Form 10-Q

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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.

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

The accompanying unaudited interim condensed 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 States 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 a full set of financial statements prepared in accordance with GAAP. The information furnished in the interim condensed 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, 2013 Annual Report on Form 10-K. Operating results for the nine months ended September 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

On May 21, 2014 (“Funding Date”), the Company’s wholly-owned subsidiary, American Shale Development Inc. (“American Shale”), 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 certain of its undeveloped leasehold amounting to approximately 2,239 net acres, (ii) an over-riding royalty interest of 1.5% in certain 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 was 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 is closed prior to December 31, 2014. The Company has recognized a deferred gain on sale of assets in the current liabilities section of the Condensed Consolidated Balance Sheet in the amount of $6,959,816 because the Company has the option of repurchasing the undivided interest across all of its undeveloped leasehold, plus the overriding royalty interest in its Wetzel County leasehold by December 31, 2014.

Although the deferred gain of $6,959,816 noted above represents a credit on our balance sheet that will never be repaid in cash (i.e., it will either be realized in earnings upon expiration of American Shale’s repurchase option, or will be reclassified back to American Shale’s property balance upon its exercise of the repurchase option), we believe that such amount results in our current ratio not exceeding 1-to-1 as of September 30, 2014, as required by the covenants of our out credit agreement (the “Credit Agreement”) with Morgan Stanley Capital Group Inc. (“Morgan Stanley”), as the administrative agent, and several lenders thereunder (collectively, the “Lenders”).

The Credit Agreement provides that the failure to observe any financial covenant will constitute an event of default, and Morgan Stanley, at the request of the majority Lenders, may terminate the commitments under the Credit Agreement and cause all of the Company’s obligations under the Credit Agreement to immediately become due and payable, upon notice to the Company. The event of default is deemed continuing until waived in writing by the Lenders. The Company has entered into discussions with the Lenders in hopes of obtaining a favorable resolution to the situation. No assurances can be given at this time that the matter will be resolved in a satisfactory manner.

In the event we are unable to obtain a waiver of default from the Lenders, there would be substantial doubt about our ability to continue as a going concern as all outstanding obligations under the Credit Agreement would come due. Consequently, all outstanding obligations under the Credit Agreement as of September 30, 2014 are reflected on the balance sheet as current maturities on long-term debt.

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the 2013 Form 10-K, and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report.

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.

The unaudited 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 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.

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, timing and costs associated with our asset retirement obligations, estimates of fair value of derivative instruments and estimates used in stock-based compensation calculations. Reserve estimates are by their nature inherently imprecise.

In connection with obtaining the Morgan Stanley financing in May 2014 and subsequent borrowings, we incurred fees and expenses of $4,706,656. These fees and expenses 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.

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 were being amortized over the same period as the Tranche A loan. In addition, when we obtained new financing 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 were being amortized over the life of the loan using the straight-line method, which approximates the effective interest method. When we obtained the Morgan Stanley financing, the remaining balance of the finance fees related to the Chambers financing were expensed due to the payoff of the related loan.

Amortization of financing costs for the three months ended September 30, 2014 and 2013 were $555,072 and $369,859, respectively. Amortization of financing costs for the nine months ended September 30, 2014 and 2013 were $905,875 and $701,807, respectively. Our policy is to recognize twelve months of deferred financing costs as a current asset and the remaining balance of deferred financing costs as other assets in the condensed consolidated balance sheets.

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.

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.

Generally accepted accounting principles require that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicated that the carrying amount of an asset may not be recoverable. The Company, at least annually, reviews its proved oil and gas properties for impairment by comparing the carrying value of its properties to the properties’ undiscounted estimated future net cash flows. Estimates of future oil and gas prices, operating costs, and production are utilized in determining undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company’s independent reserve engineer’s estimate of proved reserves, which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties.

In 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.

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.

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.

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 nine months ended September 30:

At September 30, 2014 and December 31, 2013, our current portion of the asset retirement obligation was $0.

At September 30, 2014, the Company had net operating loss carry forwards (“NOLs”) for future years of approximately $65.0 million. These NOLs will expire at various dates through 2033. There is no current tax provision for the three or nine months ended September 30, 2014 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 could be limited if there is a substantial change in ownership of the Company and is contingent on future earnings.

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 September 30, 2014 or December 31, 2013 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 2010 remain open to examination by U.S. federal and state tax jurisdictions, however prior year net operating losses remain open for examination.

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 September 30, 2014 and December 31, 2013. 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 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 7 – Derivative and Hedging Financial Instruments for tabular presentation of the Company’s gross and net derivative positions.

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 $214,906 and $283,892 for the three months ended September 30, 2014 and 2013, respectively. We also recorded total share-based compensation of $698,122 and $919,755 for the nine months ended September 30, 2014 and 2013, respectively.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principle based approach. The core principal of the standard is that revenue should be recognized when the transfer of promised goods or services is made in an amount that the entity expects to be entitled to in exchange for the transfer of goods and services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. This standard will be effective for financial statements issued by public companies for annual reporting periods beginning after December 15, 2016. Early adoption is not permitted. The Company is currently evaluating the potential impact of ASU 2014-09 on the financial statements.

The Company has reviewed all other recently issued accounting standards in order to determine their effects, if any, on the consolidated financial statements. Based on that review, the Company believes that none of these standards will have a significant effect on current or future earnings or results of operations.

