Edgar Filing: TRANS ENERGY INC

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Accelerated filer

Non-accelerated filer

¨ (Do not check if small reporting company)

Smaller reporting company

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2013

¨	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, 2013) was $8,453,099 (based on price of $2.80 per share).

The number of shares outstanding of each of the issuer’s classes of common equity, as of May 23, 2014, was 13,619,309 shares.

TRANS ENERGY, INC.

Table of Contents


		Page
PART I
Item 1	Business		1

Item 1A	Risk Factors		5

Item 1B	Unresolved Staff Comments		14

Item 2	Properties		14

Item 3	Legal Proceedings		17

Item 4	Mine Safety Disclosures		19

PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		19

Item 6	Selected Financial Data		20

Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

Item 7A	Quantitative and Qualitative Disclosures About Market Risk		25

Item 8	Consolidated Financial Statements and Supplementary Data		25

Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		25

Item 9A	Controls and Procedures		25

Item 9B	Other Information		26

PART III

Item 10	Directors, Executive Officers, and Corporate Governance		27

Item 11	Executive Compensation		30

Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		32

Item 13	Certain Relationships and Related Transactions and Director Independence		33

Item 14	Principal Accounting Fees and Services		34

PART IV

Item 15	Exhibits and Financial Statement Schedules		35

	Signatures		36

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 oil and natural gas, and, to a lesser extent, the marketing and transportation of natural gas. As of December 31, 2013, we own working interests in approximately 28 wells that have been completed in the Marcellus Shale formation, including 24 horizontal proved developed wells and 4 vertical producing wells. In addition, we also own overriding royalty interests in approximately 300 shallow oil and gas wells in West Virginia, of which 127 are currently active. We also own and operate an aggregate of 19 miles of 6-inch and 4-inch gas transmission lines located within West Virginia in Ritchie and Tyler counties. We also have 48,081 gross acres (17,863 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.

Our business strategy is to economically increase reserves, production and the sale of oil, natural gas, and natural gas liquids 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 since early 2006 have drilled more than 35 wells 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.

Recent Events

On December 20, 3013, our wholly owned subsidiary, American Shale Development, Inc. (“American Shale”), amended its existing credit agreement between the lenders thereto and Chambers Energy Management, LP as the administrative agent (the “ASD Credit Agreement”), to increase the principal amount of the borrowings by $7.5 million. On that same date, American Shale entered into an agreement whereby it agreed to acquire warrants representing 19.5% of its stock from the holders thereof for $9 million. The proceeds from the increased borrowings under the ASD Credit Agreement were used to partially fund the purchase of the warrants from the holders.

On December 13, 2013, the Company and our JV partner, Republic Energy Ventures, LLC (“Republic”), closed a transaction pursuant to a Purchase and Sale Agreement (the “PSA”) dated September 30, 2013. The Company owned 1,114.8 lease acres of the total 4,650 lease acres and leasehold working interests in certain partially completed well sites located in Tyler County, West Virginia. At closing, the Company received cash of approximately $10.6 million out of the total purchase price of $36.3 million, net of holdback. A total of 118.6 lease acres were excluded from the sale (39.8 lease acres net to the Company) due to incurable title defects. An additional 135.5 lease acres (30.7 lease acres net to the Company) were excluded from the sale due to curable title defects. The title defects of the 135.5 lease acres were cured and an additional $0.2 million was due and payable to the Company per the terms of the PSA as of December 31, 2013.

On February 28, 2013, American Shale amended and restated the ASD Credit Agreement in order to facilitate an increase in the principal amount of the borrowings under the ASD Credit Agreement 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.

Drilling Operations

Republic Partners Joint Venture

We drilled seven horizontal wells in 2013 and retained a 50% working interest in six of the wells and approximately a 44% working interest in the remaining well. In 2012, we drilled five horizontal wells and retained a 50% working interest in three of the wells and approximately a 36% working interest in the remaining two wells. In 2011, we drilled six horizontal wells in a joint venture with Republic targeting the Marcellus Shale. Republic retained a 50% working interest in these wells, as permitted by the terms of the joint venture.

Gastar Farm Out

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 12.5% and Gastar’s working interest will be reduced to 37.5%. Republic 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, which includes the farm out to Gastar.


Name	Net WI	Spud Date	Completion Date	Status
Freeland 1H	.50	March 2013	July 2013	Producing
Goshorn 3H	.50	April 2013	June 2013	Producing
Goshorn 4H	.50	May 2013	June 2013	Producing
Freeland 2H	.50	May 2013	July 2013	Producing
Jones 2H	.44	June 2013	Est. 2nd Q 2014	Est. 3rd Q 2014
Beaty 2H	.50	July 2013	November 2013	Producing
Beaty 1H	.50	August 2013	November 2013	Producing
Anderson 5H	.36	January 2012	May 2012	Producing
Anderson 7H	.36	January 2012	May 2012	Producing
Doman 1H	.50	April 2012	October 2012	Producing
Doman 2H	.50	May 2012	October 2012	Producing
Martinez 1H	.42	June 2012	April 2013	Producing
Whipkey 3H	.05	May 2011	June 2011	Producing
Lucey 2H	.05	August 2011	October 2011	Producing
Goshorn 1H	.05	October 2011	January 2012	Producing
Goshorn 2H	.05	November 2011	March 2012	Producing
Dewhurst 110H	.38	December 2011	May 2012	Producing
Dewhurst 111H	.38	December 2011	April 2012	Producing
Stout 2H	.50	August 2010	January 2011	Producing
Groves 1H	.50	September 2010	March 2011	Producing
Keaton 1H	.48	November 2010	March 2011	Producing
Lucy 1H	.50	December 2010	May 2011	Producing
Whipkey 1H	.50	November 2009	May 2010	Producing
Whipkey 2H	.50	November 2009	April 2010	Producing
Dewhurst 73V	.50	June 2008	July 2008	Producing
Hart 28H	.50	October 2008	April 2009	Producing
Dewhurst 50V	.50	October 2007	November 2007	Producing
Hart 20V	.50	November 2007	March 2008	Producing
Blackshere 101V	1.00	November 2007	December 2007	Producing

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.

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. Approximately 98% of our natural gas is sold to Dominion and the remaining 2% is sold to Sancho. Under our contract with Sancho, we have the right to sell natural gas subject to the terms and conditions of a contract that Sancho originally 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. During 2013 and 2012, Sancho retained their marketing fee and remitted a net amount to us.

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 one oil purchaser, BD Oil Gathering Corporation.

We sell our NGLs to Williams Ohio Valley Midstream, LLC. 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.

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 oil and natural gas 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 oil and natural gas.

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 oil and natural gas 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. 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 oil and natural gas 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, oil and natural gas.

Employees

As of the end of our fiscal year on December 31, 2013, we employed eighteen full-time employees, consisting of five executives and managers, ten marketing, lease acquisition and clerical persons, and three 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 oil and natural gas. We are also involved in pipeline transportation and marketing of oil and natural gas.

Item 1A Risk Factors

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

We have a history of losses and may realize future losses

Our revenues increased approximately 56% during the fiscal year ended December 31, 2013, primarily due to an increase in production volumes and the prices for 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, 2013, our net operating loss carryforward was approximately $54.1 million and our accumulated deficit was approximately $50.8 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 the ASD Credit Agreement, our financial condition and future operations would be severely and negatively affected.

Future capital requirements after 2013 may require additional capital borrowing or selling equity or other 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;

•

unexpected pressure or irregularities in geological formations;

•

shortages of or delays in obtaining equipment and qualified personnel;

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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;

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loss of drilling fluid circulation;

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uncontrollable flows of oil, natural gas and fluids;

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fires and natural disasters;

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

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adverse weather conditions;

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reductions in oil and natural gas prices;

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oil and natural gas property title problems; and

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market limitations for oil and natural gas.

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

We have less experience in drilling wells to the Marcellus Shale (only 29 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 only 29 Marcellus Shale wells since 2010, including limited horizontal drilling and completion experience. Other operators in the Marcellus Shale play may have significantly more experience in the drilling and completion of these wells, including the drilling and completion of horizontal wells. In addition, we have limited information with respect to the ultimate recoverable reserves and production decline rates in these areas. The wells drilled in the Marcellus Shale are primarily horizontal and require more stimulation, which makes them more expensive to drill and complete. The wells 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 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, 2013 and 2012, 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.

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 oil and natural gas 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 drill site 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 Dodd-Frank Act has not been completed, and the timeframes for compliance with rules under the Dodd-Frank Act that are effective remain uncertain. Consequently, it is not possible at this time to determine the full effect that the Dodd-Frank Act and the rules and regulations adopted under the Dodd-Frank 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. Any substituted purchasers may not provide the same level of our revenue in the future for a variety of reasons. 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. 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 $5.00 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

None.

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, 2013 and, 2012, are set forth below:


	As of December 31,
	2013								2012
	Oil and Condensates (BBL)		Natural Gas (Mcf)		NGL (BBL)		Mcfe		Oil and Condensates (BBL)		Natural Gas (Mcf)		NGL (BBL)		Mcfe
Developed Producing		19,073		34,536,168		890,367		39,992,808		126,995		23,716,531		839,524		29,515,645
Developed Non-Producing		—		7,999,999		—		7,999,999		2,473		4,356,390		198,053		5,559,546
Proved Undeveloped		—		—		—		—		4,267		15,866,084		612,296		19,565,462

Total Proved		19,073		42,536,167		890,367		47,992,807		133,735		43,939,005		1,649,873		54,640,653

The increase in proved developed 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 reserve plays. The horizontal lateral exceeds 2,000 feet in length and typically involves multistage fracturing completions.

Proved undeveloped reserves as of December 31, 2012 and 2013 reflect the Company’s net working interest in such reserves that we have both the intent and ability to develop, within five years of initial booking. Our strategy and that of our joint venture partner, Republic, is to maximize potential drilling locations and acreage held by production. As a result, our development plan focuses primarily on drilling probable and possible locations, rather than proved locations. While we plan to fund such capital expenditures with proceeds from new financing that we expect to obtain from a leading financial institution, we are continuing to negotiate the terms of our intended financing and therefore cannot assure its completion. If we obtain such additional financing, we may elect to augment the drilling of probable and possible locations by including the drilling of some proved locations in our five year drilling plan, which would enable us book the reserves associated with those proved locations.

As of December 31, 2012, our proved undeveloped reserves consisted of six gross locations. During 2013, we spent approximately $1.7 million to complete one of these locations, the Martinez #1H, and it is now in the proved developed producing category. With regard to the

other five locations, all of which are in Wetzel and Marshall Counties, we have removed them from the proved undeveloped category as of December 31, 2013 due to uncertainty over the timing of their development, which results from the combination of our development strategy and available financial resources as of that date.

A review of our reserves was conducted as of December 31, 2013 and 2012 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.

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, 2013 and 2012 used in the above table were as follows:


	Oil		Condensates		Natural Gas		NGL
	(BBL)		(BBL)		(MMBTU)		(BBL)
2013	$	96.78	$	81.20	$	3.67	$	35.36
2012	$	94.71	$	81.27	$	2.76	$	34.00

The Company’s gas processing arrangement did not allow for the separation of condensates or NGLs 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 2013 and 2012. See Note 19, 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 to which proved developed reserves are attributed and we own a working interest. Wells are shown on a gross basis.


	As of December 31,
	2013				2012
	Oil		Natural Gas		Oil		Natural Gas
Producing Wells		—		23		31		80
Non-Producing Wells		—		5		—		4
Undrilled Well Locations		—		—		—		6

Total Wells and Well Locations		—		28		31		90

Our total wells reported in 2013 decreased due to the sale of our shallow wells which closed on January 24, 3013.

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 a working interest. Net wells reflect the sum of our working interests in gross wells.


