Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended June 30, 2013

OR

For the transition period from              to             

Commission File Number 0-23530

TRANS ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” 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 in Rule 12b-2 of the Exchange Act.)    Yes  ¨    No  x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Table of Contents

Table of Contents

i

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

See notes to unaudited consolidated financial statements.

F-1

Table of Contents

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (continued)

See notes to unaudited consolidated financial statements.

F-2

Table of Contents

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations (Unaudited)

See notes to unaudited consolidated financial statements.

F-3

Table of Contents

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statement of Stockholders’ Equity

For the Six Months Ended June 30, 2013

(Unaudited)

See notes to unaudited consolidated financial statements.

F-4

Table of Contents

TRANS ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

See notes to unaudited consolidated financial statements.

F-5

Table of Contents

TRANS ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — BASIS OF FINANCIAL STATEMENT PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying unaudited interim consolidated financial statements have been prepared by Trans Energy, Inc., (“Trans Energy,” “we,” “our,” “us,” or the “Company”), in accordance with accounting principles generally accepted in the United State of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. Accordingly, they do not include certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP. The information furnished in the interim consolidated financial statements includes normal recurring adjustments and reflects all adjustments, which, in the opinion of management, are necessary for a fair presentation of such financial statements. Although management believes the disclosures and information presented are adequate to make the information not misleading, these interim consolidated financial statements should be read in conjunction with our most recent audited consolidated financial statements and notes thereto included in our December 31, 2012 Annual Report on Form 10-K. Operating results for the six months ended June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

Nature of Operations and Organization

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

Principles of Consolidation

The consolidated financial statements include us and 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., and interests with joint venture partners, which are accounted for under the proportional 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 our 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 the Company 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 receivable. 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 to us could be overstated, which could have a negative impact on operations. No allowance for doubtful accounts is deemed necessary at June 30, 2013 and December 31, 2012 by management and no bad debt expense was incurred during the six months ended June 30, 2013 and 2012.

F-6

Table of Contents

Financing Cost

In connection with obtaining new financing in February 2013 and April 2012, we incurred $110,365 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 three months ended June 20, 2013 and 2012 were $169,047 and $93,744, respectively. Amortization of financing costs for the six months ended June 30, 2013 and 2012 were $331,948 and $331,244, respectively.

Derivatives

Derivatives and embedded derivatives, if applicable, are measured at fair value and recognized in the consolidated balance sheet as an asset or a liability. Derivatives are classified in the balance sheet as current or non-current based on whether net-cash settlement is expected to be required within 12 months of the balance sheet date. The changes in the fair value of the derivatives are included 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 and related put option issued for one of our wholly-own subsidiaries is a derivative liability. We also enter into derivative commodity contracts at times to manage or reduce commodity price risk related to our production. These commodity contracts are not designated as a hedge, so changes in the fair value are recognized in other income (expense).

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.

The following is a description of the changes to our asset retirement obligations for the six months ended June 30:

At June 30, 2013 and 2012, our current portion of the asset retirement obligation was $0. In addition, asset retirement obligations related to the shallow wells sold in 2013 was reported as a liability of $242,595 at June 30, 2012.

Income Taxes

At June 30, 2013, we had net operating loss carry forwards (“NOLs”) for future years of approximately $36.3 million. These NOLs will expire at various dates through 2032. The current tax provision is -0- for the six months ended June 30, 2013 due to a net operating loss for the period. 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 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.

We have no material unrecognized tax benefits. No tax penalties or interest expense were accrued as of June 30, 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 2008 remain open to examination by U.S. federal and state tax jurisdictions, however prior year net operating losses remain open for examination.

F-7

Table of Contents

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.

We currently have material pending legal proceedings and we have received Administrative compliance orders and a request for information from the U.S. Environmental Protection Agency (“EPA”). See Part II, Item 1 Legal Proceedings, on page 5 for details regarding these matters.

In April and May 2013, our President and Chairman of the Board, respectively, entered into change of control agreements. These agreements provide both individuals 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. Various other Company personnel also received change in control agreements in April that provide them severance payments equal to their salary for six to twelve months.