Certain reclassifications have been made to the 2013 financial presentation to correspond to the current year’s format.

We have incurred net losses for the three months and nine months ended September 30, 2014, of $(7,305,954) and $(19,784,100), 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 nine months ended September 30, 2014 and 2013 were primarily funded using net proceeds from notes payable to Chambers and Morgan Stanley (see Note 6), in addition to proceeds from the sale of certain oil and gas properties (see Note 5).

NOTE 3 — ACCOUNTS RECEIVABLE DUE FROM DRILLING OPERATOR 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 $6,382,401 and $2,698,302 for charges incurred, but not paid, as of September 30, 2014 and December 31, 2013, respectively. The amount due to the operator reported at September 30, 2014 has been reduced for consideration received from the Republic purchase and sale agreement, which is to be paid in the form of a credit against the expenses incurred by Republic Energy Ventures on behalf of American Shale (see Note 5). The amount due to the operator reported at September 30, 2014 and December 31, 2013, is net of a $372,943 and $637,667 credit respectively, related to a refund of prior drilling costs previously invoiced to America Shale for wells we are not participating in as well as intercompany charges related to employee salary reimbursements, travel expenses, and lease costs. The accounts receivable from drilling operator reflects invoices related to reimbursable expenses.

Total additions for oil and gas properties for the three months ended September 30, 2014 and 2013 were $8,056,902 and $12,249,585, respectively. Total additions for oil and gas properties for the nine months ended September 30, 2014 and 2013 were $24,064,991 and $24,942,086, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $2,511,970 and $962,089 for the three months ended September 30, 2014 and 2013, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $6,750,318 and $2,296,046 for the nine months ended September 30, 2014 and 2013, respectively.

On January 24, 2013, we closed the sale of our interests in certain non-core assets for approximately $2.6 million 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 has commenced 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.

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

On December 13, 2013, the Company and 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 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. In February 2014, the Company received $489,608 related to curable title defects. The proceeds were applied to a receivable of $230,064 recorded at December 31, 2013. The remaining $259,544 is reported, net of expenses, as gain on sale of assets for the period ended September 30, 2014.

On May 21, 2014 (“Funding Date”), American Shale 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 is closed prior to December 31, 2014. The Company has recognized a deferred gain on sale of assets in the current liabilities section of the Condensed Consolidated Balance Sheet in the amount of $6,959,816 because the Company has the option of repurchasing the undivided interest across all of its undeveloped leasehold, plus the overriding royalty interest in its Wetzel County leasehold by December 31, 2014.

As part of the Republic PSA, Republic also agreed to amend the Amended Joint Development Agreement with American Shale (the “AJDA”). 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 a third party 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.

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. 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.

On August 25, 2014, Trans Energy entered into a civil Consent Decree with the EPA with respect to the CWA Matter and related issues that were discovered based upon an internal audit. Fines associated with the Consent Decree amount to $3,000,000.

As part of the Consent Decree, Trans Energy is required to perform certain restoration activities at affected pond, well pad and access roads at multiple sites. We have preliminarily estimated the cost of early components of restoration over all the sites involved to be an additional $3,000,000, net to Trans Energy. Overall costs may range as high as $9,000,000. The restoration will be performed during the 2015, 2016 and 2017 construction seasons. Our estimate of costs to us will be refined, and may increase or decrease as we submit work plans to the EPA for approval to perform these restoration activities. Additionally, we are exploring avenues to offset some costs to the extent they are reimbursable through our joint venture agreements and the purchase or trading of wetland credits.

On October 1, 2014, Trans Energy, Inc. pleaded guilty to three misdemeanor charges related to Unauthorized Discharge into a Water of the United States in violation of the Clean Water Act. In connection with this plea, the Company agreed to pay a $600,000 fine and was placed on probation for a period of two years. This fine was consistent with the amount the Company anticipated as disclosed in the Form 8-K filed September 3, 2014, that described the civil settlement reached with the Environmental Protection Agency (“EPA”).

As a result of this plea and the previously disclosed settlement agreement, all civil and criminal matters arising out of the EPA’s investigation and complaints arising out of the ponds in Marshall and Wetzel Counties West Virginia have been resolved.

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”).

The ASD Credit Agreement provided that the Lenders would 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 were not direct parties to the ASD Credit Agreement, but were 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 due annually. These OID costs were netted against notes payable and were being amortized over the life of the loan using the straight-line method, which approximates the effective interest method. For the nine months ended September 30, 2014 and 2013, $1,189,400 and $794,118 of the OID was amortized as interest expense, respectively.

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 was due monthly at 10% plus the greater of 1% or the 3 month LIBOR rate (11% at time of payoff). Principal was due at maturity, February 28, 2015. We had 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. American Shale was obligated 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 was defined as $12.5 million less all interest payments actually made with respect to the $25 million loan prior to such date.

The Company estimated its liability related to the Termination Fee to be approximately $6.8 million ($12.5 million gross fee, less $5.7 million in interest payments) (the “Termination Fee Liability”).

