Edgar Filing: TRANS ENERGY INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if smaller reporting company)

Smaller reporting company

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2013

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

For the transition period from to

Commission File Number 0-23530

TRANS ENERGY, INC.

(Exact name of registrant as specified in its charter)

Nevada

93-0997412

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

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

(Address of principal executive offices)

Registrant’s telephone number, including area code: (304) 684-7053

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.


Class		Outstanding as of November 14, 2013
Common Stock, $0.001 par value		13,317,978

Table of Contents


Heading	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

Condensed Consolidated Balance Sheets — September 30, 2013 and December 31, 2012		F-1

Condensed Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2013 and 2012		F-3

Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2013 and 2012		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

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

Unaudited


	September 30, 2013			December 31, 2012
	Unaudited			Audited
ASSETS
CURRENT ASSETS
Cash	$	1,013,109		$	1,009,084
Accounts receivable, trade		3,597,011			3,143,766
Accounts receivable, related parties		18,500			18,500
Commodity derivative		464,874			—
Advance royalties		26,749			221,452
Prepaid expenses		812,677			407,596
Deferred financing costs, net of amortization of $1,104,332 and $402,525, respectively		817,938			603,788

Total current assets		6,750,858			5,404,186
OIL AND GAS PROPERTIES, USING SUCCESSFUL EFFORTS ACCOUNTING
Proved properties		67,651,275			47,716,195
Unproved properties		15,019,615			10,182,481
Pipelines		1,397,440			1,387,440
Accumulated depreciation, depletion and amortization		(11,105,069	)		(8,809,022	)

Oil and gas properties, net		72,963,261			50,477,094
PROPERTY AND EQUIPMENT, net of accumulated depreciation of $295,863 and $239,277, respectively		609,059			665,874
OTHER ASSETS
Assets held for sale		2,038,432			4,853,722
Deferred financing costs		343,560			735,662
Other assets		303,394			301,923
Commodity derivative		57,859			—

Total other assets		2,743,245			5,891,307


TOTAL ASSETS	$	83,066,423		$	62,438,461

See notes to unaudited condensed consolidated financial statements.

F-1

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (continued)

Unaudited


	September 30, 2013			December 31, 2012
	Unaudited			Audited
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	542,611		$	187,089
Accounts payable due to drilling operator		111,788			839,456
Accounts payable, related party		1,500			1,500
Accrued expenses		3,076,129			1,642,718
Revenue payable		150,015			225,674
Notes payable — current		14,699			19,825

Total current liabilities		3,896,742			2,916,262
LONG-TERM LIABILITIES
Notes payable, net		79,327,147			48,225,848
Asset retirement obligations		31,766			28,317
Liabilities held for sale		—			388,005
Warrant derivative liability		2,213,033			2,808,278

Total long-term liabilities		81,571,946			51,450,448

Total liabilities		85,468,688			54,366,710
COMMITMENTS AND CONTINGENCIES		—			—
STOCKHOLDERS’ EQUITY
Preferred stock; 10,000,000 shares authorized at $0.001 par value; -0- shares issued and outstanding		—			—
Common stock; 500,000,000 shares authorized at $0.001 par value; 13,319,978 and 13,238,228 shares issued, respectively, and 13,317,978 and 13,236,228 shares outstanding, respectively		13,320			13,238
Additional paid-in capital		42,065,059			41,131,636
Treasury stock, at cost, 2,000 shares		(1,950	)		(1,950	)
Accumulated deficit		(44,478,694	)		(33,071,173	)

Total stockholders’ equity (deficit)		(2,402,265	)		8,071,751


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	83,066,423		$	62,438,461

See notes to unaudited condensed consolidated financial statements.