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 recognized $4,641,723 and $2,137,362 in oil and gas revenues for the three months ended June 30, 2013 and 2012, respectively. We recognized $8,215,606 and $4,909,344 in oil and gas revenues for the six months ended June 30, 2013 and 2012, respectively. 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 June 30, 2013 and December 31, 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. We recognized $26,447 and $94,375 of transportation revenue for the three months ended June 30, 2013 and 2012, respectively. We recognized $61,890 and $187,688 of transportation revenue for the six months ended June 30, 2013 and 2012, respectively.

NOTE 2 — OPERATIONS

We have incurred cumulative operating losses through June 30, 2013, of $38,382,906. Although the prior year 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. In February 2013, we obtained additional financing in the amount of $25 million to be used for capital expenditures and operations. During the first quarter of 2013, we also increased our cash flow by selling our shallow wells. 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.

NOTE 3 — OIL AND GAS PROPERTIES

Total additions for oil and gas properties for the three months ended June 30, 2013 and 2012 were $11,314,610 and $12,996,339, respectively. Total additions for oil and gas properties for the six months ended June 30, 2013 and 2012 were $12,692,501 and $14,249,455, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $717,643 and $685,857 for the three months ended June 30, 2013 and 2012, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $1,333,957 and $1,630,574 for the six months ended June 30, 2013 and 2012, respectively

NOTE 4 — 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 owner became the drilling operator for wells in which we own a working interest. We owed the drilling operator $5,618,771 and $839,456 for charges incurred, but not paid, as of June 30, 2013 and December 31, 2012, respectively.

F-8

Table of Contents

NOTE 5 — NOTES PAYABLE

On June 22, 2007, we 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 we, or any of our subsidiaries, have 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 American Shale Development, Inc. Credit Agreement (see further discussion below). CIT still retains ownership of the 1.5% overriding royalty interest after the payoff.

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

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

The ASD Credit Agreement is for a notional amount of $50 million, which was received at closing net of a $3 million Original Issue Discount (OID) and a $50,000 administrative fee. These OID costs are netted against Notes Payable and are being amortized over the life of the loan using the straight-line method, which approximates the effective interest method. For the three months ended June 30, 2013, $264,706 of the OID was amortized as interest expense. For the six months ended June 30, 2012, $529,412 of the OID was amortized as interest expense. Total OID amortization is $1,235,294 as of June 30, 2013. The administrative fee is due annually.

On February 28, 2013, ASD amended and restated the credit agreement that was previously entered into on February 29, 2012 by and among ASD, Lenders and Agent. The new credit agreement (“A&R Credit agreement”) was entered into among the parties in order to facilitate an increase in the principal amount of the borrowings under the facility to $75 million. 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 June 30, 2013). Principal is due at maturity, February 28, 2015. There is no corresponding 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) the exercise of the Warrant Put Option (as defined in the Warrants) 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 ASD Credit Agreement is collateralized by American Shale’s natural gas and oil reserves and is guaranteed by us. The ASD credit agreement includes reporting, financial and other restrictive covenants, as well as a contingent interest provision that adds 1% of the outstanding principal amount of the Loan to the loan balance for any quarter in which American Shale’s Consolidated Leverage Ratio exceeds certain levels, as defined in the ASD Credit Agreement. ASD’s Consolidated Leverage Ratio exceeded the allowed level at December 31, 2012, March 31, 2013, and June 30, 2013. Therefore, the contingent interest provision has been applied and $1,505,000 was added to the principal balance and interest expense in 2013. We have to pay interest through April 26, 2014, on any principal prepayments prior to April 26, 2014, at the time of the prepayment.

As of June 30, 2013 and December 31, 2012, we owed $28,575 and $15,155, respectively, for other loans, primarily for vehicles.

F-9

Table of Contents

NOTE 6 — DERIVATIVE AND HEDGING FINANCIAL INSTRUMENTS

ASC 480-10-25-8 through 25-12, Derivative and Hedging Activities, as amended, establishes accounting and reporting standards for derivative instruments. As a part of the April 26, 2012 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 ASD’s stock at $263.44 per share. The warrant expires on February 28, 2015. The warrant includes a put option whereby the Lender could require ASD to repurchase the warrant as of February 28, 2015, or earlier if certain events occur which is in accordance with the credit agreement. Under the put option, ASD would pay the excess of the fair market value per share of the stock over $263.44 times the number of shares exercisable less any distributions or similar payments defined by the agreement. In certain circumstances, ASD has the option to transfer working interest in all of its wells equal to the value of the put option instead of paying in cash.

