich gas wells and approximately 22,000 net acres of Marcellus shale leasehold rights, located in Northwestern West Virginia in the counties of Wetzel, Marshall, Marion, Tyler, and Doddridge.

The ASD Credit Agreement is for a notional amount of $50 million, which was received at closing net of a $3 million Original Issue Discount (OID) and a $50,000 administrative fee. These OID costs are netted against Notes Payable and are being amortized over the life of the loan using the straight-line method, which approximates the effective interest method. $705,882 of the OID was amortized as interest expense for the twelve months ended December 31, 2012. The administrative fee is due annually. Interest is due monthly at 10% plus the greater of 1% or the 3 month LIBOR rate (11% at December 31, 2012). Principle is due at maturity, February 28, 2015.

The ASD Credit Agreement is collateralized by American Shale’s natural gas and oil reserves and is guaranteed by Trans Energy. The ASD credit agreement includes reporting, financial and other restrictive covenants, as well as a contingent interest provision that adds 1% of the outstanding principal amount of the Loan to the loan balance for any quarter in which American Shale’s Consolidated Leverage Ratio exceeds certain levels, as defined in the ASD Credit agreement. ASD’s Consolidated Leverage Ratio exceeded the allowed level at September 30, 2012. Therefore, the contingent interest provision has been applied which is equal to 1% of the outstanding principal amount of the Loan at the beginning of such fiscal quarter, and $500,000 was added to the principal balance and interest expense. The ASD consolidated leverage ratio exceeded the allowed level at December 31, 2012. Therefore, the contingent interest provision will be added in the amount of $500,000 in April 2013. The Company has to pay interest through April 26, 2014, on any principal prepayments prior to April 26, 2014, at the time of the prepayment.

As of December 31, 2012 and December 31, 2011, the Company owed $39,791 and $33,529, respectively, for other loans, primarily for vehicles.

F-20

NOTE 11 – DERIVATIVE AND HEDGING FINANCIAL INSTRUMENTS

Pursuant to ASC 480-10-25-8 through 25-12, Derivatives and Hedging Activities, as amended, establishes accounting and reporting standards for derivative instruments. As a part of the ASD Credit agreement, the Company entered into a warrant agreement with Chambers (Lender) which required American Shale to sell the Lenders for a total of $2 million a warrant for 19,500 shares representing 19.5% of ASD’s stock at $263.44 per share. The warrant expires on February 28, 2015. The warrant includes a put option whereby the Lender could require ASD to repurchase the warrant as of February 28, 2015, or earlier if certain events occur which is in accordance with the credit agreement. Under the put option, ASD would pay the excess of the fair market value per share of the stock over $263.44 times the number of shares exercisable less any distributions are similar payments defined by the agreement ASD has the option to transfer working interest in all of its wells equal to the value of the excess value instead of paying in cash.

The embedded derivative is recoded at fair value and reported as a Long-Term Liability on the Consolidated Balance Sheet with the change in fair value recoded in the Consolidated Statements of Operations in Other Income (Expenses). The loss on the change in fair value of the embedded warrant amounted to $808,278 at December 31, 2012. As of December 31, 2012, the Embedded Warrant Liability had a fair value of $2,808,278.

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 for the year ended December 31, 2011. Trans Energy received proceeds of $236,532 relating to settlements of its derivative instruments for the year ended December 31, 2011.

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 12 – 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.

F-21

On April 8, 2009, Trans Energy granted 375,000 common stock options to four key employees under the long term incentive bonus program. As of March 31, 2010, these options have been fully expensed. In June 2011, 50,000 of these options were exercised.

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 fair market value of the common stock at the date of grant and will be amortized to compensation expense over three years. During 2012 and 2011, we recorded $127,500 and $100,500 respectively, of share based compensation related to these shares. Of the 2012 expense $54,000 was related to the approved severance agreements, see Note 14.