F-2

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Operations (Unaudited)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
OPERATING REVENUES
Oil and gas sales	$	4,343,739		$	783,045		$	12,559,344		$	5,692,389
Gas transportation, gathering, and processing		35,203			98,288			97,093			285,976
Other income		25,801			2,363			28,790			57,561

Total operating revenues		4,404,743			883,696			12,685,227			6,035,926
OPERATING COSTS AND EXPENSES
Production costs		2,795,073			829,256			7,363,564			3,558,674
Depreciation, depletion, amortization and accretion		986,670			550,759			2,365,280			2,303,807
Selling, general and administrative		1,633,112			1,456,313			4,733,539			4,548,302

Total operating costs and expenses		5,414,855			2,836,328			14,462,383			10,410,783
Gain (loss) on sale of assets		6,887			43,836			(1,900	)		112,898

LOSS FROM OPERATIONS		(1,003,225	)		(1,908,796	)		(1,779,056	)		(4,261,959	)
OTHER INCOME (EXPENSES)
Interest income		3,463			3,968			18,142			17,147
Interest expense		(5,200,628	)		(1,659,934	)		(11,002,002	)		(3,530,819	)
Gain (loss) on warrant derivatives		3,806			(63,023	)		595,245			780,317
Gain (loss) on commodity derivative		100,796			—			760,152			639

Total other income (expenses)		(5,092,563	)		(1,718,989	)		(9,628,463	)		(2,732,716	)

NET LOSS BEFORE INCOME TAXES		(6,095,788	)		(3,627,785	)		(11,407,519	)		(6,994,675	)
INCOME TAX BENEFIT		—			58,013			—			58,013

NET LOSS	$	(6,095,788	)	$	(3,569,772	)	$	(11,407,519	)	$	(6,936,662	)


NET LOSS PER SHARE — BASIC AND DILUTED	$	(.46	)	$	(.27	)	$	(.86	)	$	(.53	)
WEIGHTED AVERAGE SHARES — BASIC AND DILUTED		13,317,978			13,156,578			13,264,077			13,042,264

See notes to unaudited condensed consolidated financial statements.

F-3

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	For the Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(11,407,519	)	$	(6,936,662	)
Adjustments to reconcile net loss to net cash used by operating activities:
Depreciation, depletion, amortization and accretion		2,365,280			2,303,807
Amortization of financing cost and debt discount		3,484,843			890,370
Share-based compensation		919,755			1,533,855
Loss (gain) on sale of assets		1,900			(112,898	)
Interest and legal expense added to principal		3,329,349			557,226
Unrealized gain on warrant derivative		(595,245	)		(780,317	)
Unrealized gain on commodity derivative assets		(522,733	)		—
Changes in operating assets and liabilities:
Accounts receivable, trade		(453,245	)		428,703
Accounts receivable/payable, operator		(2,098,899	)		(731,026	)
Prepaid expenses and other current assets		(250,662	)		(181,123	)
Other assets		(1,471	)		(250,487	)
Accounts payable and accrued expenses		1,646,322			(13,326,103	)
Revenue payable		(75,659	)		(89,282	)
Accounts payable related party		—			(650	)
Income tax payable		—			(4,493	)

Net cash used by operating activities		(3,657,984	)		(16,699,080	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets		2,625,025			328,466
Expenditures for oil and gas properties		(23,829,183	)		(18,122,746	)
Expenditures for property and equipment		(9,141	)		(93,244	)

Net cash used by investing activities		(21,213,299	)		(17,887,524	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of warrant		—			2,000,000
Financing costs paid		(122,230	)		(1,460,734	)
Payments on notes payable		(16,212	)		(14,869,435	)
Proceeds from notes payable		25,000,000			47,043,307
Stock options exercised		13,750			—

Net cash provided by financing activities		24,875,308			32,713,138

NET CHANGE IN CASH		4,025			(1,873,466	)

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

CASH, END OF PERIOD	$	1,013,109		$	6,012,186


SUPPLEMENTAL DISCLOSURES FOR CASH FLOW INFORMATION:
CASH PAID FOR:
Interest	$	4,482,229		$	2,676,218
Income taxes		—			—
Non-cash investing and financing activities:
Accrued expenditures for oil and gas properties	$	1,112,214		$	1,211,010
Increase in asset retirement obligation	$	689		$	27,000
Accrued expenditures for debt financing	$	401,625		$	—

See notes to unaudited condensed consolidated financial statements.