The embedded derivative is recorded at fair value and reported as a Long-Term Liability on the Consolidated Balance Sheet with the change in fair value recorded in the Consolidated Statements of Operations in Other Income (Expenses). The gain on the change in fair value of the embedded warrant amounted to $467,762 and $843,340 for the three months ended June 30, 2013 and 2012, respectively.The gain on the change in fair value of the embedded warrant amounted to $591,439 and $843,340 for the six months ended June 30, 2013 and 2012, respectively. The Embedded Warrant Liability had a fair value of $2,216,839 and $2,808,278 as of June 30, 2013 and December 31, 2012, respectively.

On May 9, 2013 our subsidiary, American Shale Development, 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 mark to market value of the costless collars was $659,356 at June 30, 2013.

F-10

Table of Contents

NOTE 7 — STOCKHOLDERS’ EQUITY

Effective April 26, 2012, we 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.

Effective April 26, 2012, we 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 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. As of August, 2012, a total of 18,000 of these options were cancelled due to separation from service.

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

In August 2012, we 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, we 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 valued using the Black Scholes valuation model. The options are being amortized to share-based compensation expense over the vesting period.

F-11

Table of Contents

In December 2012, we granted 9,900 shares of common stock to seventeen employees under the long-term incentive bonus program. The 9,900 shares are vested immediately and the shares were valued using fair market value of the common stock at the date of grant.

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

Due to severance agreements, effective in April 2012, certain employees became vested 100% on their stock options and stock awards.

In February 2013, we granted 42,000 shares of stock to five employees under the long-term incentive bonus program. The 36,000 shares are not performance based and vest semi-annually over a three 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 using fair value of the common stock at the date of grant and 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 five years and have a five year term. These stock options were granted at an exercise price of $2.50 per common share and were valued using the Black Scholes valuation model. The options are being amortized to share-based compensation expense semi-annually over the vesting period. Of the 346,000 options granted, 12,000 of the options are performance based.

The following are assumptions made in computing the February 2013 option fair value:

In May 2013, we also granted 100,000 common stock options to an outside board member. These options vest semi-annually over five years and have a five year term. These stock options were granted at an exercise price of $3.00 per common share and were valued using the Black Scholes valuation model. The options are being amortized to share-based compensation expense semi-annually over the vesting period.

The following are assumptions made in computing the May 2013 option fair value:

As a result of the above stock and option transactions, we recorded total share-based compensation of $325,800 and $778,252 for the three months ended June 20, 2013 and 2012, respectively. As a result of the above stock and option transactions, we recorded total share-based compensation of $635,863 and $1,016,485 for the six months ended June 30, 2013 and 2012, respectively.

F-12

Table of Contents

The share-based compensation expense for the three months ended June 30, 2013 and 2012 is as follows:

Common stock awards

Stock option awards

The stock-based compensation expense for the six months ended June 30, 2013 and 2012 is as follows:

Common stock awards

Stock option awards

F-13

Table of Contents

NOTE 8 — EARNINGS PER SHARE

Basic income (loss) per share of common stock for the periods ended June 30, 2013 and 2012 is determined by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period.

The stock options were anti-dilutive for the three and six months ended June 30, 2013 and 2012.

We paid no cash distributions to our stockholders during the three and six months ended June 30, 2013 and 2012.

NOTE 9 — RELATED PARTY TRANSACTIONS

Employment separation agreements were executed between us 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 our Board of Directors. Mr. Mark Woodburn is a beneficial owner of approximately 10.3% of our common stock.

In consideration of the execution of the severance agreement, the parties received cash compensation of $50,000 each net of taxes. We 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. We 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, we granted 150,000 common stock options due to a severance agreement. 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. We recorded $198,000 of stock compensation expense in the third quarter of 2012 related to these additional stock options.

NOTE 10 — SALE OF ASSETS

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.

The assets and liabilities related to the wells and equipment sold were reported as assets and liabilities held for sale at December 31, 2012. We wrote the assets down to their fair market value as of December 31, 2012 based on the sale proceeds and recorded as an impairment on the assets of $10,132,702. The loss on sale of assets reported in 2013 is due to actual sale expenses being greater than the expenses accrued as of December 31, 2012.