In December 2010, Trans Energy granted 368,000 common stock options to eight 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 over the vesting period. During 2012 and 2011, we recorded $282,174 and $228,494 respectively of share based compensation related to these options. $107,364 of the 2012 expense was related to the approved severance agreements, see Note 14. In June 2011, 36,000 of these options have been cancelled.

The following are assumptions made in computing the 2011 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 common 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 over three years. During 2012 and 2011, we recorded $469,000 and $375,200 respectively of share-based compensation expense related to these shares. $160,800 of the 2012 expense was related to the approved severance agreements, see Note 14.

In May 2011, Trans Energy also granted 378,000 common stock options to eight employees and four outside board members. These options vest semi-annually over five 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 over the vesting period. During 2012 and 2011, we recorded $260,444 and $217,324, respectively, of share-based compensation expense related to these options. $77,616 of the 2012 expense was related to the approved severance agreements, see Note 14. A total of 30,000 of these options were cancelled/expired due to separation from service.

In December 2011, Trans Energy granted 12,000 shares of common stock to an employee under the long-term incentive bonus program. The 12,000 shares are not performance based and vest semi-annually over a three year period, subject to ongoing employment. These shares were valued at $32,160 using fair market value of the common stock at the date of grant and will be amortized to compensation expense over three years. During 2012 and 2011, we recorded $10,720 and $5,360 respectively of share-based compensation expense related to these shares.

F-22

In December 2011, Trans Energy also granted 36,000 common stock options to an employee. These options vest semi-annually over five 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 over the vesting period. During 2012 and 2011, we recorded $20,698 and $10,349, respectively, of share-based compensation expense related to these options. Another employee purchased 10,000 shares of common stock at $2.00 per common share. The discount of $2,100 was recorded as stock-based compensation.

The following are assumptions made in computing the 2012 option fair value:


Average risk-free interest rate	1.72	%
Dividend yield	0	%
Expected term	5 years
Average expected volatility	77.09	%

Effective April 26, 2012, Trans Energy granted 60,000 shares of common stock to six employees under the long-term incentive bonus program. The 60,000 shares are not performance based and vest semi-annually over a three year period, subject to ongoing employment. These shares were valued at $138,000 using fair market value of the common stock at the date of grant and will be amortized to compensation expense over three years. During 2012, we recorded $46,000 of share-based compensation expense related to these shares.

Effective April 26, 2012, Trans Energy granted 804,000 common stock options to nine employees and four outside board members. These options vest semi-annually over five years and have a five year term. The stock options were granted at an exercise price of $2.30 per common share which was equal to the fair market value of the common stock at the date of the grant and were valued using the Black Scholes valuation model. The model uses key estimates such as estimated useful lives of the options and the estimated volatility of our stock price. The options are being amortized to share-based compensation expense over the vesting period. During 2012 we recorded $349,800 of share-based compensation expense related to these options. As of August, 2012, a total of 18,000 of these options were cancelled due to separation from service.

In June 2012, Trans Energy, due to a severance agreement, granted 150,000 common stock options. These options vested immediately. These options were granted at an exercise price of $2.30 per common share and were valued using the Black Scholes valuation model and similar assumptions as the April, 2012 options. During 2012 we recorded $198,000 of stock compensation expense related to these additional stock options.

In August 2012, Trans Energy granted 30,000 shares of common stock to an outside board member under the long-term incentive bonus program. The 30,000 shares are not performance based and vest semi-annually over a three year period, subject to ongoing employment. These shares were valued at $52,500 using fair market value of the common stock at the date of grant and will be amortized to compensation expense over three years. During 2012, we recorded $8,750 of share-based compensation expense related to these shares.

In August 2012, Trans Energy granted 60,000 common stock options to an outside board member. These options vest semi-annually over five years and have a five year term. The stock options were granted at an exercise price of $2.30 per common share which was equal to the fair market value of the common stock at the date of the grant and were valued using the Black Scholes valuation model. The model uses key estimates such as estimated useful lives of the options and the estimated volatility of our stock price. The options are being amortized to share-based compensation expense over the vesting period. During 2012 we recorded $13,200 of share-based compensation expense related to these options.