	During the Year Ended, December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		5		2.4		8		3.4		2.0		0.1
Dry		—		—		—		—		—		—
Exploratory Wells
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—

Total		5		2.4		8		3.4		2.0		0.1

The Freeland 1H, Freeland 2h, Goshorn 3H, and Goshorn 4H were drilled in the second quarter of 2013. These wells were completed by the fourth quarter of 2013 and are reflected in the table above. The Martinez 1H was drilled in the second quarter of 2012 and completed in 2013 and is reflected in the table above. The Beaty 1H and Beaty 2H were drilled in the third quarter of 2013, but were not completed until 2014, and are not reflected in the table above.

The Anderson 5H and 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 was not completed until 2013 and is not reflected in the table above under 2012 but is reflected under 2013

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.

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, 2013 and 2012.


	Developed Acres				Undeveloped Acres				Total
	Gross		Net		Gross		Net		Gross		Net
2013		24,099		10,023		23,982		7,840		48,081		17,863
2012		34,800		15,946		25,966		7,230		60,766		23,176

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:


Year Ending December 31,	Expiring Acreage
Year Ending December 31,	Gross		Net
2014		2,295		750
2015		2,766		1,025
2016		8,774		3,013
2017		6,035		1,800
2018		3,999		1,235
2019		108		14
2020		5		3

Total		23,982		7,840

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

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.

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

EQT Corporation

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. On February 25, 2014, the United States Court of Appeals for the Fourth Circuit in Richmond Virginia affirmed the summary judgment motion of the U.S. District Court for the Northern District of West Virginia. At this time we are not aware if the defendant plans any further appeals, including an appeal to the Supreme Court of the United States.

On June 12, 2013, EQT Production Company filed a quiet title action in the Circuit Court of Wetzel County, West Virginia. The action relates to a quiet title action relating to a 1,314 acre lease in Wetzel County, West Virginia known as the Robinson lease. On February 28, 2014, the presiding Judge issued an order granting a motion to stay this case pending appeal of the Blackshere case and the same styled case pending in the U.S. District Court of the Northern District of West Virginia.

On July 18, 2013, we filed an action in the U.S. District Court for the Northern District of West Virginia against EQT Production Company. The action relates to a quiet title action relating to a 1,314 acre lease known as the Robinson lease.

Abcouwer

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 according to 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. Trial date has been set for June 23, 2014.

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 and Loren E. Bagley. 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. Trial date has been set for November 17, 2014.

EPA

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.

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
2013
First Quarter		3.30		2.25
Second Quarter		3.36		2.55
Third Quarter		3.15		2.60
Fourth Quarter		3.95		2.71

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

As of May 23, 2014, there were approximately 413 holders of record of our common stock. This number 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 1,516 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. In addition, provisions of the ASD Credit Agreement restrict our ability to declare dividends. 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. 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 oil and natural gas properties, with interests targeting the Marcellus Shale in West Virginia. We successfully increased our drilling program in 2013 and 2012, adding both natural gas and natural gas liquids reserves to the Company’s 2013 proved developed reserve base and natural gas and oil reserves to the Company’s 2012 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 during 2014 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,
	2013			2012
Total revenues		18,365,558		$	11,755,421
Total costs and expenses		(22,202,993	)		(26,602,269	)
Gain on sale of assets		7,015,950			112,898

Income (loss) from operations		3,178,515			(14,733,950	)
Other expenses		(20,913,866	)		(6,527,667	)
Income tax benefit (expense)		—			58,013

Net loss		(17,735,351	)		(21,203,604	)

The following table is a summary of revenues, volumes, and pricing for the twelve months ended December 31, 2013 and 2012.

Twelve Months Ended December 31, 2013 compared to the Twelve Months Ended December 31, 2012


	Twelve Months Ended December 31,				Increase/
	2013		2012		(Decrease)
Natural gas sales	$	14,580,415	$	7,754,107	$	6,826,308		88.0	%
Oil sales	$	160,583	$	1,012,918	$	(852,335	)	(84.1	%)
Natural gas liquid sales	$	3,433,526	$	2,589,601	$	843,925		32.6	%

Total Oil & Gas Sales	$	18,174,524	$	11,356,626	$	6,817,898		60.0	%
Transportation and other revenue	$	191,034	$	398,795	$	(207,761	)	(52.1	%)

Total revenue	$	18,365,558	$	11,755,421	$	6,610,137		56.2	%
Net Production
Natural gas sales (Mcf)		3,793,457		2,118,350		1,675,107		79.1	%
Oil sales (Bbls)		1,897		11,006		(9,109	)	(82.8	%)
Natural gas liquids (gallons)		4,224,840		3,510,108		714,732		20.4	%
Natural Gas Equivalent ( Mcfe)		4,408,388		2,685,830		1,722,558		64.1	%
Average Sales Price per Unit
Natural Gas (Mcf)	$	3.84	$	3.66	$	.18		4.9	%
Oil (Bbl)	$	84.65	$	92.03	$	(7.38	)	(8.0	%)
Natural gas liquids (gallons)	$	.81	$	.74	$	.07		9.5	%
Natural Gas Equivalent (Mcfe)	$	4.12	$	4.23	$	(.11	)	(2.6	%)

Expenses

All data presented below is derived from costs and production volumes for the relevant period indicated.


	Twelve Months Ended December 31,
	2013		2012
Costs and Expenses Per Mcfe of Production:
Production Expenses	$	1.97	$	2.26
Production Taxes		0.34		0.26
G&A Expenses (Excluding Share-Based Compensation)		1.13		1.52
Non-Cash Shared-Based Compensation		0.28		0.68
Depletion of Oil and Natural Gas Properties		1.28		1.31
Impairment of Oil and Natural Gas Properties		—		3.77
Depreciation and Amortization		0.02		0.08
Accretion of Discount on Asset Retirement Obligation		—		0.02

Total revenues of $18,365,558 for the year ended December 31, 2013 increased $6,610,137 or 56.2% compared to $11,755,421 for the year ended December 31, 2012. The increase in revenue is due to an increase in pricing on natural gas, natural gas liquids, and production volumes. We focused our efforts during 2013 and 2012 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 2014.

Production costs increased $3,448,911 or 50.9% for 2013 as compared to 2012, primarily due to severance and property taxes and 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 increased $1,973,798 or 52.2% for 2013 as compared to 2012, primarily due to higher production volumes and lower year end reserves.

Impairment of oil and gas properties in 2013 decreased by $10,132,702 due to the write down of shallow producing properties in 2012. 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. The Company recorded no impairments of its oil and gas properties for the year ended December 31, 2013.

Selling, general and administrative expense increased $310,717 or 5.2% for 2013 as compared to 2012, due to increased legal and professional fees for the year.

Gain on sale of assets increased by $6,903,052 in 2013 as compared to 2012 as the result of the sale of our assets in Tyler County to Antero Resources Corporation.

Our income from operations for 2013 was $3,178,515 compared to loss of $14,733,950 for 2012. This change is primarily due to the large sale of acreage to Antero and the increase in production revenue in 2013, as well as the oil and gas property impairment recorded for 2012.

Interest expense increased $9,308,816 or 162% for 2013, as compared to 2012 due to a significantly higher loan balance after the refinancing. The average loan balance for 2013 and 2012 was $75,979,762 and $38,699,144 respectively.

Extinguishment/loss on derivative for 2013 was $6,191,722 compared to a loss of $807,639 in 2012. The extinguishment/loss for 2013 was the result of settlement of the warrant derivative liability which was a part of the ASD Credit Agreement. The loss for 2012 was the result of recording the change in the fair value of the put option associated with our warrant derivative liability.

We have accumulated approximately $51.4 million of net operating loss carryforwards as of December 31, 2013, which may be offset against future tax obligations through 2032. 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 $58,013 in income tax benefits in 2012, 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, 2013 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, 2013, we have positive working capital of $65,897 compared to a positive working capital of $2,487,924 at December 31, 2012. This decrease in working capital is primarily attributed to an increase in accounts payable due to drilling operator and an increase in accrued expenses.

During 2013, net cash used by operating activities was $3,760,460 compared to net cash used of $14,707,856 in 2012. This increase in cash flow from operating activities is primarily due to a smaller decrease in accounts payable during 2013 compared to 2012.

We expect our cash flow provided by operations for 2014 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 2013, net cash used for investing activities was $18,266,499 compared to net cash used of $24,845,110 in 2012. The reason for the change was an increase in cash proceeds from acreage sales and increased expenditures for oil and gas properties during 2013 compared to 2012. See notes 6 and 8 to the financial statements for additional information.

During 2013, net cash provided by financing activities was $23,745,707 compared to net cash provided of $32,676,398 in 2012. This change reflects that the Company’s debt increased by a greater amount in 2012 than in 2013. We anticipate meeting our working capital needs with revenues from our ongoing operations and from debt or equity financings.

Inflation

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

Subsequent Events

On May 21, 2014 (“Funding Date”), our wholly owned subsidiary, American Shale, entered into a credit agreement (hereafter the “Credit Agreement”) 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 (the “Lenders”), and Morgan Stanley Capital Group Inc. as the administrative agent (“Agent”). Trans Energy is a guarantor of the Credit Agreement as is Prima, another of our wholly owned subsidiaries. The Credit Agreement provides that the Lenders will lend American Shale up to $200 million, including an initial draw of $102.5 million, a contingent committed amount of $47.5 million and an uncommitted amount of $50 million (the “Loans”). The initial draw under the facility was used primarily to repay all of the outstanding debt under the A&R Credit Agreement with Chambers, as well as to fund certain fees and expenses incurred in connection with the Credit Agreement. (See Note 18, Subsequent Events).

Forward-looking and Cautionary Statements

This report includes forward-looking statements. 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;

•

the risk factors described elsewhere herein; 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, 2013and 2012 and for the fiscal years ended December 31, 2013 and 2012 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 Principal Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of our disclosure controls and procedures as of December 31, 2013, 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, 2013, our disclosure controls and procedures were effective.

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, 2013 based on the criteria framework established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

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

Based on the assessment, our management has concluded that our internal control over financial reporting was effective as of December 31, 2013, and provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles. The results of management’s assessment were reviewed with our Board of Directors.

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, 2013 in conformity with U.S. GAAP.

Changes in Internal Control over Financial Reporting

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

Item 9B Other Information

None.

PART III

Item 10 Directors, Executive Officers, and Corporate Governance

MANAGEMENT

The following table sets forth the names, ages, and offices held by our directors and executive officers:


Name	Age		Position	Director Since
John G. Corp		54	President and Director	February 2005

Loren E. Bagley		72	Director	August 1991

William F. Woodburn		72	Director	August 1991

John S. Tumis (a)		61	Chief Financial Officer\Treasurer	n/a

Robert L. Richards		68	Director	September 2001

Richard L. Starkey		61	Director	June 2011

Stephen P. Lucado		42	Director\Chairman of the Board	June 2011

Josh L. Sherman		38	Director	September 2012

(a)	Mr. Tumis was appointed Treasurer, on April 26, 2012.

Information About Directors and Executive Officer

Background information about the nominees for election to the Board, including information regarding additional experience, qualifications, attributes or skills that led the Board to conclude that the nominee should serve on the Board, is set forth below. There are no family relationships among the nominees or between any nominee and any executive officer of Trans Energy.

John G. Corp, age 54, became a director on February 28, 2005 and was appointed Vice President of Northern Operations in May 2009. Mr. Corp was then appointed to President in July 2010. Mr. Corp has more than 25 years of extensive experience in drilling, production and oilfield service operations in the Appalachian Basin. Prior to joining Trans Energy, Inc., he held various management positions with Belden & Blake Corp. from 1987-2004. He has a BS degree in Petroleum Engineering from Marietta (Ohio) College and is a member of the Society of Petroleum Engineers and the Ohio Oil & Gas Association. Mr. Corp is qualified to serve on our Board due to his significant operational and engineering experience in the oil and gas industry as well as his extensive relationships throughout the industry, particularly within the Appalachian Basin.