F-14

Table of Contents

NOTE 11 — BUSINESS SEGMENTS

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

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

Property and equipment acquisitions include accrued amounts and reclassifications.

F-15

Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion will assist in the understanding of our financial position and results of operations. The information below should be read in conjunction with the consolidated financial statements, the related notes to consolidated financial statements and our 2012 Form 10-K. Our discussion contains both historical and forward-looking information. We assess the risks and uncertainties about our business, long-term strategy and financial condition before we make any forward-looking statements but we cannot guarantee that our assessment is accurate or that our goals and projections can or will be met. Statements concerning results of future exploration, development and acquisition expenditures as well as revenue, expense and reserve levels are forward-looking statements. We make assumptions about commodity prices, drilling results, production costs, administrative expenses and interest costs that we believe are reasonable based on currently available information. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control.

We intend to focus our development and exploration efforts in our West Virginia properties and utilize our attractive opportunities to expand our reserve base through continuing to drill higher risk/higher reward exploratory and development drilling in the Marcellus Shale for 2013 and beyond with our new financing as discussed under item 1. Management intends to use a portion of the proceeds from the Chambers facility financing to fund this drilling program. We will evaluate our properties on a continuous basis in order to optimize our existing asset base. We plan to employ the latest drilling, completion, and fracturing technology in all of our wells to enhance recoverability and accelerate cash flows associated with these wells. We believe that our extensive acreage position will allow us to grow through high risk drilling in the near term.

In summary, our strategy is to increase our oil and gas reserves and production while keeping our development costs and operating costs as low as possible. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential. The success of this strategy is contingent on various risk factors, as discussed in our 2012 Form 10-K.

Results of Operations

Three months ended June 30, 2013 compared to June 30, 2012

The following table sets forth the relationship of total revenues of principal items contained in our Unaudited Consolidated Statements of Operations for the three months ended June 30, 2013 and 2012.

Total revenues of $4,671,158 for the three months ended June 30, 2013 increased $2,206,456 or 90% compared to $2,464,702 for the three months ended June 30, 2012 due to over a 100% increase in exploration and production revenue. This increase was due to an increase in natural gas and natural gas liquid (NGL) production volumes as well as an increase in natural gas prices. The increase in natural gas and NGL volumes was the result of our 2012 drilling. This increase in revenue was offset by a decrease in oil production volumes and prices and NGL prices. Revenue from natural gas sales increased by $2,499,431 or 191% when compared to 2012 which was the result of higher prices and production volumes. Natural gas volumes increased 427,804 MCFs or 106% when compared to 2012. The price of natural gas increased $1.34 or 41% when compared to 2012. Revenues from NGL sales for the three months ended June 30, 2013 increased $316,980 or 66% when compared to 2012. The average price of NGLs decreased from $0.86 per gallon for the three months ended June 30, 2012 to $0.77 per gallon for the three months ended June 30, 2013. Total production for NGLs was 1,036,161 gallons for the three months ended June 30, 2013 which was an increase of 477,148 gallons or 85% compared to 559,013 gallons for the three months ended June 30, 2012. Oil sales decreased $312,051 or 90% in 2013 due to lower production volumes associated with the sale of the shallow wells in January 2013 and lower product prices when comparing 2013 to 2012. Oil volumes decreased from 3,956 bbls for the three months ended June 30, 2012 to 445 bbls for the three months ended June 30, 2013 for a 3,511 decrease in production. The price of oil decreased from an average of $88.02/bbl for the three months ended June 30, 2012 to an average of $81.37 for the three months ended June 30, 2013 or a $6.65 decrease in average price. For the period of April 1, 2013 through May 25, 2013, six wells in Wetzel county were shut in due to pipeline repairs and testing. Our pipeline transmission and corporate revenue decreased from $327,340 to $29,343 primarily due to the sale of most of our transmission lines with our shallow wells in January 2013.

1

Table of Contents

Production costs increased $1,140,600 for the three months ended June 30, 2013 as compared to the same period for 2012, primarily due to an increase in transportation fees and natural gas liquid processing fees, associated with the increased production in 2013.

Depreciation, depletion, amortization and accretion expense stayed relatively the same for the three months June 30, 2013 compared to the same period for 2012, primarily due to the sale of the shallow assets in January 2013, which was offset by the increased production from our other wells.