F-23

In December 2012, Trans Energy granted 9,900 shares of common stock to seventeen employees under the long-term incentive bonus program. The 9,900 shares are vested immediately and the shares were valued using fair market value of the common stock at the date of grant. During 2012, we recorded $25,740 of share based compensation related to these shares.

In August 2006, Trans Energy granted 800,000 common stock options to two employees with an expiration date of August 16, 2011. Trans Energy extended those options in September 2011 to August 16, 2012. Trans Energy recorded $11,831 of additional stock-based compensation in September 2011 related to the one year extension. In 2012 Trans Energy extended these options to August 16, 2014 due to provisions of severance agreements. We recorded an additional stock based compensation in December 2012 of $19,672 related to this two year extension.

Due to severance agreements, effective in April 2012, certain employees became vested 100% on their stock options and stock awards, we recorded an additional $597,536 of share-based compensation expense for accelerating the vesting of these stock options and stock awards.

As a result of the above stock and option transactions, Trans Energy recorded total share-based compensation of $1,831,698 and $975,099 for the twelve months ended December 31, 2012 and 2011, respectively.

A summary of the status of the options granted under various agreements at December 31, 2012 and 2011, and changes during the years then ended is presented below:


	December 31, 2012					December 31, 2011
	Weighted Average Exercise					Weighted Average Exercise
	Shares			Price		Shares			Price
Outstanding at beginning of year		2,674,324		$	1.59		2,871,324		$	1.37
Granted		1,014,000			2.30		414,000			2.68
Exercised		—			—		(50,000	)		0.98
Forfeited		(33,000	)		2.47		(411,000	)		1.06
Expired		(15,000	)		2.68		(150,000	)		0.65


Outstanding at end of year		3,640,324		$	1.76		2,674,324		$	1.59

A summary of the status of the options granted under various agreements at December 31, 2012 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
$ 2.30		996,000		4.50 years	$	2.30		422,000	$	2.30
$ 3.00		332,000		2.77 years	$	3.00		302,667	$	3.00
$ 2.75		125,000		2.48 years	$	2.75		125,000	$	2.75
$ 0.98		200,000		1.27 years	$	0.98		200,000	$	0.98
$ 0.82		200,000		0.01 years	$	0.82		200,000	$	0.82
$ 0.65		800,000		1.60 years	$	0.65		800,000	$	0.65
$ 2.68		384,000		3.50 years	$	2.68		280,000	$	2.68
$ 0.98		50,000		1.37 years	$	0.98		50,000	$	0.98
$ 1.50		553,324		2.04 years	$	1.50		553,324	$	1.50


		3,640,324						2,932,991

F-24

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,		Exploration and Production			Pipeline Transmission		Corporate			Total
Revenue		2012	$	11,356,626		$	323,395	$	75.400		$	11,755,421
		2011	$	14,293,883		$	360,358	$	66,992		$	14,721,233
Income (Loss) from operations		2012		(9,065,844	)		172,146		(5,840,252	)		(14,733,950	)
		2011		16,025,801			351,020		(5,606,855	)		10,769,966
Interest expense		2012		5,738,803								5,738,803
		2011		1,679,276			—		—			1,679,276
Depreciation, depletion, amortization and accretion		2012		3,778,242			321					3,778,563
		2011		5,556,435			9,244		—			5,565,679
Property and equipment acquisitions, including oil and gas properties		2012		24,309,374								24,309,374
		2011		13,817,963			—		—			13,817,963
Total assets, net of intercompany accounts:
December 31, 2012				62,408,692			29,769					62,438,461
December 31, 2011				57,994,415			231,202		—			58,255,817

NOTE 14 – RELATED PARTY TRANSACTIONS

Employment separation agreements were executed between the Company and Messrs. Loren Bagley, Mark Woodburn and William Woodburn on June 26, 2012. Messrs. Loren Bagley, Mark Woodburn and William Woodburn are collectively referred to as the parties. Messrs, Loren Bagley and William Woodburn remain on the Company’s Board of Directors. Mr. Mark Woodburn is a beneficial owner of the Company.