Loren E. Bagley, age 72, cofounder, served as our President and CEO from September 1993 to September 2001, at which time he resigned as President and was appointed Vice President. On April 26, 2012, Mr. Bagley resigned his position as Vice President. Mr. Bagley has been actively engaged in the oil and gas business in various capacities for the past thirty years. Prior to becoming involved in the oil and gas industry, Mr. Bagley was employed by the United States government with the Agriculture Department. Mr. Bagley attended Ohio University and Salem College and earned a B.S. Degree. Mr. Bagley’s status as cofounder of the Company, a former senior executive, as well as a current major shareholder provide an excellent background with regard to his nomination as a Director. In addition, he has worked in the oil and gas industry within West Virginia for over 20 years.

William F. Woodburn, age 72, cofounder, served as our Vice President from August 1991 to September 2001, at which time he resigned as Vice President and was appointed Secretary / Treasurer. In January 2006, Mr. Woodburn was named as our Chief Operating Officer. Mr. Woodburn resigned his position as Secretary/Treasurer and Chief Operating Officer on April 26, 2012. Mr. Woodburn has been actively engaged in the oil and gas business in various capacities for the past thirty years. Prior to his involvement in the oil and gas industry, Mr. Woodburn was employed by the United States Army Corps of Engineers for twenty four years and was Resident Engineer on several construction projects. Mr. Woodburn graduated from West Virginia University with a B.S. in civil engineering. Mr. Woodburn’s status as cofounder of the Company, a former senior executive, as well as a current major shareholder provide an excellent background with regard to his nomination as a Director. In addition, he has worked in the oil and gas industry within West Virginia for over 20 years and currently consults on location and pad site development as well as other operational concerns in the oil and gas industry.

Robert L. Richards, age 68, became a director and was appointed President and CEO in September 2001. On February 28, 2004, Mr. Richards relinquished his position as CEO, but remained as a director. From 1982 to the present, he has been President of Robert L. Richards, Inc. a consulting geologist firm with 27 years’ experience in the petroleum industry. He has also served as a geologist with Exxon, exploration geologist with Union Texas Petroleum, and regional exploration manager for Carbonit Exploration, Inc. From 2000 to the present, he has been President and CEO of Derma – Rx, Inc., a formulator and marketer of skin care products. Also, from 1992 to August 2000, Mr. Richards was CEO of Kaire Nutraceuticals, Inc., a developer and marketer of health and nutritional products. Mr. Richards served as Vice President of Continental Tax Corporation from March 1989 to August 1992. He has five and one-half years’ experience in the United States Air Force as an Instructor Pilot. Mr. Richards holds a B.S. degree in geology from Brigham Young University. Mr. Richards has an extensive history with the Company, and has been a long serving Board member as well as a former executive of the Company. His background in petroleum geology as well as his executive experience outside the petroleum industry make him a significant contributor to our Board of directors.

Richard L. Starkey, age 61, became a director on June 29, 2011. He has over 33 years of professional legal experience with an emphasis on oil and gas law. Since 1994, Mr. Starkey has practiced law as a sole practitioner in Parkersburg, West Virginia with an emphasis in oil and gas, real estate and corporate transactions. Mr. Starkey holds a BA degree from the University of Ohio and a Juris Doctor Degree from the University of Cincinnati School of Law. Mr. Starkey has extensive experience in oil and gas law, with a particular experience in the Company’s focus area of West Virginia. As such, he provides a unique skill set to our Board of Directors.

Stephen P. Lucado, age 42, became a director on June 29, 2011 and was elected Chairman of the Board on April 17, 2012. He has over 18 years of professional financial experience. He has been associated with various financial companies and has managed investments in the oil and gas and power industries. Since 2009, Mr. Lucado has served as Senior Managing Director and Founder of Three Oaks Group, specializing in financial advisory to companies in the oil and gas industry. In 2009, he served as interim CFO of Texas American Resources Company in Austin, Texas, an oil and gas exploration and production company. From 2006 to 2008, Mr. Lucado was a director managing an investment portfolio with Z Capital Partners, LLC in Lake Forest, Illinois. Mr. Lucado holds a Bachelor of Arts Degree in history and science from Harvard University and a Master of Business Administration Degree from the University of Chicago. Mr. Lucado’s extensive financial executive experience and contacts within the oil and gas financial community make him very well qualified to serve on our Board.

Josh L. Sherman, age 38, became a director September 4, 2012 and serves as the Chairman of the Audit and Compensation Committees. He has more than 15 years of experience in the oil and gas industry, with an emphasis on financial reporting. He is currently a partner at the energy focused consulting firm, Opportune, LLP, where he leads the firm’s complex financial reporting practice. Mr. Sherman further served as Chairman of the Audit Committee of Voyager Oil and Gas, serving from

November 2010 until that company’s merger in July 2012. Mr. Sherman worked in the audit and global energy markets departments with Deloitte & Touche from January 1997 to August 2002, where he managed the audits of regulated gas and electric utilities, independent power producers and energy trading entities. A Certified Public Accountant and a member of the American Institute of Certified Public Accountants and the National Association of Corporate Directors, Mr. Sherman holds a BBA and a Masters in Accountancy from the University of Texas. Mr. Sherman’s background in complex financial reporting and accounting related consulting as well as his focus on the oil and gas industry make him a key contributor to our Board and provides a skill set that serves our shareholders by assisting the Company in its efforts to deliver the highest quality of financial reporting.

John S. Tumis, age 61, became Chief Financial Officer in April 2011. Mr. Tumis has over 25 years of significant experience in financial and strategic business planning, general accounting and auditing in the oil and gas industry. Mr. Tumis was Vice President of Appalachian Accounting for Triad Hunter, LLC prior to coming to Trans Energy. Mr. Tumis’ past experience includes being Chief Financial Officer for the Triad Energy Corporation. Mr. Tumis was employed by the Belden & Blake Corporation from 1983 to 2001. Mr. Tumis held various financial positions with Belden & Blake including Corporate Controller. Mr. Tumis also managed an operating division for Belden & Blake. Mr. Tumis graduated from Ohio Northern University with a Bachelor of Science degree in accounting and is a certified public accountant. He is a member of the Ohio Society of CPAs, American Society of CPAs and the Council of Petroleum Societies.

SECTION 16(a) BENEFICIAL OWNERSHIP COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers, directors and persons who own more than 10% of the common stock to file initial reports of ownership and changes in ownership with the SEC. To the Company’s knowledge, with respect to the fiscal year ended December 31, 2013, all applicable filings were made.

CORPORATE GOVERNANCE

Code of Ethics. We currently do not have a code of ethics. Following the 2014 Annual Meeting, our Board will consider adopting a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions.

Director Nominations. The Board does not currently have a standing nominating committee nor has it adopted a nominating committee charter. The entire Board currently operates as the nominating committee. There is no formal process or policy that governs the manner in which we identify potential candidates for the Board. Historically, the Board has considered several factors in evaluating candidates for nomination to the Board including, but not limited to, the candidate’s knowledge of the Company and its business, the candidate’s business experience and credentials, and whether the candidate would represent the interests of all our stockholders as opposed to a specific group of stockholders.

Audit Committee. Currently, the audit committee consists of Messrs. Sherman (Chairman), Starkey and Richards. Messrs. Sherman, Starkey and Richards are independent directors within the meaning of Rule 5605(a)(2) of the NASDAQ Stock Market Inc. listing rules. Mr. Sherman, the chairman of the audit committee, serves as the audit committee financial expert. The audit committee examines and reviews, on behalf of the Board, internal financial controls, financial and accounting policies and practices, the form and content of financial reports and statements and the work of the external auditors. The Audit Committee is responsible for hiring, overseeing and terminating the independent registered public accounting firm and determining the compensation of such accountants. The Chief Financial Officer attends the meetings of the Audit Committee by invitation.

Item 11 Executive Compensation

EXECUTIVE COMPENSATION

The following table sets forth information concerning the compensation earned by our principal executive officer and principal financial officer during 2013 and 2012:


Name and Principal Position	Year		Salary		Bonus		Stock Awards (1)		Option Awards (2)		All Other Compensation		Total Compensation
John G. Corp (3) (4)		2013	$	200,554		—	$	152,450	$	249,758	$	14,934	$	617,696
President		2012	$	181,238		—	$	158,000	$	228,437		14,305	$	581,980

John S. Tumis (3)		2013	$	140,250		—	$	42,375	$	43,310	$	5,503	$	231,438
CFO		2012	$	125,308		—	$	29,880	$	33,898	$	5,114	$	194,200

(1)

The amount shown in the table represents the grant date fair value of the restricted stock granted in 2013, computed in accordance with FASB ASC Topic 718. Information regarding assumptions made in valuing the stock awards can be found in Note 12, Stockholders’ Equity, to the consolidated financial statements for the year ended December 31, 2013 included in the Form 10-K.

(2)

The amount shown in the table represents the grant date fair value of the stock options granted in 2013, computed in accordance with FASB ASC Topic 718. The fair value of the stock options awarded was determined using the Black-Scholes option pricing model. Information regarding assumptions made in valuing the option grants under this model can be found in Note 12, Stockholders’ Equity, to the consolidated financial statements for the year ended December 31, 2013 included in the Form 10-K.

(3)	All other compensation relates to the matching 401k contribution by the Company.

(4)	All other compensation includes a housing reimbursement.

No other executive officers received cash compensation greater than $100,000 in any of the past two fiscal years.

We currently have a long-term incentive and bonus program for the benefit of employees and officers of the Company. The program is primarily focused on senior officers, but certain elements of the plan are made available to key managers and to any employee in certain circumstances. In addition, management has established a 401(K) plan for employees and officers of the Company.

Change in Control Termination Agreement

Mr. Corp has a change in control termination agreement. A change of control is defined in the change of control termination agreement to mean when more than 50% of the Company’s common shares are sold to a new owner or a group forming a bloc for the purpose of such investment in ownership.

The Change in Control Termination Agreement provides a severance payment equal to twice the annual salary in the event one of the following occurs subsequent to a change in control of the Company, (1) the new ownership of the Company terminates Mr. Corp’s employment or demotes him in level of responsibility or moves his place of employment (office) more than 30 miles from St. Marys WV during the 12 month period beginning immediately upon the change in control, such termination or demotion not being the result of “good cause”, or (2) Mr. Corp voluntarily ends his employment during the 30-day period immediately following the 12-month period described in (1).

Outstanding Equity Awards at Fiscal Year-End for 2013

The following table sets forth information about outstanding equity awards held by our Named Executive Officer and our Chief Financial Officer as of December 31, 2013:


			Option Awards						Stock Awards
Name	Grant Date		Number of Securities Underlying Unexercised Options Exercisable		Number of Securities Underlying Unexercised Options Unexercisable		Options Exercise Price		Options Expiration Date		Number of Shares of Restricted Stock That Have Not Vested		Market Value of Shares of Restricted Stock That Have Not Vested (1)
John G. Corp (2)		5/14/2009		50,000		—	$	0.98		5/14/2014		—	$	—
		10/7/2010		90,000		—	$	3.00		10/8/2015		—	$	—
		5/26/2011		60,000		—	$	2.68		6/30/2016		—	$	—
		4/26/2012		200,000		100,000	$	2.30		6/30/2017		—		—
		2/13/2013		33,334		66,666	$	2.50		6/30/2018		—		—
John S. Tumis (3)		5/26/2011		36,000		—	$	2.68		6/30/2016		—	$	—
		4/26/2012		20,000		10,000	$	2.30		6/30/2017		6,000	$	23,700
		2/13/2013		6,000		12,000	$	2.50		6/30/2018		6,000	$	23,700

(1)	The closing price of our common stock on December 31, 2013 was $3.95.