The Termination Fee Liability was recorded on the Company’s condensed consolidated balance sheet as an addition to the related debt balance, offset by an equal debt discount of $6.8 million (the “Termination Fee Debt Discount”). The Termination Fee Debt Discount was being amortized to interest expense through the expected payment date of February 28, 2015; however, such amortization was accelerated upon payment of the Termination Fee in conjunction with the Morgan Stanley financing as detailed below. At repayment of the loan the Termination Fee was computed to be $9,077,778. For the three and nine months ended September 30, 2014, the Company recorded $0 and $3,940,689 of amortization related to the Termination Fee.

During the three and nine months ended September 30, 2014, the Company recorded interest expense of $0 and $1,115,280 related to the amortization of the Termination Fee Debt Discount.

The A&R Credit Agreement included a contingent interest provision that added 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. American Shale’s Consolidated Leverage Ratio exceeded the allowed level at September 30, 2012, and quarterly thereafter. Therefore, the contingent interest provision had been applied and $1,149,969 and $2,030,050 was added to the principal balance and interest expense in 2014 (through the date of the repayment) and September 30, 2013, respectively.

For the months of August, September, and October 2013, Chambers amended the ASD 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 was being amortized over the three month period. August, September and October 2013 interest of $2,186,038 was 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 7). There were no other changes to the terms of the loan. The additional funds were received December 20, 2013.

On May 21, 2014, our wholly owned subsidiary, American Shale, entered into a credit agreement (hereafter the “Credit Agreement”) by and among American Shale, several lenders (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 plus a PIK fee of $593,750, 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 (collectively, the Morgan Stanley Financing).

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, the loans will bear interest at an additional 2% per annum above the initial rate, and with respect to other events of default, may bear interest at the higher default rate. Interest will be due and payable monthly in arrears. During the three months ending September 30,2014, the Company recorded interest expense of $1,145,486 related to the Credit Agreement.

The initial loan was advanced as a single funding of $102.5 million plus a PIK fee of $593,750 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. 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. 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 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 will be charged 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. 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.

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 the Agent. The NPI Agreement provides that subsequent to the repayment of the Loans, American Shale will pay a net profits interest to the 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. The 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. At June 30, 2014, the company recorded a discount related to the NPI of $3,339,376 on proved property and $733,034 on unproved property. The total value recorded as a discount on loan payable related to the NPI is $4,072,410. For the three months ended September 30, 2014, the company recorded accretion of the discount related to the NPI in the amount of $296,175 which is computed using the straight line method over the life of the loan, which approximates the effective interest method.

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 the Agent prior to such date. In such event, 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 August 20, 2014, American Shale made a $5 million draw in accordance with the Credit Agreement.

The following table summarizes the components of total debt recorded on the Company’s consolidated balance sheets as of September 30, 2014 and December 31, 2013:

On May 9, 2013 our subsidiary, American Shale, entered into costless collars (“BP Hedge”) 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 1.6 MMBtu is 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 $32,174 and $(125,773) at September 30, 2014 and December 31, 2013, respectively.

On May 21, 2014 American Shale, entered into fixed price hedges (“Morgan Stanley Fixed I”) covering approximately 90% of its expected natural gas production from PDP wells 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 hedges consist of long put options (floor) with strike prices ranging between $4.38 per MMBtu to $4.06 per MMBtu. The hedges begin with the June 2014 contract and end with the December 2018 contract. A total of 13,932,171 MMBtu is hedged over this period, with monthly volumes declining from a high of 444,534 MMBtu in July 2014 to 171,940 MMBtu in November 2018. The fair value of these commodity contracts was $577,585 at September 30, 2014.

On August 20, 2014 American Shale, entered into fixed price hedges (“Morgan Stanley Fixed II”) covering approximately 90% of its expected natural gas production from PDP wells 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 hedges consist of long put options (floor) with a fixed strike price of $3.92 per MMBtu. The hedges begin with the September 2014 contract and end with the December 2018 contract. A total of 10,499,038 MMBtu is hedged over this period, with monthly volumes declining from a high of 326,700 MMBtu in January 2015 to 33,200 MMBtu in November 2014. The fair value of these commodity contracts was $(878,168) at September 30, 2014.

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

The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place for gas collars and gas hedges as of September 30, 2014:

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 could 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 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 Shale entered into an agreement with the holders of all of its outstanding warrants 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 detail the fair value of derivatives recorded in the accompanying balance sheets, by category:

The table below summarizes the realized and unrealized gains and losses related to our derivative instruments for the three and nine months ended September 30, 2014 and 2013.

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

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 principal 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 September 30, 2014 and December 31, 2013 by level within the fair value hierarchy

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 7 – Derivative and Hedging Financial Instruments). The fair value of the commodity derivative assets and liabilities is estimated by the Company using the 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 were comprised of the warrants issued by the Company to purchase 19,500 shares of common stock with a put option (See Note 7—Derivative and Hedging Financial Instruments). The warrants were valued by third parties using a binomial lattice-based valuation model and were classified as Level 3 in the fair value hierarchy. The lattice-based valuation technique was utilized because it embodies all of the requisite assumptions (including the underlying price, exercise price, term, volatility, and risk-free interest-rate) that were necessary to measure the fair value of these instruments. 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:

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:

In August 2014, Trans Energy issued 400,000 shares of common stock to William F. Woodburn, a related party, for the exercise of options at a price of $0.65 per share.

In August 2014, Trans Energy issued 190,000 shares of common stock to Loren E. Bagley, a related party, for the exercise of options at a price of $0.65 per share.