In consideration of the execution of the severance agreement, the parties received cash compensation of $50,000 each net of taxes. The Company also agreed to immediately vest all unvested stock options and waive the 90 day termination language in current stock option agreements. $184,736 of share-based compensation was recorded during the 2nd quarter of 2012 for accelerating the vesting of these stock options. The Company also agreed to immediately vest and issue all unvested stock awards which increased share-based compensation expense by an additional $214,800. In June 2012, Trans Energy, due to a severance agreement, granted 150,000 common stock

F-25

options. These options vested immediately. These options were granted at an exercise price of $2.30 per common share and were valued using the Black Scholes valuation model and similar assumptions as the April, 2012 options. The Company recorded $198,000 of stock compensation expense in the third quarter related to these additional stock options.

As described in Note 5, of the 2010 Form 10K, Republic Energy Ventures, LLC (Republic) withheld 20% of the purchase price on certain acreage not subject to pooling provisions to ensure that pooling provisions would be added to the leases. This acreage belonged to Sancho Oil and Gas which is wholly owned by Loren Bagley a board member. During 2012, Republic paid Trans Energy $274,948 for the remaining 20% and Trans Energy than remitted $213,093 to Sancho Oil and Gas for the amount for the 20% which Sancho previously owned on the leases.

NOTE 15 – ECONOMIC DEPENDENCE AND MAJOR CUSTOMERS

Trans Energy, Inc. has nine customers for the year ended December 31, 2012 and nine customers for the year ended December 31, 2011 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 $36,990 for 2012 and $60,701 for 2011

As described in Note 11, 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 the Trans Energy is able to purchase the gas for redelivery (resale) to its customers.

NOTE 17 – SUBSEQUENT EVENTS

Trans Energy sold wells and farmed out drilling rights related to its shallow well assets in a transaction that closed on Thursday, January 24, 2013.

Trans Energy sold its working interest in all of its existing shallow wells, but retained an overriding royalty interest of approximately 2.5% on most of the wells. The purchaser assumed the role of operator with respect to approximately 300 wellbores, and intends to commence a workover program with respect to a number of the existing wells. The wells produced at a rate of approximately 800 mcfe per day as of December 31, 2012, which was the effective date for the transaction. As of the December 31, 2011 reserve report, these wells had proven reserves of 2.5 Bcfe.

Additionally, Trans Energy granted the purchaser (the “shallow operator”) the right to drill wells in or above conventional shallow Devonian formations, for leases where Trans Energy currently holds rights to such depths. Trans Energy did not farm out any of its rights to drill in deeper formations such as the Rhinestreet, Marcellus or Utica. Trans Energy retained up to a 5% overriding royalty interest on any such wells drilled, depending on the net revenue interest.

F-26

Trans Energy retained rights to ensure that production either commences or continues, if necessary to maintain its existing leasehold. Additionally, Trans Energy has the right to participate in up to 20% of any well drilled by the shallow operator, unless the shallow operator fails to fulfill its development commitments, in which case Trans Energy can participate in up to 50% of each well. This participation right can be invoked on any well, and the failure to participate in any well will not impact Trans Energy’s future participation rights.

In order for the buyer to earn acreage on leases that are not currently HBP, the buyer is required to commit to drilling such acreage on a semiannual basis as part of a development program. Trans Energy can choose the drilling locations for these development programs, and the company intends to ensure that the buyer drills shallow wells on certain leases that are not currently HBP and in which Trans Energy’s subsidiary, American Shale Development, retains its rights to drill in deeper prospective formations, including the Marcellus. Both parties have prioritized a list of leases that they intend to convert to HBP status in this manner. These leases represent more than 3,500 acres net to the interest of American Shale Development, which could potentially be converted to HBP status by drilling shallow wells.