Selling, general and administrative expense decreased $369,126 or 19% for the three months ended June 30, 2013 as compared to the same period for 2012, primarily due to approximately $400,000 of share-based compensation related to 2012 employee separation agreements.

Interest expense increased $2,466,487 or 172% for the three months ended June 30, 2013 as compared to the same period for 2012 due to higher loan balance. For the three months ended June 30, 2013 the average loan balance was $76,204,144 compared to $40,368,980 for the same period in 2012.

Gain on warrant derivative for the three months ended June 30, 2013 was $467,762 as compared to $843,340 for the same period last year. This represents the change in value of the put option associated with our warrant derivative liability.

Gain on derivative assets for the three months ended June 30, 2013 was $659,356. This represents the increase in the mark to market value of our gas hedges.

Net loss for the three months ended June 30, 2013 was $2,618,595 compared to a net loss of $1,870, 421 for the same period of 2012. This increase in the net loss is due primarily to the increase in interest expense which was offset partially by a decrease in loss from operations.

Six months ended June 30, 2013 compared to June 30, 2012

The following table sets forth the relationship of total revenues of principal items contained in our Unaudited Consolidated Statements of Operations for the six months ended June 30, 2013 and 2012.

Total revenues of $8,280,484 for the six months ended June 30, 2013 increased $2,898,254 or 54% compared to $5,382,230 for the six months ended June 30, 2012 due to a 67% increase in our exploration and production revenue. This increase was due to an increase in natural gas and NGL production volumes as well as an increase in natural gas prices. The increase in natural gas and NGL volumes was the result of our 2012 drilling. This increase in revenue was offset by a decrease in oil production volumes and prices. Revenue from natural gas sales increased by $3,773,169 or 133% when compared to 2012, which was the result of higher prices and production volumes. Natural gas volumes increased 691,198 MCFs or 81% when compared to 2012. The price of natural gas increased $0.96 or 29% when compared to 2012. Revenues from NGL sales for the six months ended June 30, 2013 decreased $8,657 or 1% when compared to 2012. The average price of NGLs decreased from $1.35 per gallon for the six months ended June 30, 2012 to $0.72 per gallon for the six months ended June 30, 2013. Total production for NGLs was 2,082,105 gallons for the six months ended June 30, 2013 which was an increase of 961,520 gallons or 86% compared to 1,120,585 gallons for the six months ended June 30, 2012. Oil sales decreased $458,250 or 81% in 2013 due to lower production volumes associated with the sale of the shallow wells in January 2013 and lower product prices when comparing 2013 to 2012. Oil volumes decreased from 5,803 bbls for the six months ended June 30, 2012 to 1,257 bbls for the six months ended June 30, 2013 for a 4,546 decrease in production. The price of oil decreased from an average of $97.56/bbl for the six months ended June 30, 2012 to an average of $85.83 for the six months ended June 30, 2013, or an $11.73 decrease in average price. For the period of February 18, 2013 through May 25, 2013, six wells in Wetzel county were shut in due to pipeline repairs and testing. Our pipeline transmission and corporate revenue decreased from $472,886 to $64,878 primarily due to the sale of most of our transmission lines with our shallow wells in January 2013.

2

Table of Contents

Production costs increased $1,839,074 for the six months ended June 30, 2013 as compared to the same period for 2012, primarily due to an increase in transportation fees and natural gas liquid processing fees, associated with the increased production in 2013.

Depreciation, depletion, amortization and accretion expense decreased $374,438 for the six months June 30, 2013 compared to the same period for 2012, primarily due to the selling of the shallow assets in January 2013.

Selling, general and administrative expense decreased $221,562 or 7% for the six months ended June 30, 2013 as compared to the same period for 2012, primarily due to approximately $400,000 of share-based compensation related to 2012 employee separation agreements which was offset by higher legal and professional fees in 2013.

Interest expense increased $3,930,490 or 210% for the six months ended June 30, 2013 as compared to the same period for 2012 due to higher loan balance. The average loan balance for the six months ended June 30, 2013 was $67,860,909 compared to $27,594,850 for the same period in 2012.

Gain on warrant derivative for the six months ended June 30, 2013 was $591,439 as compared to $843,440 for the same period last year. This represents the change in value of the put option associated with our warrant derivative liability.

Gain on derivative assets for the six months ended June 30, 2013 was $659,356. This represents the increase in the mark to market value of the our gas hedges.