In August 2014, Trans Energy issued 75,000 shares of common stock to Mark D. Woodburn, a related party, for the exercise of options at a price of $0.65 per share.

In August 2014, Trans Energy issued 10,000 shares of common stock to Brett Greene, a related party, for the exercise of options at a price of $0.65 per share.

In August 2014, Trans Energy issued 20,998 shares of common stock to Jordan Corp, a related party, in a cashless exercise of options at a price of $0.65 per share.

In August 2014, Trans Energy issued 62,963 shares of common stock to John G. Corp, a related party, in a cashless exercise of options at a price of $0.65 per share.

In April 2014, we granted 21,000 shares of stock to three employees under the long-term incentive bonus program. The 21,000 shares are not performance based and vest semi-annually over a three year period. The 21,000 shares were valued at $3.80 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 April 2014, we also granted 252,000 common stock options to six 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 $3.80 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 January 2014, Trans Energy issued 25,000 shares of common stock to Jonathan J. Corp, a related party, for the exercise of options at a price of $0.65 per share.

In January 2014, Trans Energy issued 138,331 shares of common stock to Clarence E. Smith, a 5% Beneficial owner, for the exercise of options at a price of $1.50 per share.

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 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 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.

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 by the Company for 2011 through 2014 was determined using the following assumptions:

As a result of the above stock and option transactions, we recorded total stock-based compensation of $214,906 and $283,892 for the three months ended September 30, 2014 and 2013, respectively and $698,122 and $919,755 for the nine months ended September 30, 2014 and 2013, respectively.

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 three and nine month periods ended September 30, 2014 and 2013, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of September 30 2014, potentially dilutive securities included (i) 49,500 unvested shares of restricted common stock and (ii) 3,344,994 in-the-money outstanding options.

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:

Property and equipment acquisitions include accrued amounts and reclassifications.

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 and 2014, 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 $48,000 and $48,000 for 2013 and 2014, respectively.

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 2013 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 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 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 2013 Form 10-K.

The following table sets forth the relationship of total revenues of principal items contained in our Unaudited Condensed Consolidated Statements of Operations for the three months ended September 30, 2014 and 2013.

The following table is a summary of revenues, volumes, and pricing for the three months ended September 30, 2014 and 2013.

Three Months Ended September 30, 2014 compared to the Three Months Ended September 30, 2013

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

Total revenues increased primarily due to an increase in natural gas and oil production volumes despite a decrease in natural gas and natural gas liquid (NGL) prices. The increase in natural gas and oil volumes was the result of recently drilled wells put into production. For the three months ended September 30, 2014 and 2013, respectively, we had 30 gross wells and 12.18 net wells compared to 22 gross wells and 9.13 net wells.

Production costs increased $463,059 or 17% for the three months ended September 30, 2014 as compared to the same period for 2013, primarily due to an increase in natural gas liquid transportation and processing fees associated with the increased production in 2014.

Depreciation, depletion, amortization and accretion expense increase by $2,101,434 or 213% for the three months ended September 30, 2014 compared to the same period for 2013, primarily due to the increased production volumes and lower year end reserves.

Environmental settlement and related costs increased $6,600,000 or 100% due to the settlement related to the Clean Water Act.

Selling, general and administrative expense decreased $456,259 or 28% for the three months ended September 30, 2014 as compared to the same period for 2013, primarily due to a decrease in legal fees.

Interest expense decreased $2,297,316 or 44% for the three months ended September 30, 2014 as compared to the same period for 2013 due to no contingent interest due to the payoff of the Chambers loan and a lower interest rate on the new Morgan Stanley loan. Stated interest rate was 10% on the Morgan Stanley loan in 2014 compared to 11% on the Chambers loan in 2013. For the three months ended September 30, 2014 the average loan balance was $104,276,956 compared to $77,006,006 for the same period in 2013.

Gain on warrant derivative for the three months ended September 30, 2014 was $0 as compared to a gain of $3,806 for the same period last year. This represents the change in value of the put option associated with our warrant derivative liability. The warrant was repurchased in December 2013.

Gain on commodity derivative for the three months ended September 30, 2014 was $2,963,096 as compared to a gain of $100,796 for the same period last year. This represents the increase in the fair value of the gas hedges that were entered into in connection with the Morgan Stanley financing.

Net loss for the three months ended September 30, 2014 was $7,305,954 compared to a net loss of $6,095,788 for the same period of 2013. The increase in net loss is due primarily to an increase in selling, general and administrative expense.

The following table sets forth the relationship of total revenues of principal items contained in our Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30, 2014 and 2013.

The following table is a summary of revenues, volumes, and pricing for the nine months ended September 30, 2014 and 2013.

Nine Months Ended September 30, 2014 compared to the Nine Months Ended September 30, 2013

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

Total revenues increased primarily due to an increase in natural gas, oil, and natural gas liquid (NGL) production volumes as well as an increase in natural gas and natural gas liquid (NGL) prices. The increase in natural gas, oil, and natural gas liquid (NGL) volumes was the result of recently drilled wells put into production. For the nine months ended September 30, 2014 and 2013, respectively, we had 30 gross wells and 12.18 net wells compared to 22 gross wells and 9.13 net wells.