(2)

The 100,000 unvested common stock options grant to Mr. Corp on April, 26, 2012 will vest 50% on each of June 30, 2014 and December 31, 2014. The 66,666 unvested stock options granted to Mr. Corp on February 13, 2013 will vest 25% on each of June 30, 2014, December 31, 2014, June 30, 2015 and December 31, 2015

(3)

The 10,000 unvested stock options granted to Mr. Tumis on April 26, 2012 vest 50% on each of June 30, 2014, and December 31, 2014. The 12,000 unvested stock options granted to Mr. Tumis on February 13, 2013 vest 25% on each of June 30, 2014, December 31, 2014, June 30, 2015, and December 31, 2015 The 6,000 unvested restricted common stock shares granted to Mr. Tumis on April 26, 2012 vest 50% on each of June 30, 2014 and December 31, 2014. The 6,000 unvested restricted common stock shares granted to Mr. Tumis on February 13, 2013 vest 25% on each of June 30, 2014, December 31, 2014, June 30, 2015, and December 31, 2015.

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

The following table sets forth information, to the best of our knowledge as May 23, 2014, with respect to each person known by us to own beneficially more than 5% of our outstanding common stock, each director, the CEO and CFO, and all directors and officers as a group. Unless otherwise noted, the address of each person listed below is that of Trans Energy, 210 Second Street, St. Marys, West Virginia 26170.


Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership			Percent of Class (1)
5% Beneficial Owners
James K. Abcouwer, 2006 Kanawha Ave. SE, Charleston, WV 25304		2,256,819	₍₂₎		16.6	%
Mark D. Woodburn		1,362,210	₍₃₎		10.0	%
Clarence E. Smith		1,483,797			10.9	%
Directors and Officers
John G. Corp. *		320,200			2.4	%
Robert L. Richards *		411,498	₍₄₎		3.0	%
Loren E. Bagley *		2,191,246	₍₅₎		16.1	%
William F. Woodburn *		2,253,636	₍₆₎		16.5	%
John S. Tumis *		33,000			<1.0	%
Richard L. Starkey *		30,000			<1.0	%
Stephen P. Lucado *		30,000			<1.0	%
Josh L. Sherman *		15,000			<1.0	%
All directors and executive officers as a group (8 persons)		5,284,580			38.80	%

*	Indicates director and/or executive officer at May 23, 2014.

(1)	Based upon 13,619,309 shares of common stock outstanding as of May 23, 2014.

(2)	Includes 1,287,000 shares of common stock held in the name of the Abcouwer Family Limited Partnership Trust.

(3)	Includes 522,099 shares held in the name of MDW Capital, Inc., of which Mr. Woodburn is the CEO and stockholder, and 397,100 shares in the name of Meredith Woodburn, wife of Mr. Woodburn, which Mr. Woodburn disavows beneficial ownership or voting power.

(4)	Includes 35,087 shares held in the name of Argene Richards, wife of Mr. Richards.

(5)	Includes 33,543 shares held in the name of Carolyn S. Bagley, wife of Mr. Bagley, over which Mrs. Bagley retains voting power, and 803,372 shares in the name of a corporation in which Mr. Bagley is the President and stockholder.

(6)	Includes 333,986 shares in the name of Janet L. Woodburn, wife of Mr. Woodburn, over which shares Mrs. Woodburn retains voting power, and 454,230 in the name of two corporations in which William and Janet Woodburn are officers and stockholders.

EQUITY COMPENSATION PLAN INFORMATION


Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders		—		—		—
Equity compensation plans not approved by security holders		4,045,324	$	1.85		62,000

Total		4,045,324	$	1.85		62,000

Item 13 Certain Relationships and Related Transactions and Director Independence

Certain Relationships and Related Transactions. The Company does not have a written policy pertaining solely to the approval or ratification of “related party transactions.” However, it is our policy that any material transactions between us and members of management or their affiliates, must be on terms no less favorable than those available from unaffiliated third parties.

In November 2013, Clarence E. Smith, a 5% Beneficial Owner, issued payment to the Company in the amount of $200,000. Mr. Smith was exercising 138,331 options at a price of $1.50 per share. On January 24, 2014, Mr. Smith’s stock was issued. The Company is recognizing interest since the funds were held approximately three months before the stock was actually issued. At December 31, 2013, the $205,314 due to Mr. Smith is recorded as a note payable, related party in the current liability section of the balance sheet.

During 2013, the Company has conducted business with two companies owned by Clarence E. Smith. Work was awarded the companies after bids were sought and reviewed. The amount of payments total $64,000 for the year of 2013.

Director Independence. Our common stock is currently traded on the OTC Bulletin Board. Accordingly, we are not subject to the rules of any national securities exchange that require that a majority of a listed company’s directors and specified committees of the board of directors meet independence standards prescribed by such rules. However, of our seven directors currently serving on

the Board, we believe that Robert L. Richards, Richard L. Starkey, and Josh L. Sherman are independent directors within the meaning of Rule 5605(a)(2) of the NASDAQ Stock Market Inc. listing rules. The Board believes this leadership structure provides effective and clear leadership for the Company.

Item 14 Principal Accounting Fees and Services

Audit Fees. Audit fees (including expenses) billed to the Company by Maloney + Novotny were $196,405 in fiscal year 2013, and $141,671 in fiscal year 2012. The increase fees in 2013 reflect additional time spent by our auditor in reviewing our 2013 transactions (sale of assets), new financing and derivatives, increased activity, and amending Form 10K related to four prior years. Audit fees include professional services with respect to the audit of the Company’s consolidated financial statements included in our Annual Report on Form 10-K and review of financial statements included in our Quarterly Reports on Form 10-Q. These services are normally provided by Maloney + Novotny in connection with statutory and regulatory filings performed by Maloney + Novotny to comply with generally accepted auditing standards, as well as fees for the audit of the Company’s internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002.

Audit-Related Fees. Audit-related fees (including expenses) billed to the Company by Maloney + Novotny were $0 in both fiscal years 2013 and 2012.

Tax Fees. Tax fees (including expenses) billed to the Company by Maloney + Novotny were $14,978 in fiscal year 2013 and $11,683 in fiscal year 2012.

All Other Fees. All other fees billed by our auditors were $2,583 related to sale of shallow wells and sale of Tyler County assets in 2013 and $9,397 related to our newly created wholly-owned subsidiary, American Shale Development, Inc. in 2012

The Board has adopted procedures for pre-approving all audit and permissible non-audit services provided by the independent registered public accountants. The Board will annually review and pre-approve the audit, review and attest services to be provided during the next audit cycle by the independent registered public accountants and may annually review and pre-approve permitted non-audit services to be provided during the next audit cycle by the independent registered public accountants.

PART IV

Item 15 Exhibits and Financial Statement Schedules


Exhibit No.		Exhibit Name

3.1		Articles of Incorporation for Trans Energy, Inc., a Nevada corporation

3.2		By-Laws

21.1		Subsidiaries of Registrant

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, 2013.

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase

**101.DEF		XBRL Taxonomy Extension Definition Linkbase

**101.LAB		XBRL Taxonomy Extension Label Linkbase

**101.PRE		XBRL Taxonomy Extension Presentation Linkbase

**	Filed herewith.

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: May 23, 2014

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


Signature	Title	Date

/s/ John G. Corp	President and Director	May 23, 2014
John G. Corp	(Principal Executive Officer)

/s/ John S. Tumis	Chief Financial Officer	May 23, 2014
John S. Tumis

/s/ Loren E. Bagley	Director	May 23, 2014
Loren E. Bagley

/s/ William F. Woodburn	Director	May 23, 2014
William F. Woodburn

/s/ Josh L. Sherman	Director	May 23, 2014
Josh L. Sherman

/s/ Richard L. Starkey	Director	May 23, 2014
Richard L. Starkey

/s/ Stephen P. Lucado	Director	May 23, 2014
Stephen P. Lucado

/s/ Robert L. Richards	Director	May 23, 2014
Robert L. Richards

TRANS ENERGY, INC. AND SUBSIDIARIES

CONTENTS


Report of Independent Registered Public Accounting Firm			F-2

Consolidated Balance Sheets			F-3

Consolidated Statements of Operations			F-5

Consolidated Statements of Stockholders’ Equity			F-6

Consolidated Statements of Cash Flows			F-7

Notes to Consolidated Financial Statements			F-9

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Trans Energy, Inc.

St. Marys, West Virginia

We have audited the accompanying consolidated balance sheets of Trans Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2013 and 2012, 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, 2013 and 2012, 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

May 23, 2014

F-2

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets


	December 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash	$	2,727,832		$	1,009,084
Accounts receivable, trade		4,460,535			3,143,766
Accounts receivable, related parties		18,500			18,500
Advance royalties		16,937			221,452
Prepaid expenses		1,065,061			407,596
Deferred financing costs, net of amortization of $1,308,817 and $402,525		817,938			603,788

Total current assets		9,106,803			5,404,186
OIL AND GAS PROPERTIES, USING SUCCESSFUL EFFORTS ACCOUNTING
Proved properties		77,961,183			47,730,848
Unproved properties		15,092,783			12,008,550
Pipelines		1,397,440			1,387,440
Accumulated depreciation, depletion and amortization		(14,473,069	)		(8,809,022	)

Oil and gas properties, net		79,978,337			52,317,816
PROPERTY AND EQUIPMENT, net of accumulated depreciation of $317,704 and $239,277, respectively		587,218			665,874
OTHER ASSETS
Assets held for sale		—			3,013,000
Deferred financing costs		139,076			735,662
Other assets		303,887			301,923

Total other assets		442,963			4,050,585


TOTAL ASSETS	$	90,115,321		$	62,438,461

See notes to consolidated financial statements.

F-3

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (continued)


	December 31, 2013			December 31, 2012
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	632,795		$	187,089
Accounts payable due to drilling operator		2,698,302			839,456
Accounts payable, related party		1,500			1,500
Accrued expenses		5,302,816			1,642,718
Revenue payable		127,106			225,674
Commodity derivative liability		58,176			—
Notes payable – current		14,897			19,825
Notes payable, related party		205,314			—

Total current liabilities		9,040,906			2,916,262
LONG-TERM LIABILITIES
Notes payable, net		89,204,102			48,225,848
Asset retirement obligations		41,440			28,317
Liabilities held for sale		—			388,005
Warrant derivative liability		—			2,808,278
Commodity derivative liability		67,597			—

Total long-term liabilities		89,313,139			51,450,448

Total liabilities		98,354,045			54,366,710

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; 13,457,978 and 13,238,228 shares issued, and 13,455,978 and 13,236,228 shares outstanding, respectively		13,458			13,238
Additional paid-in capital		42,556,292			41,131,636
Treasury stock, at cost, 2,000 shares		(1,950	)		(1,950	)
Accumulated deficit		(50,806,524	)		(33,071,173	)

Total stockholders’ equity (deficit)		(8,238,724	)		8,071,751


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	90,115,321		$	62,438,461

See notes to consolidated financial statements.

F-4

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations


	For the Year Ended December 31,
	2013			2012
OPERATING REVENUES
Oil and gas sales	$	18,174,524		$	11,356,626
Gas transportation, gathering, and processing		158,937			323,395
Other income		32,097			75,400

Total operating revenues		18,365,558			11,755,421
OPERATING COSTS AND EXPENSES
Production costs		10,220,034			6,771,123
Depreciation, depletion, amortization and accretion		5,752,361			3,778,563
Impairment of oil and gas properties		—			10,132,702
Selling, general and administrative		6,230,598			5,919,881

Total operating costs and expenses		22,202,993			26,602,269
Gain on sale of assets		7,015,950			112,898

INCOME (LOSS) FROM OPERATIONS		3,178,515			(14,733,950	)

OTHER INCOME (EXPENSES)
Interest income		19,090			18,775
Interest expense		(15,047,619	)		(5,738,803	)
Extinguishment/loss on warrant derivatives		(6,191,722	)		(807,639	)
Gain on commodity derivative		306,385			—

Total other income (expenses)		(20,913,866	)		(6,527,667	)

NET LOSS BEFORE INCOME TAXES		(17,735,351	)		(21,261,617	)
INCOME TAX BENEFIT (EXPENSE)		—			58,013


NET LOSS	$	(17,735,351	)	$	(21,203,604	)


NET LOSS PER SHARE – BASIC AND DILUTED	$	(1.34	)	$	(1.62	)
WEIGHTED AVERAGE SHARES – BASIC AND DILUTED		13,281,859			13,074,208

See notes to consolidated financial statements.