Net loss for the six months ended June 30, 2013 was $5,311,733 compared to a net loss of $3,366,889 for the same period of 2012. This increase in the net loss is due primarily to the increase in interest expense which was offset partially by a decrease in loss from operations.

Liquidity and Capital Resources

Historically, we have satisfied our working capital needs with borrowed funds and the proceeds of acreage sales. At June 30, 2013, we had positive working capital of $15,261,048 compared to positive working capital of $2,487,924 at December 31, 2012. This increase in working capital is due to the additional loan proceeds received in February, 2013.

During the first six months of 2013, net cash used by operating activities was $2,854,419 compared to $13,786,610 net cash used for the same period of 2012. This increase in cash flow from operations was due to a decrease in the amount paid on our accounts payable and revenue payable during the first six months of 2013.

We expect our cash flow from operations for 2013, compared to the comparable period in 2012, to improve because of higher projected production from the drilling program due to increase in the number of producing wells. However, if our drilling or realized commodity prices miss expectations, our cash flow provided by operations may differ materially from our expectations.

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 the first six months of 2013, net cash used by investing activities was $5,042,105 compared to net cash used of $14,055,489 in the same period in 2012. The change was due to lower capital expenditures in 2013 and increased proceeds from the sale of assets in 2013.

During the first six months of 2013, net cash provided by financing activities was $24,885,979 compared to net cash provided of $32,722,795 for the same period in 2012. This decrease was due to lower proceeds from borrowing in 2013.

We anticipate meeting our working capital needs with revenues from our ongoing operations, particularly from our wells in Marshall and Wetzel counties in West Virginia and additional borrowing.

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 Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2012.

3

Table of Contents

Inflation

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

Forward-looking and Cautionary Statements

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

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

Item 4. Controls and Procedures

We maintain disclosure controls and procedures that are designed to be effective in providing reasonable assurance that information required to be disclosed in our reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission (“SEC”), and that such information is accumulated and communicated to our management to allow timely decisions regarding required disclosure.

In designing and evaluating disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute assurance of achieving the desired objectives. Also, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. The design of any system of controls is based, in part, upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based upon that evaluation, management concluded that our disclosure controls and procedures were effective to cause the information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods prescribed by SEC, and that such information is accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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.

4

Table of Contents

PART II

Item 1. Legal Proceedings

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

On May 11, 2011, we filed an action in the U.S. District Court for the Northern District of West Virginia against EQT Corporation, a Pennsylvania corporation (Trans Energy, Inc., et al. v. EQT Corporation). The action relates to our attempt to quiet title to certain oil and gas properties referred to as the Blackshere Lease, consisting of approximately 22 oil and/or gas wells on the Blackshere Lease. The defendant, EQT Corporation, has filed with the Court an answer and counterclaim wherein it claims it holds title to the natural gas within and underlying the Blackshere Lease. We believe that we will ultimately prevail in the action, but it is too early in the proceedings to accurately assess the final outcome. Currently we have no plans to drill on this acreage. On September 5, 2012, the parties filed competing motions seeking summary judgment in this case. On November 26, 2012, the Court granted our motion for summary judgment and denied the defendant’s motions for declaratory judgment and summary judgment. At this time, the defendant has appealed the Court’s decision.

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

On January 14, 2013, Abcouwer filed an action in the Circuit Court of Kanawha County, West Virginia against us, and two individual defendants currently on our Board of Directors – William F. Woodburn (“Woodburn”) and Loren E. Bagley (“Bagley”). The matter is identified as Civil Action No. 13-C-56 and was assigned to the Honorable Carrie L. Webster. In his complaint, Abcouwer alleges that Plaintiff and Defendants entered into a verbal agreement that required us 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. We believe that no such agreement existed and that Abcouwer’s claims are wholly without merit. On March 25, 2013, we filed an answer denying the existence of any liability and asserting, in the alternative, counterclaims for fraud and breach of fiduciary duty. Our counterclaims allege that, to the extent a binding agreement between Abcouwer and us existed, Abcouwer failed to disclose such agreement to us despite a duty to do so.

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.

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

We may be engaged in various other 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.

5

Table of Contents

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not Applicable

Item 3. Defaults Upon Senior Securities

Not Applicable

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

None.

Item 6. Exhibits