Production costs increased $2,639,800 or 36% for the nine months ended September 30, 2014 as compared to the same period for 2013, primarily due to an increase in natural gas liquid transportation and processing fees associated with the increased production in 2014 and higher ad valorem taxes.

Depreciation, depletion, amortization and accretion expense increase by $5,083,519 or 215% for the nine months ended September 30, 2014 compared to the same period for 2013, primarily due to the increased production volumes and lower year end reserves.

Environmental settlement and related costs increased $6,600,000 or 100% due to the settlement related to the Clean Water Act.

Selling, general and administrative expense decreased $574,390 or 12% for the nine months ended September 30, 2014 as compared to the same period for 2013, primarily due to a decrease in legal and professional fees.

Interest expense increased $5,707,262 or 52% for the nine months ended September 30, 2014 as compared to the same period for 2013 due to recording a termination fee of $3,104,200 related to the A&R Credit Agreement, amortization of debt discount in the amount of $2,825,379 and higher contingent interest due to the higher Chambers loan balance in 2014. Stated interest rate was 11% for both periods until refinancing occurred, then the interest rate for the new loan in 2014 was 10%. For the nine months ended September 30, 2014 the average loan balance was $96,598,429 compared to $70,942,773 for the same period in 2013.

Gain on warrant derivative for the nine months ended September 30, 2014 was $0 as compared to a gain of $595,245 for the same period last year. This represents the change in value of the put option associated with our warrant derivative liability. The warrant was repurchased in December 2013.

Loss on commodity derivative for the nine months ended September 30, 2014 was $62,533. This represents the decrease in the fair value of our gas hedges.

Net loss for the nine months ended September 30, 2014 was $19,784,100 compared to a net loss of $11,407,519 for the same period of 2013. This increase in net loss is due primarily to an increase in interest expense, an increase in selling, general and administrative expenses, and the loss on commodity derivatives.

Historically, we have satisfied our working capital needs with borrowed funds and the proceeds of acreage sales. At September 30, 2014, we had negative working capital of $10,313,265 compared to positive working capital of $65,897 at December 31, 2013. The decrease in working capital is primarily due to an increase in environmental settlement and related costs, accounts receivable trade and an increase in accounts payable to drilling operator.

During the first nine months of 2014, net cash provided by operating activities was $2,001,526 compared to net cash used of $3,657,984 for the same period of 2013. This increase in cash flow from operations was primarily due to higher production volumes and higher commodity prices, which were partially offset by an increase in environmental settlement and related costs.

We expect our cash flow from operations for 2014, compared to the comparable period in 2013, to improve because of higher projected production from the drilling program due to the 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 nine months of 2014, net cash used by investing activities was $8,813,793 compared to net cash used of $21,213,299 in the same period in 2013. The change was due to higher capital expenditures in 2014 that were offset by greater proceeds from the sale of assets in 2014.

During the first nine months of 2014, net cash provided by financing activities was $5,400,689 compared to net cash provided of $24,875,308 for the same period in 2013. This change was due to the fact that we increased our loan balance by a larger amount in the first six months of 2013 than in the comparable period in 2014.

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

As discussed in Note 1 to our Financial Statements, we determined that we did not meet the Current Ratio as required by the financial covenants in the Credit Agreement for the quarters ended September 30, 2014. As a result, we have triggered an event of default under the Credit Agreement, and Morgan Stanley, at the request of the majority Lenders, may terminate the commitments under the Credit Agreement and cause all of our obligations under the Credit Agreement to immediately become due and payable, upon notice to the Company. The event of default is deemed continuing until waived in writing by the Lenders. We have entered into discussions with the Lenders in hopes of obtaining a favorable resolution to the situation.

As we are no longer in compliance with the financial covenant of the Credit Agreement, additional borrowings may not permitted, and the outstanding loans may become due and payable upon notice to us by Morgan Stanley. Absent relief from the Lenders, the restructuring of all of the indebtedness under the Credit Agreement or the emergence of a new lender, our ability to meet our obligations in due course is threatened. Without additional borrowings under our Credit Agreement, we may be forced to further curtail existing operations, reduce or delay capital expenditures or sell assets to meet our operating and debt service obligations, and we may be forced to take other actions, including a restructuring of our existing indebtedness and capital structure to address our ongoing liquidity issues. Our ability to continue as a going concern is dependent upon our ability to generate sufficient cash flows or other sources of capital sufficient to repay or refinance our indebtedness, continue our operations and fund our long-term capital needs. There can be no assurance that the Company will be able to resolve the default under our Credit Agreement, to engage in a strategic transaction, sell properties or realize enough proceeds from the sale of our properties in order to fund operations or to resolve the Company’s liquidity issues.

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, 2013.

This report includes “forward-looking statements” which 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.

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 principal 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 principal 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.

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:

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. 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. The defendant’s time to appeal this judgment has passed, so this judgment in our favor is final.

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.

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.

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.

In April 2014, we granted 21,000 shares of stock to three employees under the long-term incentive bonus program. These shares were issued in a transaction not constituting a public offering as provided in Section 4(2) of the Securities Act of 1933.