F-5

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity

For the years ended December 31, 2013 and 2012


	Common Stock				Additional Paid in		Treasury			Accumulated
	Shares		Amount		Capital		Stock			Deficit			Total
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

Shares issued for services		151,750		152		414,848		—			—			415,000
Stock option compensation expense		—		—		826,701		—			—			826,701
Stock options exercised		30,500		30		81,520								81,550
Stock Issued		37,500		38		101,587								101,625
Net loss		—		—		—		—			(17,735,351	)		(17,735,351	)

Balance, December 31, 2013		13,457,978	$	13,458	$	42,556,292	$	(1,950	)	$	(50,806,524	)	$	(8,238,724	)

See notes to consolidated financial statements.

F-6

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows


	For the Year Ended December 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(17,735,351	)	$	(21,203,604	)
Adjustments to reconcile net loss to net cash used by operating activities:
Depreciation, depletion, amortization, and accretion		5,752,361			3,778,563
Impairment of fixed assets		—			10,132,702
Amortization of deferred financing cost and debt discount		4,809,081			1,345,908
Share-based compensation		1,241,701			1,831,698
Gain on sale of assets		(7,015,950	)		(112,898	)
Unrealized (gain) loss on derivatives		(682,505	)		808,278
Interest and legal expense added to principal		4,591,088			1,057,226
Realized loss on warrant derivatives		7,000,000			—
Changes in operating assets and liabilities:
Accounts receivable, trade		(1,086,705	)		(1,068,915	)
Accounts receivable, operator		—			1,754,020
Noncurrent other assets		(1,964	)		(250,971	)
Prepaid expenses and other current assets		(452,950	)		(441,851	)
Accounts payable and accrued expenses		73,206			(12,679,959	)
Accounts payable drilling operator		(153,904	)		839,456
Accounts payable related party		—			(650	)
Revenue payable		(98,568	)		(226,151	)
Income tax payable		—			(270,708	)

Net cash used by operating activities		(3,760,460	)		(14,707,856	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets		11,451,244			328,466
Expenditures for oil and gas properties		(29,708,602	)		(25,080,332	)
Expenditures for property and equipment		(9,141	)		(93,244	)

Net cash used for investing activities		(18,266,499	)		(24,845,110	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		101,625			—
Stock options exercised		81,550			—
Financing costs paid		(122,230	)		(1,491,976	)
Proceeds from issuance of warrant		—			2,000,000
Payment on warrant derivative liability		(1,500,000	)
Proceeds from notes payable		25,000,000			47,043,307
Proceeds from notes payable – related party		205,314			—
Payments on notes payable		(20,552	)		(14,874,933	)

Net cash provided by financing activities		23,745,707			32,676,398


NET CHANGE IN CASH		1,718,748			(6,876,568	)

CASH, BEGINNING OF YEAR		1,009,084			7,885,652


CASH, END OF YEAR	$	2,727,832		$	1,009,084

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	$	6,016,039	$	4,044,987
Income Taxes		—		212,396

Non-cash investing and financing activities
Accrued expenditures for oil and gas properties		2,344,893		259,017
Increase in asset retirement obligation		13,123		112,667
Warrant extinguishment added to loan		7,500,000		—

See notes to consolidated financial statements.

F-8

TRANS ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Organization

Trans Energy, Inc. (“Trans Energy” or the “Company”) 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 our wholly-owned subsidiaries, Prima Oil Company, Inc. (“Prima”), Ritchie County Gathering Systems, Inc., Tyler Construction Company, Inc., American Shale Development, Inc. (“American Shale” or “ASD”), 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 GAAP 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. Our 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 us 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, 2013 and December 31, 2012 by management and no bad debt expense was incurred during the years ended December 31, 2013 and 2012.

Financing Cost

In October 2013 we reached a settlement with Oppenheimer & Co., Inc. (“Opco”) which related to the amount of the fee which was earned by Opco acting as our investment banker in assisting the Company in obtaining funding (“Tranche A”) with Chambers Energy Capital (“Chambers”). We recorded $401,625 in financing fees related to the settlement. The Opco financing fees are being amortized over the same

F-9

period as the Tranche A loan. In addition, when we obtained new financing from Chambers in February 2013 and April 2012, we incurred $122,230 in fees during 2013 and $1,741,976 in 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 costs for the years ended December 31, 2013 and 2012 were $906,292 and $640,024, respectively Our policy is to recognize twelve months of future deferred financing cost amortization as a current asset and the remaining balance of deferred financing costs as other assets in the consolidated balance sheets.

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 five to ten 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 ten 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.

Impairments

Generally accepted accounting principles require that long-lived assets (including oil and gas properties) and certain identifiable intangibles are 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.

F-10

In January 2013, the Company sold certain shallow wells for approximately $11.5 million. We determined that the sales price negotiated with the independent buyer represented the fair market value of those properties as of December 31, 2012. Accordingly, the Company recorded an impairment of approximately $10.1 million in 2012 so that the carrying value of those properties as of December 31, 2012 were equal to the subsequent sales price.

No impairments were recorded in 2013.

Derivatives

We may enter into derivative commodity contracts at times to manage or reduce commodity price risk related to our production. Derivatives and embedded derivatives, if applicable, are measured at fair value and recognized in the consolidated balance sheets as assets or liabilities. Derivatives are classified in the consolidated balance sheets as current or non-current based on whether net-cash settlement is expected to be required within 12 months of the balance sheet date. These commodity contracts are not designated as cash flow hedges, so changes in the fair value are recognized immediately in other income (expense) in 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.

We have determined that the warrant previously issued for equity of one of our wholly-own subsidiaries was a derivative liability prior to being settled in December 2013.

Notes Payable

We record notes payable at fair value and recognize 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

We record 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. 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 which has been determined to be 40 years for Marcellus Shale wells.

The following is a description of the changes to our asset retirement obligations for the twelve months ended December 31:


	2013			2012
Asset retirement obligations at beginning of period	$	416,322		$	256,651
Liabilities incurred during the period		4,259			3,849
Accretion expense		4,124			47,004
Liability revisions		4,740			108,818
Liabilities held for sale		(388,005	)		—

Asset retirement obligations at end of period	$	41,440		$	416,322

F-11

At December 31, 2013 and 2012, the Company’s current portion of the asset retirement obligation was $0. In addition, $388,005 of asset retirement obligations are reported as liabilities held for sale as of December 31, 2012 (see Note 6 and 7).

The revisions in the 2012 estimated liabilities are the result of changes in numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, and timing of retirement. The revisions in the 2013 estimated liabilities are the result of a change in the ultimate retirement cost.

Income Taxes

At December 31, 2013, the Company had net operating loss carry forwards (NOLs) for future years of approximately $51.4 million. These NOLS will expire at various dates through 2033. There is no current tax provision for the year ended December 31, 2013 due to a net operating loss for the period. 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 Alternative Minimum Tax (“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 and could be limited if there is a substantial change in ownership of the Company.

We have 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, 2013 or 2012 or paid during the periods then ended. We file tax returns in the United States and states in which we have operations and are subject to taxation. Tax years subsequent to 2009 remain open to examination by U.S. federal and state tax jurisdictions, however prior year net operating losses remain open for examination.

Revenue and Cost Recognition

We recognize gas revenues upon delivery of the gas to the customers’ pipeline from our pipelines when recorded as received by the customer’s meter. We recognize oil revenues when pumped and metered by the customer. We use 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 we are 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. We had no material imbalances as of December 31, 2013 and 2012. Costs associated with production are expensed in the period incurred.

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

Transportation revenue is recognized when earned and we have a contractual right to receive payment.

On January 1, 2013, the Company adopted new authoritative accounting guidance issued by the Financial Accounting Standards Board (“FASB”), which enhanced disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position and provided

F-12

clarification as to the specific instruments that should be considered in these disclosures. These pronouncements were issued to facilitate comparison between financial statements prepared on the basis of GAAP and International Financial Reporting Standards. These disclosures are effective for annual and interim reporting periods beginning on or after January 1, 2013, and are to be applied retrospectively for all comparative periods presented. See Note 10 – Derivatives for tabular presentation of the Company’s gross and net derivative positions.

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. As a result of stock and option transactions, we recorded total share-based compensation of $1,241,701 and $1,831,698 for the years ended December 31, 2013 and 2012, respectively.

New Accounting Standards

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

Reclassification

Certain reclassifications have been made to the 2012 financial presentation to correspond to the current year’s format.

NOTE 2 - OPERATIONS

We have incurred net losses for the years ended December 31, 2013 and 2012 of $(17,735,351) and $(21,203,604), respectively. Although our current and prior year-to-date revenues were not sufficient to cover our operating costs and interest expense, we are focusing on drilling Marcellus Shale wells which based upon projections, are expected to increase our cash flow. If our cash flows from operations are not sufficient to meet liquidity requirements, we may need to sell assets, obtain additional financing or issue equity.

Our net losses and cash flows used in operating and investing activities during the years ended December 31, 2013 and 2012 were primarily funded using net proceeds from notes payable to Chambers (see Note 9), in addition to proceeds from the sale of certain oil and gas properties (see Note 7).

NOTE 3 - ACCOUNTS RECEIVABLE DUE FROM NON-OPERATORS AND ACCOUNTS PAYABLE DUE TO DRILLING OPERATOR

We have historically been the drilling operator for wells drilled on our behalf and other third parties in which we own a working interest. In 2012, another working interest owner became the drilling operator for wells in which we own a working interest. We owed the drilling operator $2,698,302 and $839,456

F-13

for charges incurred, but not paid, as of December 31, 2013 and 2012, respectively. The amount due to the operator reported at December 31, 2013 is net of a $637,667 credit related to a refund of prior drilling costs previously invoiced to American Shale for a well we were not participating in as well as intercompany charges related to employee salary reimbursements, travel expenses, and lease costs.

NOTE 4 - OIL AND GAS PROPERTIES

Total additions for oil and gas properties for the year ended December 31, 2013 and 2012 were $29,708,602 and $25,080,332, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $5,664,047 and $3,563,599 for the years ended December 31, 2013 and 2012, 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 its 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 6).

NOTE 5 - PROPERTY AND EQUIPMENT

At December 31, 2013 and 2012, property and equipment consisted of:


	2013			2012

Vehicles		140,768		$	140,768
Machinery and equipment		114,032			123,402
Furniture and fixtures		236,475			227,334
Leasehold improvements		30,696			30,696
Land		382,951			382,951
Accumulated depreciation		(317,704	)		(239,277	)

Total fixed assets	$	587,218		$	665,874

Total additions for property, plant and equipment for the years ended December 31, 2013 and 2012 were $9,141 and $93,244, respectively. Depreciation, depletion and amortization expenses for property and equipment were $88,314 and $214,964 for the years ended December 31, 2013 and 2012, 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 6).

NOTE 6 - ASSETS AND LIABILITIES HELD FOR SALE

At December 31, 2012 the assets held for sale consists of $3,013,000 related to the sale of shallow wells in January 2013. The amount includes property and equipment sold which was used to maintain the shallow wells. Assets held for sale are reported as other assets in the Consolidated Balance Sheet. Liabilities held for sale at December 31, 2012, $388,005 relates to the sale of the shallow wells and consists of the Asset Retirement Obligation and settlement expenses. Liabilities held for sale are reported as long-term liabilities in the Consolidated Balance Sheet.