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, 2012 and 2011, 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 2. 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. Because the Company uses year-end reserves and adds back current quarter production to calculate fourth quarter depletion expense, adoption of these new standards had an impact on fourth quarter 2009 DD&A expense.

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.

F-27

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,
	2012			2011
Proved oil and gas producing properties and related lease, wells and equipment	$	69,270,310		$	49,723,104
Unproved Oil and Gas Properties		13,963,619			9,507,789
Accumulated Depreciation, Depletion and Amortization		(28,194,422	)		(14,545,126	)


Net Capitalized Costs	$	55,039,507		$	44,685,767

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,
	2012		2011
Acquisition of Properties
Proved			$	—
Unproved		4,477,833		4,882,438
Exploration Costs				—
Development Costs		19,528,207		11,242,136


Total Costs Incurred		24,006,040	$	16,124,574

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,
	2012			2011
Sales	$	11,356,626		$	14,293,883
Production Costs (a)		(6,624,423	)		(3,314,707	)
Depreciation, Depletion and Amortization		(3,778,563	)		(5,565,679	)
Income Tax Benefit (Expense)		58,013			(214,000	)


Total Results of Operations for Producing Activities (b)	$	1,011,653		$	5,199,497

(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, impairment of fixed 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

F-28

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.

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


	As of December 31,
	2012									2011
	Oil (BBL)			Gas (MCF)			NGL (BBL)			Oil (BBL)			Gas (MCF)			NGL (BBL)
Proved Reserves:
Beginning of the period		163,906			16,695,133			559,389			372,769			12,791,642			—
Revisions of previous estimates		(20,749	)		838,105			224,307			(198,659	)		4,559,552			—
Extensions and discoveries		6,740			29,356,710			976,248			5,672			2,713,069			595,505
Improved recovery
Production		(16,162	)		(2,950,943	)		(110,071	)		(15,876	)		(3,369,131	)		(36,116	)
Purchases of minerals in place		—			—			—			—			—			—
Sales of minerals in place		—			—			—			—			—			—


End of period		133,735			43,939,005			1,649,873			163,906			16,695,132			559,389


Proved Developed Reserves, End of Year		129,468			28,072,921			1,037,577			163,906			16,695,133			559,389

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, 2012 and 2011 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,
	2012			2011
Future Cash Inflows	$	212,933,565		$	124,209,995
Future Production Costs (a)		(80,504,937	)		(35,128,834	)
Future Development Costs		(18,845,514	)		—
Future Income Tax Expense		(22,716,623	)		(17,816,232	)
Future Net Cash Flows		90,866,491			71,264,959
Discounted for Estimated Timing of Cash Flows		56,571,491			38,262,929


Standardized Measure of Discounted Future Net Cash Flows	$	34,295,000			33,002,000

(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 on current year-end economic conditions.

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 2012 used in the above table were gas $2.76 per MMBTU, oil $94.71 per BBL and natural gas liquids $34.00 per BBL. The prices used for 2011 were gas $4.24 per MMBTU, oil $89.73 per BBL and natural gas liquids $48.65 per BBL.

F-29

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,
	2012			2011
Standardized Measure, Beginning of Year	$	33,002,000		$	21,590,000
Oil and gas sales, net of production costs		(5,187,428	)		(10,979,176	)
Changes in prices and future production		(1,430,105	)		145,458
Extensions, discoveries and improved recovery, net of costs		20,268,426			5,920,873
Purchases and Sales of Minerals in place		—			—
Change in estimated future development costs		(18,845,514	)		(5,550,000	)
Previously estimated development costs incurred		—			5,550,000
Revisions of previous quantity estimates		2,609,337			14,742,791
Accretion of Discount		3,300,200			2,159,000
Net change in income taxes		(4,900,391	)		(6,468,496	)
Timing and Other		5,478,475			5,891,550


Standardized Measure, End of Year	$	34,295,000		$	33,002,000

F-30