In accordance with the requirements of the Securities Exchange Act of 1934, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Class		Outstanding as of November 19, 2014
Common Stock, $0.001 par value		14,404,260


Heading	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

Condensed Consolidated Balance Sheets —September 30, 2014 and December 31, 2013		F-1

Condensed Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2014 and 2013		F-3

Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2014 and 2013		F-4

Notes to Condensed Consolidated Financial Statements		F-5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		1

Item 4. Controls and Procedures		6

PART II OTHER INFORMATION

Item 1. Legal Proceedings		7

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		8

Item 3. Defaults Upon Senior Securities		8

Item 4. Mine Safety Disclosures		8

Item 5. Other Information		8

Item 6. Exhibits		8

Signatures		9


	September 30, 2014			December 31, 2013
	Unaudited			Audited
ASSETS
CURRENT ASSETS
Cash	$	1,316,254		$	2,727,832
Accounts receivable, trade		6,883,543			4,460,535
Accounts receivable from drilling operator		562,000			—
Accounts receivable, related parties		18,500			18,500
Derivative assets		780,148			—
Advance royalties		—			16,937
Prepaid expenses		1,090,689			1,065,061
Deferred financing costs, net of amortization of $337,054 and $1,308,817, respectively		1,028,142			817,938

Total current assets		11,679,276			9,106,803
OIL AND GAS PROPERTIES, USING SUCCESSFUL EFFORTS ACCOUNTING
Proved properties		99,952,561			77,961,183
Unproved properties		7,536,331			15,092,783
Pipelines		1,259,052			1,397,440
Accumulated depreciation, depletion and amortization		(21,036,700	)		(14,473,069	)

Oil and gas properties, net		87,711,244			79,978,337
PROPERTY AND EQUIPMENT, net of accumulated depreciation of $344,518 and $317,704, respectively		524,718			587,218
OTHER ASSETS
Deferred financing costs		3,341,461			139,076
Other assets		355,381			303,887

Total other assets		3,696,842			442,963

TOTAL ASSETS	$	103,612,080		$	90,115,321


	September 30, 2014			December 31, 2013
	Unaudited			Audited
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	359,836		$	632,795
Accounts payable due to drilling operator		6,382,401			2,698,302
Accounts payable, related party		1,500			1,500
Accrued expenses		4,418,063			5,302,816
Deferred gain on sale of assets		6,959,817			—
Environmental settlement and related costs		3,600,000			—
Revenue payable		45,284			127,106
Commodity derivative liability		217,451			58,176
Notes payable — current		104,325,704			14,897
Notes payable, related party					205,314

Total current liabilities		126,310,056			9,040,906
LONG-TERM LIABILITIES
Notes payable, net		0			89,204,102
Environmental settlement and related costs		3,000,000			—
Asset retirement obligations		78,556			41,440
Commodity derivative liability		831,106			67,597

Total long-term liabilities		108,227,177			89,313,139

Total liabilities		3,909,662			98,354,045
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; 14,406,260 and 13,457,978 shares issued, respectively, and 14,404,260 and 13,455,978 shares outstanding, respectively		14,406			13,458
Additional paid-in capital		43,970,530			42,556,292
Treasury stock, at cost, 2,000 shares		(1,950	)		(1,950	)
Accumulated deficit		(70,590,624	)		(50,806,524	)

Total stockholders’ equity (deficit)		(26,607,638	)		(8,238,724	)

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	103,612,080		$	90,115,321

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if smaller reporting company)

Smaller reporting company


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
OPERATING REVENUES
Oil and gas sales	$	6,667,618		$	4,343,739		$	24,816,633		$	12,559,344
Gas transportation, gathering, and processing		44,256			35,203			121,875			97,093
Other income		63,407			25,801			69,840			28,790

Total operating revenues		6,775,281			4,404,743			25,008,348			12,685,227
OPERATING COSTS AND EXPENSES
Production costs		3,258,132			2,795,073			10,003,364			7,363,564
Depreciation, depletion, amortization and accretion		3,088,104			986,670			7,448,799			2,365,280
Environmental settlement and related costs		6,600,000			—			6,600,000			—
Selling, general and administrative		1,176,853			1,633,112			4,159,149			4,733,539

Total operating costs and expenses		14,123,089			5,414,855			28,211,312			14,462,383
(Loss) Gain on sale of assets		(18,480	)		6,887			188,616			(1,900	)

LOSS FROM OPERATIONS		(7,366,288	)		(1,003,225	)		(3,014,348	)		(1,779,056	)
OTHER INCOME (EXPENSES)
Interest income		550			3,463			2,045			18,142
Interest expense		(2,903,312	)		(5,200,628	)		(16,709,264	)		(11,002,002	)
Gain on warrant derivatives		—			3,806			—			595,245
Gain (loss) on derivative assets		2,963,096			100,796			(62,533	)		760,152

Total other income (expenses)		60,334			(5,092,563	)		(16,769,752	)		(9,628,463	)

NET LOSS BEFORE INCOME TAXES		(7,305,954	)		(6,095,788	)		(19,784,100	)		(11,407,519	)
INCOME TAX		—			—			—			—

NET LOSS	$	(7,305,954	)	$	(6,095,788	)	$	(19,784,100	)	$	(11,407,519	)
NET LOSS PER SHARE — BASIC AND DILUTED	$	(.52	)	$	(.46	)	$	(1.44	)	$	(.86	)
WEIGHTED AVERAGE SHARES — BASIC AND DILUTED		14,026,790			13,317,978			13,742,149			13,264,077