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NOTE 7 - SALE OF OIL AND GAS PROPERTIES

On December 13, 2013, the Company and our JV Partner, Republic Energy Ventures, LLC (“Republic”), closed a transaction that was previously announced pursuant to a Purchase and Sale Agreement (the “PSA”) dated September 30, 2013. The Company owned 1,114.8 lease acres of the total 4,650 lease acres and leasehold working interests in certain partially completed well sites, located in Tyler County, West Virginia. At closing, the Company received cash of approximately $10.6 million of the total purchase price of $36.3 million, net of holdback. A total of 118.6 lease acres were excluded from the sale (39.8 lease acres net to the Company) due to incurable title defects. An additional 135.5 lease acres (30.7 lease acres net to the Company) were excluded from the sale due to curable title defects, which were cured and an additional $0.2 million was due and payable to the Company, as of December 31, 2013, per the terms of the PSA.

NOTE 8 - PROVISION FOR TAXES

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


	2013			2012
Current:	$	—		$	(58,013	)

Deferred:
Change in depreciation, depletion and amortization	$	2,895,000		$	(1,737,000	)
Change in unrealized loss on derivative		232,000			(275,000	)
Change in other items		128,000			(29,000	)
Change in NOL		(11,783,000	)		(3,564,000	)
Increase in AMT credit		—			58,000
Change in valuation allowance		8,528,000			5,547,000

Total	$	—		$	(58,013	)

The income tax benefit of $58,013 for 2012 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, 2013 and 2012 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-15

At December 31, 2013, Trans Energy had net operating loss carryforwards of approximately $51.4 million that may be offset against future taxable income from 2014 through 2032. Except for an over accrual adjustment, no tax benefit has been reported in the December 31, 2013 and 2012 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, 2013 and 2012:


	2013			2012
Deferred tax assets:
NOL carryover	$	17,465,000		$	5,682,000
AMT credit		606,000			606,000
Unrealized loss on derivative contract		43,000			275,000
Other		14,000			142,000

Total deferred tax assets		18,128,000			6,705,000

Deferred tax liabilities:
Depreciation, depletion and amortization		(3,447,000	)		(552,000	)

Total deferred tax liabilities		(3,447,0000	)		(552,000	)

Valuation allowance		(14,681,000	)		(6,153,000	)

Net deferred taxes	$	—		$	—

NOTE 9 - NOTES PAYABLE

On June 22, 2007, Trans Energy finalized a financing agreement with CIT Capital USA Inc. (“CIT”) for an amount that was ultimately increased to $30,000,000. Payment was due at maturity on June 15, 2010, for all borrowing outstanding on that date. During the subsequent period up to and including April 2, 2012, the Company and CIT made eight amendments to their initial agreement to, among other things, restructure the maturity date, confirm the principal amount following certain payments, and grant 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 Trans Energy, or any of its subsidiaries, has an interest. Each 1.5% overriding royalty interest is to be proportionately reduced to the extent we or our 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.

On April 2, 2012, we paid $125,000 on the principal amount outstanding and the remainder of the principal was paid with proceeds received from the ASD Credit Agreement (see further discussion below). CIT still retains ownership of the 1.5% overriding royalty interest after the payoff.

On April 26, 2012, our newly created, wholly owned subsidiary, American Shale, closed a Credit Agreement transaction (hereafter the “ASD Credit Agreement”) with 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” or “Chambers”).

F-16

The ASD Credit Agreement provided that the Lenders will lend American Shale up to $50 million, which funds would be used to develop wells and properties that we transferred to American Shale. In order to accommodate the terms of the ASD Credit Agreement, Trans Energy transferred certain assets and properties to American Shale. Trans Energy and Prima are not direct parties to the ASD Credit Agreement, but are guarantors of loans to be made there under. We received a portion of the loan proceeds to repay CIT and certain other outstanding debts. The assets and properties transferred are referred to herein as the “Marcellus Properties,” which at the time of the transfer consisted 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 was originally 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. $1,058,823 and $705,882 of the OID was amortized as interest expense for the years ended December 31, 2013 and 2012, respectively. The administrative fee is due annually.

On February 28, 2013, American Shale, the Lenders and the Agent amended and restated the ASD Credit Agreement (as amended, the “A&R Credit Agreement”) in order to facilitate an increase in the principal amount of the borrowings under the facility to $75 million. The additional funds were received February 28, 2013. The other terms of the credit agreement were unchanged.

Interest is due monthly at 10% plus the greater of 1% or the 3 month LIBOR rate (11% at December 31, 2013). Principal is due at maturity, February 28, 2015. We have to pay interest through April 26, 2014, on any principal prepayments with respect to the original $50 million loan at the time of the prepayment prior to April 26, 2014. There is no make-whole amount with respect to the $25 million loan in the event of a prepayment. American Shale will be required to pay a “Termination Fee” with respect to the $25 million loan upon the earliest to occur of (i) a Change of Control (as defined in the A&R Credit agreement), (ii) repayment in full of the loans under the A&R Credit Agreement and (iii) certain defaults under the A&R Credit Agreement related to seeking relief from creditors or generally being unable to repay debts as they come due. The Termination Fee will be equal to $12.5 million less all interest payments actually made with respect to the $25 million loan prior to such date.

The Company expects to pay a Termination Fee upon maturity or repayment of the debt outstanding to Chambers on or before February 28, 2015. The total amount of interest payments with respect to the $25 million through the February 28, 2015 maturity date is approximately $5.6 million; therefore, the Company believes it has a liability related to the Termination Fee of approximately $6.8 million ($12.5 million gross fee, less $5.7 million in interest payments) (the “Termination Fee Liability”).

The Termination Fee Liability is recorded on the Company’s consolidated balance sheet as an addition to the related debt balance upon entering into the A&R Credit Agreement, offset by an equal debt discount of $6.8 million (the “Termination Fee Debt Discount”). The Termination Fee Debt Discount is being amortized to interest expense through the expected payment date of February 28, 2015; however, such amortization will be accelerated if payment of the Termination Fee occurs, or is probable of occurring, prior to such date. During the year ended December 31, 2013, the Company recorded interest expense of approximately $2.8 million related to the cumulative amortization of the Termination Fee Debt Discount.

The A&R Credit Agreement is collateralized by American Shale’s oil and natural gas reserves and the guarantees discussed earlier. The A&R 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

F-17

Ratio exceeds certain levels, as defined in the A&R Credit Agreement. American Shale’s Consolidated Leverage Ratio exceeded the allowed level at September 30, 2012, and quarterly thereafter. Therefore, the contingent interest provision has been applied and $2,030,050 was added to the principal balance and interest expense in 2013. A contingent interest amount of $532,388 is included in accrued expenses in anticipation of exceeding the December 31, 2013 level.

For the months of August, September, and October 2013, Chambers amended the A&R Credit Agreement to add the interest due during those months to the principal balance of the loan. In addition, $375,000 was added to the principal balance of the loan in connection with this amendment. The $375,000 is being amortized over the three month period. August, September and October 2013 interest of $2,186,038 has been added to the principal balance of the loan.

On December 20, 3013, American Shale amended the A&R Credit Agreement to increase the principal amount of the borrowings by $7.5 million to pay a portion of the cost to purchase an outstanding warrant held by Chambers (See Note 10). There were no other changes to the terms of the loan. The additional funds were received December 20, 2013.

The following table summarizes the components of total debt recorded on the Company’s consolidated balance sheets as of December 31, 2013 and 2012:


	December 31, 2013			December 31, 2012
	(audited)			(audited)

ASD Credit Agreement	$	50,000,000		$	50,000,000
Unamortized Original Issuance Discount – ASD		(1,235,294	)		(2,294,118	)
PIK Contingent Interest Expense		2,530,050			500,000
A&R Credit Agreement-February 2013		25,000,000			—
Termination Fee – A&R		6,784,626			—
Termination Fee Debt Discount – A&R		(3,940,659	)		—
PIK Interest Fee-ASD		375,000			—
PIK Interest – A&R		2,186,037			—
A&R Credit Agreement-December 2013		7,500,000
Other loans – related party		205,314
Other loans – vehicles		19,239			39,791

Total debt	$	89,424,313		$	48,245,673

On May 21, 2014 (“Funding Date”), American Shale entered into a credit agreement (hereafter the “Credit Agreement”) 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 (the “Lenders”), and Morgan Stanley Capital Group Inc. as the administrative agent (“Agent ”). Trans Energy is a guarantor of the Credit Agreement as is Prima, another of our wholly owned subsidiaries. The Credit Agreement provides that the Lenders will lend American Shale up to $200 million, including an initial draw of $102.5 million, a contingent committed amount of $47.5 million and an uncommitted amount of $50 million (the “Loans”). The initial draw under the facility was used primarily to repay all of the outstanding debt under the A&R Credit Agreement, as well as to fund certain fees and expenses incurred in connection with the Credit Agreement (See Note 18, Subsequent Events),

NOTE 10 - DERIVATIVE AND HEDGING FINANCIAL INSTRUMENTS

On May 9, 2013 our subsidiary, American Shale, entered into costless collars covering approximately 85% of its expected natural gas production from wells that were considered proved developed producing (“PDP”) as of that date. Neither oil nor natural gas liquids have been hedged, but the BTU associated with our ethane production was essentially hedged, since it is sold as part of the natural gas stream. The costless collars consist of long put options (floor) with a strike price of $4.00 per MMBtu and offsetting short calls (ceiling) with a strike price of $4.28 per MMBtu. The aforementioned volumes are hedged beginning with the June 2013 contract and ending with the April 2015 contract. A total of 3.4 MMBtu are hedged over this period, with monthly volumes declining from a high of approximately 207,000 MMBtu in June 2013 to 113,000 MMBtu in April 2015. The fair value of these commodity contracts was $(125,773) at December 31, 2013.

F-18

The Company has a master netting agreement on the gas hedge and therefore the current asset and liability are netted on the consolidated balance sheet and the non-current asset and liability are netted on the consolidated balance sheet.

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company has netting arrangements with BP Energy Company that provide for offsetting payables against receivables from separate derivative instruments.

As a part of the ASD Credit Agreement, we entered into a warrant agreement with Chambers which required American Shale to sell the Lenders for a total of $2 million a warrant for 19,500 shares representing 19.5% of American Shale’s stock at $263.44 per share. The warrant would have contractually expired on February 28, 2015. The warrant included a put option whereby the Lenders can require American Shale to repurchase the warrant as of February 28, 2015, or earlier if certain events occur. Under the put option, American Shale would pay the excess of the fair value per share of the stock over $263.44 times the number of shares exercisable less any distributions or similar payments defined by the agreement. In certain circumstances, American Shale had the option to transfer the working interest in all of its wells equal to the value of the put option instead of paying in cash. As a result of the contingent put, the warrant is accounted for as a liability with changes in its fair value reported in earnings.

On December 20, 2013, American entered into an agreement with the holders of warrants representing 19.5% of the stock of American Shale whereby American Shale agreed to purchase the warrants from the holders for $9 million. The proceeds from the increased borrowings under the A&R Credit Agreement were used to partially fund the purchase of the warrants from the holders.

The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of December 31, 2013:


Gas Collars
Contract Period	Volumes		Weighted- Average Floor Price		Weighted- Average Ceiling Price
	(MMBtu)		(per MMBtu)		(per MMBtu)
2014		1,650,248	$	4.00	$	4.28
2015		464,825	$	4.00	$	4.28

All gas collars *		2,115,073

*	Gas collars are priced based on Inside FERC - Henry Hub (100%).