F-4

TRANS ENERGY, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited)

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 State of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. Accordingly, they do not include certain information and footnote disclosures normally included in 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, 2012 Annual Report on Form 10-K. Operating results for the nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

Significant Accounting Policies

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the 2012 Form 10-K, and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report.

Nature of Operations and Organization

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

Principles of Consolidation

The unaudited consolidated financial statements include us 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.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Our financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion, amortization, and impairment of oil and gas properties, 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.

Financing Costs

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 with Chambers. We recorded $401,625 in financing fees related to the settlement. The Opco financing fees are being amortized over the same period as the Tranche A loan. We have recorded $189,000 in amortization to record the expense for the period of April 1, 2012 to August 31, 2013 in the current period. In addition, when we obtained new financing in February 2013 and April 2012, we incurred $110,365 in fees during 2013 and $1,741,976 in 2012. These fees were recorded as financing costs and are being amortized over the life of the loan using the straight-line method, which approximates the effective interest method. Amortization of financing costs for the three months ended September 30, 2013 and 2012 were $369,859 and $142,459, respectively Amortization of financing costs for the nine months ended September 30, 2013 and 2012 were $701,807 and $473,703, 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.

F-5

Property and Equipment

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

Oil and Gas Properties

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

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

Long-Lived Assets

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

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

Derivatives

Derivatives and embedded derivatives, if applicable, are measured at fair value and recognized in the condensed consolidated balance sheets as assets or liabilities. Derivatives are classified in the condensed 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. The changes in the fair value of the derivatives are included in other income (expense) in the condensed 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 issued for equity of one of our wholly-own subsidiaries is a derivative liability. We also enter into derivative commodity contracts at times to manage or reduce commodity price risk related to our production. These commodity contracts are not designated as cash flow hedges, so changes in the fair value are recognized in other income (expense).

F-6

Asset Retirement Obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. These obligations include dismantlement, plugging and abandonment of oil and gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset which has been determined to be 50 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:


	2013		2012
Asset retirement obligations at beginning of period	$	28,317	$	256,651
Liabilities incurred during the period		689		27,000
Accretion expense		2,760		16,926

Asset retirement obligations at end of period	$	31,766	$	300,577

At September 30, 2013 and December 31, 2012, our current portion of the asset retirement obligation was $0. In addition, asset retirement obligations related to the shallow wells sold in 2013 was reported as a liability of $247,955 at December 31, 2012.

Income Taxes

At September 30, 2013, we had net operating loss carry forwards (“NOLs”) for future years of approximately $44.3 million. These NOLs will expire at various dates through 2032. The current tax provision is -0- for the three months and nine months ended September 30, 2013 due to a net operating loss for the period. The current tax benefit of $58,013 for the three months and nine months ended September 30, 2012 was based on the actual alternative minimum tax paid for 2011. No tax benefit has been recorded in the consolidated financial statements for the remaining NOLs or Alternative Minimum Tax (“AMT”) credit since the potential tax benefit is offset by a valuation allowance of the same amount. Utilization of the NOLs is contingent on future earnings and could be limited if there is a substantial change in ownership of the Company.

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

We have no material unrecognized tax benefits. No tax penalties or interest expense were accrued as of September 30, 2013 or 2012 or paid during the periods then ended. We file tax returns in the United States and states in which we have operations and are subject to taxation. Tax years subsequent to 2008 remain open to examination by U.S. federal and state tax jurisdictions, however prior year net operating losses remain open for examination.

Commitments and Contingencies

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

F-7

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

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

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

Revenue and Cost Recognition

We recognize gas revenues upon delivery of the gas to the customers’ pipeline from our pipelines when recorded as received by the customer’s meter. We recognize oil revenues when pumped and metered by the customer. We use the sales method to account for sales and imbalances of natural gas. Under this method, revenues are recognized based on actual volumes sold to purchasers. The volumes sold may differ from the volumes to which we are entitled based on our interest in the properties. These differences create imbalances which are recognized as a liability only when the imbalance exceeds the estimate of remaining reserves. We had no material imbalances as of September 30, 2013 and December 31, 2012. Costs associated with production are expensed in the period incurred.