	2014		2013
Asset retirement obligations at beginning of period	$	41,440	$	28,317
Liabilities incurred during the period		34,116		689
Accretion expense		3,000		2,760

Asset retirement obligations at end of period	$	78,556	$	31,766


	September 30,			December 31,
	2014			2013
	(unaudited)			(audited)
ASD Credit Agreement	$	—		$	50,000,000
Unamortized Original Issuance Discount - ASD		—			(1,235,294	)
PIK Contingent Interest Expense		—			2,530,050
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		8,189			19,239
ASD Credit Agreement - Morgan Stanley Tranche A		107,500,000			—
ASD Credit Agreement - Morgan Stanley PIK Fee		593,750			—
ASD Credit Agreement - Morgan Stanley NPI		(3,776,235	)		—

Total debt	$	104,325,704		$	89,424,313


Contract Period of BP Hedge	Volumes		Weighted- Average Floor Price		Weighted- Average Ceiling Price
	(MMBtu)		(per MMBtu)		(per MMBtu)
2014		371,808	$	4.00	$	4.28
2015		464,825	$	4.00	$	4.28

All gas collars*		836,633


Contract Period of Morgan Stanley Fixed I	Volumes		Weighted- Average Fixed Price
	(MMBtu)		(per MMBtu)
2014		971,987	$	4.38
2015		3,581,893	$	4.11
2016		3,058,358	$	4.06
2017		2,528,996	$	4.16
2018		2,193,294	$	4.29

All gas hedges*		12,334,528


	As of September 30, 2014
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Commodity derivative	Current assets	$	780,148	Current liabilities	$	217,451
Commodity derivative	Noncurrent assets		—	Noncurrent liabilities		831,106

		$	780,148		$	1,048,557


	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

		$	—		$	125,773


	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Realized gains (loss) on commodity derivative	$	530,150	$	237,419		$	80,103		$	237,419
Change in fair value of commodity derivative		2,432,946		(136,623	)		(142,636	)		522,733
Change in fair value of warrant derivative liability		—		3,806			—			595,245

Total realized and unrealized gains (loss) recorded	$	2,963,096	$	104,602		$	(62,533	)	$	1,355,397


	Level 1		Level 2		Level 3		Total
September 30, 2014
ASSETS:
Commodity contracts		—	$	780,148		—	$	780,148
LIABILITIES:
Commodity contracts		—	$	1,048,557		—	$	1,048,557

December 31, 2013
ASSETS:
Commodity contracts		—		—		—		—
LIABILITIES:
Commodity contracts		—	$	125,773		—	$	125,773


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	%


	September 30, 2014		September 30, 2013
Balance as of beginning of period	$	—	$	(2,216,839	)
Total realized and unrealized gains (losses)
Included in earnings		—		3,806
Issuances		—		—
Settlements		—		—
Transfers in and out of Level 3		—		—

Balance as of September 30	$	—	$	(2,213,033	)

Change in unrealized gains included in earnings Relating to instruments still held as of September 30	$	—	$	(3,806	)


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


	Number of Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Fair Value
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
Granted		252,000		$	3.80
Exercised		(938,331	)	$	0.78
Forfeited		(14,000	)	$	2.43
Expired		—			—

Outstanding September 30, 2014		3,344,993		$	2.01		1.79 Years	$	6,723,438
Exercisable at September 30, 2014		3,023,329		$	2.09			$	6,318,758
Unvested at September 30, 2014		321,664


	Three Months Ended
	September 30,				Increase/
	2014		2013		(Decrease)
Natural gas sales	$	5,217,908	$	3,541,101	$	1,676,807		47.4	%
Oil sales	$	20,119	$	17,277	$	2,842		16.4	%
Natural gas liquid sales	$	1,429,591	$	785,361	$	644,230		82.0	%

Total Oil & Gas Sales	$	6,667,618	$	4,343,739	$	2,323,879		53.5	%
Transportation and other revenue	$	107,663	$	61,004	$	46,659		76.5	%

Total revenue	$	6,775,281	$	4,404,743	$	2,370,538		53.8	%
Net Production
Natural gas sales (MCF)		1,751,042		958,706		792,336		82.6	%
Oil sales (Bbls)		250		193		57		29.5	%
Natural gas liquids (gallons)		1,613,096		1,061,830		551,266		51.9	%
Natural Gas Equivalent (MCFe)		1,982,984		1,111,554		871,429		78.4	%
Average Sales Price per Unit
Natural Gas (MCF)	$	2.98	$	3.69	$	(0.71	)	-19.2	%
Oil(Bbl)	$	80.48	$	89.52	$	(9.04	)	-10.1	%
Natural gas liquids (gallons)	$	.89	$	0.74	$	0.15		20.3	%
Natural Gas Equivalent (MCFe)	$	3.36	$	3.91	$	(0.55	)	-14.1	%


	Three Months Ended September 30,
	2014		2013
Costs and Expenses Per MCFE of Production:
Production Expenses	$	1.41	$	2.39
Production Taxes		0.25		0.12
G&A Expenses (Excluding Share-Based Compensation)		3.79		1.21
Non-Cash Shared-Based Compensation		0.14		0.26
Depletion of Oil and Natural Gas Properties		1.45		0.87
Impairment of Oil and Natural Gas Properties		—		—
Depreciation and Amortization		0.10		0.02
Accretion of Discount on Asset Retirement Obligation		—		—