F-19

The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category:


	As of December 31, 2013
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value

Commodity derivative	Current assets	$	—	Current liabilities	$	58,176
Commodity derivative	Noncurrent assets		—	Noncurrent liabilities		67,597
Warrant derivative liability			—	Noncurrent liabilities		—

		$			$	125,773


	As of December 31, 2012
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value

Commodity derivative	Current assets	$	—	Current liabilities	$	—
Commodity derivative	Noncurrent assets		—	Noncurrent liabilities		—
Warrant derivative liability			—	Noncurrent liabilities		2,808,278

		$	—		$	2,808,278

The table below summarizes the realized and unrealized gains and losses related to our derivative instruments for the years ended December 31, 2013 and 2012.


	Twelve Months Ended December 31,
	2013			2012

Realized gains on commodity derivative	$	432,158		$	639
Change in fair value of commodity derivative		(125,773	)		—
Change in fair value of warrant derivative		808,278			(808,278	)
Realized loss on warrant derivative		(7,000,000	)

Total realized and unrealized gains/(losses) recorded	$	(5,885,337	)	$	(807,639	)

These realized and unrealized gains and losses are recorded in the accompanying consolidated statements of operations as derivative gains (losses).

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NOTE 11 - FAIR VALUE MEASUREMENTS

The authoritative guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:


Level 1:		Quoted prices are available in active markets for identical assets or liabilities;

Level 2:		Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

Level 3:		Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flows models or valuations.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The valuation policies are determined by the Chief Financial Officer and are approved by the President. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, the inputs used in the fair value calculations are updated and management reviews the changes from period to period for reasonableness. The Company has consistently applied the valuation techniques discussed below in all periods presented.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and December 31, 2012, respectively by level within the fair value hierarchy


	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
December 31, 2013
ASSETS:
Commodity contracts		—		—		—		—
LIABILITIES:
Commodity contracts		—	$	125,773		—	$	125,773
Warrant derivative liability		—		—		—

December 31, 2012

ASSETS:
Commodity contracts		—		—		—		—
LIABILITIES:
Warrant derivative liability		—		—		2,808,278		2,808,278

F-21

We use Level 2 inputs to measure the fair value of gas commodity collar derivatives. Level 2 assets consist of commodity derivative assets and liabilities (See Note 10 Derivative and Hedging Financial Instruments). The fair value of the commodity derivative assets and liabilities are estimated by the Company using income valuation techniques utilizing the income approach and an option pricing model, which take into account notional quantities, market volatility, market prices, contract parameters, counterparty credit risk and discount rates based on published LIBOR rates. The Company validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.

As of December 31, 2012, the Company’s warrant derivative financial instrument issued as a part of the ASD Credit Agreement is comprised of the warrants issued by the Company to purchase 19,500 shares of common stock with a put option (See Note 10 Derivative and Hedging Financial Instruments). The warrants are valued by third parties using a binomial lattice-based valuation model and are classified as Level 3 in the fair value hierarchy. The lattice-based valuation technique is utilized because it embodies all of the requisite assumptions (including the underlying price, exercise price, term, volatility, and risk-free interest-rate) that are necessary to measure the fair value of these instruments. The valuation policies are determined by the Chief Financial Officer and approved by the President. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, the Chief Financial Officer reviews the updated inputs used in the fair value calculations and internally reviews the changes from period to period for reasonableness. The Company uses data from its peers as well as from external sources in the determination of the volatility and risk free interest rates used in the fair value calculations. A sensitivity analysis is performed as well to determine the impact of the inputs on the ending fair value estimate. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument due to both internal and external market factors. In addition, option-based techniques are highly sensitive to volatility assumptions. An increase in the volatility would cause an increase in the fair value of the warrants. Likewise, a decrease in the volatility would cause a decrease in the value of the Warrants.

The significant assumptions used in the valuation of the warrant derivative liability as of December 31, 2012 were as follows:


Exercise price	$	1.63 per share
Stock price	$	2.89 per share
Volatility		75	%
Remaining Term of Warrants		1.41 years
Risk-free interest rate		0.20	%

The following table sets forth a reconciliation of changes in the fair value of financial liabilities classified as Level 3 in the fair value hierarchy:


	For the Twelve Months Ended December 31,
	2013			2012

Balance as of beginning of period	$	(2,808,278	)	$	—
Total unrealized gains (losses) Included in earnings		(6,191,722	)		(808,278	)
Issuances		—			(2,000,000	)
Settlements		9,000,000			—
Transfers in and out of Level 3		—			—

Balance as of December 31	$	0		$	(2,808,278	)

Change in unrealized gains (losses) included in earnings
Relating to instruments still held as of December 31,	$	—		$	(808,278	)

F-22

NOTE 12 - STOCKHOLDERS’ EQUITY

In December 2013, Trans Energy granted 9,000 shares of common stock to eleven employees. These shares vest immediately and the shares were valued using the fair market value of the common stock at the date of grant. During 2013, we recorded $25,650 of share-based compensation expense related to these shares.

In November 2013, Trans Energy issued 37,500 shares of common stock to Opco related to their settlement agreement.

In February 2013, we granted 42,000 shares of stock to five employees under the long-term incentive bonus program. Of the 42,000 shares, 36,000 shares are not performance based and vest semi-annually over a three year period and 6,000 shares are performance based and vest semi-annually over a three year period, subject to ongoing employment. The 42,000 shares were valued at $2.50 per share of common stock using the fair value of the common stock at the date of grant and the fair value will be amortized to compensation expense semi-annually over three years.

In February 2013, we also granted 346,000 common stock options to seven employees and five outside board members. These options vest semi-annually over three years and have a five year term. These stock options were granted at an exercise price of $2.50 per common share and the fair value was determined using the Black Scholes option pricing model. The options are being amortized to share-based compensation expense semi-annually over the vesting period. Of the 346,000 options granted, 12,000 of the options are performance based.

In May 2013, we also granted 100,000 common stock options to an 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 and the fair value was determined using the Black Scholes option pricing model. The options are being amortized to share-based compensation expense semi-annually over the vesting period.

In April 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.

In April 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

F-23

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. As of August, 2012, a total of 15,000 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.

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.

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.

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 were vested immediately and the shares were valued using fair market value of the common stock at the date of grant.

The Company has computed the fair value of all options granted using the Black-Scholes option pricing model. In order to calculate the fair value of the options, certain assumptions are made regarding components of the model, including the estimated fair value of the underlying common stock, risk-free interest rate, volatility, expected dividend yield and expected option life. Changes to the assumptions could cause significant adjustments to valuation. The Company estimated a volatility factor utilizing a weighted average of comparable published volatilities of peer companies. The Company has estimated a forfeiture rate of zero as the effect of forfeitures has not been significant and the small number of option holders does not provide a reasonable basis for prediction. The Company estimates the expected term based on the average of the vesting term and the contractual term of the options. The risk- free interest rate is based on the U.S. Treasury yield in effect at the time of the grant for treasury securities of similar maturity. The fair value of all options granted during the years ended December 31, 2013 and 2012 was determined using the following assumptions:


Expected volatility		70% - 90%
Risk free interest rate		0.80% - 1.75%
Expected term (years)		3.0 - 5.0
Dividend yield		0%

As a result of the above stock and option transactions, we recorded total stock-based compensation of $1,241,701 and $1,831,698 for the years ended December 31, 2013 and 2012, respectively.

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Stock option activity is as follows:


	Number of Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Fair Value
Outstanding December 31, 2011		2,674,324		$	1.59		2.43 Years	$	4,252,175

Granted		1,014,000		$	2.30
Exercised		—			—
Forfeited		(33,000	)	$	2.47
Expired		(15,000	)	$	2.68

Outstanding December 31, 2012		3,640,324		$	1.76		2.69 Years	$	6,406,970

Granted		446,000		$	2.61
Exercised		(30,500	)	$	2.67
Forfeited		(10,500	)	$	2.35
Expired		—			—

Outstanding December 31, 2013		4,045,324		$	1.85		2.05 Years	$	7,483,849

Exercisable at, December 31, 2013		3,460,992		$	1.75			$	6,056,736

Unvested at December 31, 2013		584,332

NOTE 13 - EARNINGS PER SHARE

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income (loss) per share of common stock includes both vested and unvested shares of restricted stock. Diluted net income (loss) per common share of stock is computed by dividing net income by the diluted weighted-average common shares outstanding. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had losses for the twelve month periods ended December 31, 2013 and 2012, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of December 31, 2013, potentially dilutive securities included (i) 62,000 unvested shares of restricted common stock and (ii) 3,620,824 in-the-money outstanding options.

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NOTE 14 - BUSINESS SEGMENTS

Our principal operations consist of exploration and production through Trans Energy, American Shale and Prima, and pipeline transmission with Ritchie County Gathering Systems and Tyler Construction Company.

Certain financial information concerning our operations in different segments is as follows:


	For the Year Ended December 31,		Exploration and Production			Pipeline Transmission		Corporate			Total

Revenue		2013	$	18,174,524		$	158,937	$	32,097		$	18,365,558
		2012	$	11,356,626		$	323,395	$	75.400		$	11,755,421
Income (Loss) from operations		2013		9,302,666			70,263		(6,194,412	)		3,178,517
		2012		(9,065,844	)		172,146		(5,840,252	)		(14,733,950	)
Interest expense		2013		15,047,619			—		—			15,047,619
		2012		5,738,803			—		—			5,738,803
Depreciation, depletion, amortization and accretion		2013		5,751,781			580					5,752,361
		2012		3,778,242			321					3,778,563
Property and equipment acquisitions, including oil and gas properties		2013		29,698,602			10,000		9,141			29,717,743
		2012		25,080,332					93,244			25,173,576

Total assets, net of intercompany accounts:

December 31, 2013				90,098,192			17,129					90,115,321
December 31, 2012				62,408,692			29,769					62,438,461

NOTE 15 - 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 options. These options vested immediately. These options were granted at an exercise price of $2.30 per common share and were valued using the

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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.

In 2010, 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 then remitted $213,093 to Sancho Oil and Gas for the amount of the 20% which Sancho previously owned on the leases.

NOTE 16 - ECONOMIC DEPENDENCE AND MAJOR CUSTOMERS

Trans Energy, Inc. has five customers for the year ended December 31, 2013 and nine customers for the year ended December 31, 2012 that represent 100% of its gross oil and gas sales. BD Oil Gathering Corporation is the major purchaser of oil and SEI Energy, LLC is the major purchaser of gas and Williams Ohio Valley Midstream, LLC is the major purchaser of NGLs of the Company.

NOTE 17 - COMMITMENTS AND CONTINGENCIES

We operate exclusively in the United States, entirely in West Virginia, in the business of oil and gas acquisition, exploration, development, exploitation and production. We operate 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. Our ability to expand our reserve base and diversify our operations is also dependent upon our ability to obtain the necessary capital through 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 our proposed business activities. We cannot predict what effect, if any, current and future regulations may have on our results of operations.

In October 2013 we reached a settlement with Oppenheimer & Co., Inc. which related to the amount of the fee which was earned by Opco acting as our investment banker in assisting the Company in obtaining funding with Chambers. We recorded $401,625 in financing fees related to the settlement. The settlement consisted of $300,000 in cash, and 37,500 shares of common stock valued at $101,625 ($2.71 per share) and a registration rights agreement relating to the common stock issued.

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On September 28 and December 17, 2012, the U.S. Environmental Protection Agency (“EPA”) issued us 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. We are 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.

In April and May 2013, our President and Chairman of the Board, respectively, entered into change of control agreements. These agreements provide that both individuals are entitled to receive a severance payment equal to twice their annual salary and 85,000 vested common shares if there is a change in control of the Company and they are terminated or demoted. There are four other Company employees who received change in control agreements in 2013 that provide them severance payments equal to their salary for six to twenty four months and one employee would receive 50,000 vested common shares upon consummation of a change in control of the Company.

Trans Energy has gas delivery commitments to Dominion Field Services for Gateway firm nomination up to 800 Dth per day with the receipt/delivery point being Meter #4395501 (ED120). We believe that we can meet the delivery commitments based on our estimated production. If, however, Trans Energy cannot 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 18 - SUBSEQUENT EVENTS

On May 21, 2014 (“Funding Date”), our wholly owned subsidiary, American Shale, entered into a credit agreement (hereafter the “Credit Agreement”) 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 (the “Lenders”), and Morgan Stanley Capital Group Inc. as the administrative agent (“Agent ”). Trans Energy is a guarantor of the Credit Agreement as is Prima, another of our wholly owned subsidiaries. The Credit Agreement provides that the Lenders will lend American Shale up to $200 million, including an initial draw of $102.5 million, a contingent committed amount of $47.5 million and an uncommitted amount of $50 million (the “Loans”). The initial draw under the facility was used primarily to repay all of the outstanding debt under the A&R Credit Agreement with Chambers, as well as to fund certain fees and expenses incurred in connection with the Credit Agreement.

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The Loans will initially bear interest at a per annum rate equal to 9% plus the greater of 1% or LIBOR, for a three month interest period. The interest rate will be automatically lowered if American Shale improves the ratio of the value of its proved developed producing (“PDP PV9”) properties to its funded debt, less cash and other liquid assets, as further defined under the Credit Agreement (the “Net Debt Ratio”). Upon the occurrence of certain events of default as defined in the Credit Agreement, the loans will bear interest at an additional 2% per annum above the initial rate, and with respect to other events of default, at the election of the required lenders, may bear interest at the higher default rate. Interest will be due and payable monthly in arrears, on the maturity date, and on the date of any prepayment of principal.

The initial loan was advanced as a single funding of $102.5 million on the Funding Date. Additional amounts up to $47.5 million may be drawn within the two year period after the Funding Date provided that the Net Debt Ratio, pro forma for such subsequent drawdowns, based on the level of PDP PV9 that is projected six months from the date of each drawdown, meets certain pre-defined targets as specified in the Credit Agreement. All principal will be due on December 31, 2018 (the “Maturity Date”), if not accelerated before that date. Scheduled amortization of the principal amount of the loans may begin on May 1, 2015, unless the Net Debt Ratio exceeds certain defined parameters, in which case scheduled amortization may begin as late as May 1, 2016. No amortization is required if American Shale’s Net Debt Ratio meets certain criteria, as defined in the Credit Agreement. The minimum amortization required each month will be the greater of (i) 0.75% of the then outstanding balance (after May 1, 2016) or (ii) the amortization amount that would be required for American Shale to achieve a predetermined Net Debt Ratio within six months. Such ratios are specified in the Credit Agreement and increase over time.

The principal amount of the Loans may be prepaid, but not reborrowed. If the Loans are prepaid on or prior to the first anniversary of the Funding Date, a make-whole amount equal to 4.0% of the principal balance of the Loans, plus the sum of the remaining scheduled payments of interest prior to the first anniversary of the Funding Date, will be charged. Up to $25 million of prepayments from specified sources will be exempt from this provision if payments are made prior to the first anniversary of the Funding Date. If the Loans are prepaid on or after the first anniversary of the Funding Date but prior to the second anniversary of the Funding Date, a make-whole amount equal to 4.0% of the principal balance of the Loans will be charged. Prepayments between the second and third anniversary of the Funding Date will be charged 3.0% of the principal balance of the Loans.

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

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The Credit Agreement contains representations and warranties that are common in such agreements, including, but not limited to

•

financial condition;

•

material adverse effects;

•

corporate existence;

•

corporate authorizations and powers;

•

enforceable obligations; and

•

existing indebtedness and material litigation.

Other representations and warranties relate to operations such as environmental matters, gas imbalances, hedging agreements, reserve reports, sale of production and contingent obligations. The Credit Agreement also includes typical indemnification provisions.

The Credit Agreement also includes certain customary affirmative covenants such as minimum hedging requirements, delivery of financial information, operation and maintenance of properties, and maintenance of books and records. Financial covenants include a maximum leverage ratio (latest twelve months EBITDA to net debt) and minimum current ratio (consolidated current assets to consolidated current liabilities). The definition of net debt includes funded debt plus accounts payable, offset by cash as well as accounts receivable. American Shale is also required to apply toward approved capital expenditures a minimum of 50% of the proceeds of any equity issuance that occurs subsequent to the first anniversary of the Funding Date.

Negative covenants include limitations on indebtedness, liens, fundamental changes, dispositions of property, payment of dividends or distributions, capital expenditures, investments and transactions with affiliates. There are also limitations on hedging transactions, creation or acquisition of subsidiaries, use of proceeds, drilling without providing title opinions, amending certain documents and appointing non-approved officers or directors.

Upon the occurrence of a change of control (as defined in the Credit Agreement), the Lenders may require American Shale to pay all of the outstanding interest, make-wholes and fees in addition to 101% of the principal amounts of the Loans under the Credit Agreement.

On the Funding Date, American Shale also entered into a Net Profits Interest Agreement (the “NPI Agreement”) with Agent. The NPI Agreement provides that subsequent to the repayment of the Loans, American Shale will pay a net profits interest to Agent (the “NPI”). The NPI is to be calculated based on production revenues less certain expenditures, including operating costs, general and administrative expenses, interest and capital expenditures. The amount of interest expense and general and administrative expenses that can be charged are limited based on the amounts that were previously expensed prior to repayment of the Loans. The NPI is earned based on amounts borrowed under the Credit Agreement. As of the Funding Date, a NPI of 6.5% of the net profits, as defined under the NPI Agreement, has been earned. Agent will earn up to an additional 2.5% of the net profits pro rata for any subsequent borrowing by American Shale under the $47.5 million contingent commitment.

The NPI Agreement provides the Agent with the option to sell its NPI for fair value, as defined in the NPI Agreement, alongside American Shale or Trans Energy in the event that either American Shale or Trans Energy sells interests, including partial interests, in the subject properties at a fair value for the NPI that meets or exceeds $1.5 million for each 1.0% of NPI earned by Agent prior to such date. In such event,

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American Shale can also require the Agent to sell all of its NPI to American Shale (or, alternatively, to the buyer of any subject interests) for fair value. In the event of a sale of all or substantially all of the assets of American Shale, fair value is defined as the net cash received that is attributable to the equity interests of either American Shale or Trans Energy in such transaction.

On the Funding Date, American Shale also entered into a purchase and sale agreement (the “Republic PSA”) with its joint venture partner, Republic Energy Ventures (“Republic”). Under the Republic PSA, for $15 million, American Shale sold (i) an undivided interest across all of its undeveloped leasehold amounting to approximately 2,239 net acres, (ii) an over-riding royalty interest of 1.5% in all of its leasehold in Wetzel County, West Virginia, and (iii) an over-riding royalty interest of 1.0% in six (6) wells that are currently being drilled in Marshall County, West Virginia. The consideration is to be paid in the form of a credit against expenses incurred by Republic on behalf of American Shale. American Shale reserved the right to receive 25% of the net profits earned by Republic on the assets sold by American Shale under the Republic PSA. American Shale has the option to repurchase the undivided interest across all of its undeveloped leasehold, plus the over-riding royalty interest in its Wetzel County leasehold, for $15 million if (i) such payment is made within six (6) months of the Funding Date, or (ii) a purchase and sale agreement that would allow for such repayment by American Shale is signed within such period and the transaction contemplated therein in closed prior to December 31, 2014.

As part of the Republic PSA, Republic also agreed to amend the Amended Joint Development Agreement with American Shale. Under the revised AJDA, Republic agreed to fund all costs associated with new leasehold acquisitions subsequent to April 1, 2014. American Shale has the right to buy a 25% interest in any such leasehold at Republic’s cost, plus 12% interest, in the event that Republic sells its interest in the leasehold or permits to drill a well on the leasehold. In the event that American Shale repays Republic under the terms of the Republic PSA, American Shale will have the option to fund a 50% portion of any future leasehold expenditures, upon providing satisfactory evidence of its ability to continue such funding on a go-forward basis.

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NOTE 19 - 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, 2013 and 2012, 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.

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

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

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


	As of December 31,
	2013			2012
Proved oil and gas producing properties and related lease, wells and equipment	$	79,358,623		$	69,270,310
Unproved Oil and Gas Properties		15,092,783			13,963,619
Accumulated Depreciation, Depletion and Amortization		(14,473,069	)		(28,194,422	)

Net Capitalized Costs	$	79,978,337		$	55,039,507

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,
	2013		2012
Acquisition of Properties
Proved	$	—	$	—
Unproved		6,065,258		4,477,833
Exploration Costs				—
Development Costs		23,643,344		20,602,499

Total Costs Incurred	$	29,708,602	$	25,080,332

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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,
	2013			2012
Sales	$	18,174,524		$	11,356,626
Production Costs (a)		(10,136,028	)		(6,624,423	)
Depreciation, Depletion and Amortization		(5,751,781	)		(3,778,242	)
Income Tax Expense		—			58,013

Total Results of Operations for Producing Activities (b)	$	2,286,715		$	1,011,974

(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 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,
	2013									2012
	Oil (BBL)			Gas (Mcf)			NGL (BBL)			Oil (BBL)			Gas (Mcf)			NGL (BBL)
Proved Reserves:
Beginning of the period		133,735			43,939,005			1,649,873			163,906			16,695,133			559,389
Revisions of previous estimates		(1,808	)		(13,028,885	)		(722,757	)		(20,749	)		838,105			224,307
Extensions and discoveries		6,267			16,916,629			63,537			6,740			29,356,710			976,248
Improved recovery		—			—			—
Production		(1,414	)		(3,783,427	)		(100,284	)		(16,162	)		(2,950,943	)		(110,071	)
Purchases of minerals in place		—			—			—			—			—			—
Sales of minerals in place-leaseholds		(117,707	)		(1,507,155	)		(2	)		—			—			—

End of period		19,073			42,536,167			890,367			133,735			43,939,005			1,649,873

Proved Developed Reserves, End of Year		19,073			42,536,167			890,367			129,468			28,072,921			1,037,577

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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, 2013 and 2012 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,
	2013			2012
Future Cash Inflows	$	186,892,866		$	212,933,565
Future Production Costs (a)		(71,482,928	)		(80,504,937	)
Future Development Costs		—			(18,845,514	)
Future Income Tax Expense		(23,081,988	)		(22,716,623	)

Future Net Cash Flows		92,327,950			90,866,491
Discounted for Estimated Timing of Cash Flows		(48,013,950	)		(56,571,491	)

Standardized Measure of Discounted Future Net Cash Flows	$	44,314,000		$	34,295,000

(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.

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 2013 used in the above table were gas $3.67 per MMBTU, oil $96.78 per BBL and natural gas liquids $35.36 per BBL. The prices used for 2012 were gas $2.76 per MMBTU, oil $94.71 per BBL and natural gas liquids $34.00 per BBL.

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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,
	2013			2012

Standardized Measure, Beginning of Year	$	34,295,000		$	33,002,000
Oil and gas sales, net of production costs		(8,648,780	)		(5,187,428	)
Changes in prices and future production		2,402,924			(1,430,105	)
Extensions, discoveries and improved recovery, net of costs		21,245,578			20,268,426
Sales of Minerals in place-leaseholds		(7,591,348	)		—
Change in estimated future development costs		18,845,514			(18,845,514	)
Previously estimated development costs incurred		—			—
Revisions of previous quantity estimates		(25,123,031	)		2,609,337
Accretion of Discount		3,429,500			3,300,200
Net change in income taxes		(365,365	)		(4,900,391	)
Timing and Other		5,824,008			5,478,475

Standardized Measure, End of Year	$	44,314,000		$	34,295,000

In 2013, the Company had net negative revisions of 8.2 MMcf, as 5 proved undeveloped locations were removed from its estimate of reserves at December 31, 2013 due primarily to declines in natural gas pricing and changes to the Company’s drilling plans with regards to horizontal drilling.

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