	For the Three Months Ended September 30	Exploration and Production		Pipeline Transmission			Corporate			Total
Revenue	2014	$	6,667,618	$	44,256		$	63,407		$	6,775,281
	2013		4,343,739		35,203			25,801			4,404,743
Income (Loss) from operations	2014		368,873		(21,715	)		(7,713,446	)		(7,366,288	)
	2013		862,737		(10,376	)		(1,855,586	)		(1,003,225	)
Interest expense	2014		2,901,745		—			1,567			2,903,312
	2013		5,200,033		—			595			5,200,628
Depreciation, depletion, amortization and accretion	2014		3,087,854		250			—			3,088,104
	2013		986,393		277			—			986,670
Property and equipment acquisitions, including oil and gas properties	2014		8,056,902		—			6,383			8,063,285
	2013		12,242,765		10,000			—			12,252,765

	For the Nine Months Ended September 30	Exploration and Production		Pipeline Transmission			Corporate			Total
Revenue	2014	$	24,816,633	$	121,875		$	69,840		$	25,008,348
	2013		12,559,344		97,093			28,790			12,685,227
Income (Loss) from operations	2014		7,667,821		7,141			(10,689,310	)		(3,014,348	)
	2013		2,900,923		21,153			(4,701,132	)		(1,779,056	)
Interest expense	2014		16,703,108		—			6,156			16,709,264
	2013		10,995,490		—			6,512			11,002,002
Depreciation, depletion, amortization and accretion	2014		7,447,943		856			—			7,448,799
	2013		2,364,950		330			—			2,365,280
Property and equipment acquisitions, including oil and gas properties	2014		24,064,991		—			8,470			24,073,461
	2013		24,942,086		10,000			—			24,952,086
Total assets, net of intercompany accounts:
September 30, 2014			103,597,410		14,670			—			103,612,080
December 31, 2013			90,098,192		17,129			—			90,115,321


	Three months ended September 30,
	2014			2013
Total revenues	$	6,775,281		$	4,404,743
Total costs and expenses		(14,123,089	)		(5,414,855	)
Gain (loss) on sale of assets		(18,480	)		6,887

Income from operations		(7,366,288	)		(1,003,225	)
Other expenses, net		60,334			(5,092,563	)
Income tax		—			—

Net loss	$	(7,305,954	)	$	(6,095,788	)


	Nine months ended September 30,
	2014			2013
Total revenues	$	25,008,348		$	12,685,227
Total costs and expenses		(28,211,312	)		(14,462,383	)
Gain (loss) on sale of assets		188,616			(1,900	)

Income (loss) from operations		(3,014,348	)		(1,779,056	)
Other expenses, net		(16,769,752	)		(9,628,463	)
Income tax		—			—

Net loss	$	(19,784,100	)	$	(11,407,519	)


	Nine Months Ended
	September 30,				Increase/
	2014		2013		(Decrease)
Natural gas sales	$	20,982,334	$	10,142,664	$	10,839,670		106.9	%
Oil sales	$	148,209	$	125,180	$	23,029		18.4	%
Natural gas liquid sales	$	3,686,090	$	2,291,500	$	1,394,590		60.9	%

Total Oil & Gas Sales	$	24,816,633	$	12,559,344	$	12,257,289		97.6	%
Transportation and other revenue	$	191,715	$	125,883	$	65,832		52.3	%

Total revenue	$	25,008,348	$	12,685,227	$	12,323,121		97.1	%
Net Production
Natural gas sales (MCF)		4,839,952		2,499,111		2,340,841		93.7	%
Oil sales (Bbls)		1,865		1,451		414		28.5	%
Natural gas liquids (gallons)		3,701,491		3,143,936		557,555		17.7	%
Natural Gas Equivalent ( MCFe)		5,379,928		2,956,951		2,422,977		81.9	%
Average Sales Price per Unit
Natural Gas (MCF)	$	4.34	$	4.06	$	0.28		6.9	%
Oil(Bbl)	$	79.46	$	86.27	$	(6.81	)	-7.9	%
Natural gas liquids (gallons)	$	1.00	$	0.73	$	0.27		37.0	%
Natural Gas Equivalent (MCFe)	$	4.61	$	4.25	$	0.36		8.5	%


	Nine Months Ended September 30,
	2014		2013
Costs and Expenses Per MCFE of Production:
Production Expenses	$	1.58	$	0.57
Production Taxes		0.29		0.37
G&A Expenses (Excluding Share-Based Compensation)		1.87		1.29
Non-Cash Shared-Based Compensation		0.13		0.31
Depletion of Oil and Natural Gas Properties		1.34		0.78
Impairment of Oil and Natural Gas Properties		—		—
Depreciation and Amortization		0.05		0.02
Accretion of Discount on Asset Retirement Obligation		—		—


Exhibit 31.1		Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 31.2		Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

**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


		TRANS ENERGY, INC.

Date: November 19, 2014	By	/s/ JOHN G. CORP
		JOHN G. CORP
		Principal Executive Officer

Date: November 19, 2014	By	/s/ MICHAEL R. GUZZETTA
		MICHAEL R. GUZZETTA
		Treasurer