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

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

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 06 — Derivatives for tabular presentation of the Company’s gross and net derivative positions.

Share-Based Compensation

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

We recognize share-based compensation expense on a straight-line basis over the requisite service period for the entire award. As a result of stock and option transactions, we recorded total share-based compensation of $283,892 and $517,370 for the three months ended September 30, 2013 and 2012, respectively. We also recorded total share-based compensation of $919,755 and $1,533,855 for the nine months ended September 30, 2013 and 2012, respectively.

Reclassification

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

F-8

NOTE 2 — OPERATIONS

We have incurred net losses for the three months and nine months ended September 30, 2013, of $(6,095,788) and $(11,407,519), 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. On January 24, 2013, we closed the sale of our interests in certain non-core assets for approximately $2,625,000 of net cash proceeds. The interests sold consisted of our working interest in all existing shallow wells, but we retained an overriding royalty interest of approximately 2.5% on most of the wells. In February 2013, we obtained additional financing in the amount of $25 million to be used for capital expenditures and operations.

On September 30, 2013 we entered into a Purchase and Sale Agreement (“PSA”) to sell approximately 4,900 lease acres (approximately 1,163 net acres of which were owned by us) and leasehold working interests in certain partially completed well sites located in Tyler County for approximately $7,700 per acre. The Company will receive approximately $11.2 million, of which $10.7 million is payable in cash, subject to customary adjustments as described in the PSA. The sale of the assets pursuant to the PSA is scheduled to close on or about December 13, 2013 and is to be effective as of September 1, 2013. The assets held for sale related to the PSA include leasehold costs and prepaid drilling costs an is disclosed as other assets in the Condensed Consolidated Balance Sheet. The foregoing descriptions of the PSA and the consideration payable hereunder do not purport to be complete are qualified in their entirety by reference to the complete text of the PSA, a copy of which is attached as Exhibit 99.1 to this Form 10-Q.

Assets/Liabilities held for sale

The assets held for sale at September 30, 2013, relates to the PSA and includes leasehold costs and prepaid drilling costs in Tyler county. At December 31, 2012 the assets held for sale consists of $1,840,722 related to the assets sold under the PSA and $3,013,000 related to the sale of shallow wells in January 2013. Assets held for sale are reported as other assets in the Condensed Consolidated Balance Sheet. Liabilities held for sale at December 31, 2012, $388,005 relates to the sale of the shallow wells and consists of the Asset Retirement Obligation and settlement expenses. Liabilities held for sale are reported as long-term liabilities in the Condensed Consolidated Balance Sheet

NOTE 3 — OIL AND GAS PROPERTIES

Total additions for oil and gas properties for the three months ended September 30, 2013 and 2012 were $12,249,585 and $3,875,414, respectively. Total additions for oil and gas properties for the nine months ended September 30, 2013 and 2012 were $24,942,086 and $18,124,869, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $962,089 and $491,540 for the three months ended September 30, 2013 and 2012, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $2,296,046 and $2,122,114 for the nine months ended September 30, 2013 and 2012, respectively.

NOTE 4 — ACCOUNTS PAYABLE DUE TO DRILLING OPERATOR

We have historically been the drilling operator for wells drilled on our behalf and other third parties in which we own a working interest. In 2012, another working interest owner became the drilling operator for wells in which we own a working interest. We owed the drilling operator $111,788 and $839,456 for charges incurred, but not paid, as of September 30, 2013 and December 31, 2012, respectively. The September 30, 2013 amount due to the operator is net of a $2,098,899 credit related to a refund of prior drilling costs previously invoiced to American Shale.

NOTE 5 — NOTES PAYABLE

On June 22, 2007, Trans Energy finalized a financing agreement with CIT Capital USA Inc. (“CIT”) for an amount that was ultimately increased to $30,000,000. Payment was due at maturity on June 15, 2010, for all borrowing outstanding on that date. During the subsequent period up to and including April 2, 2012, the Company and CIT made eight amendments to their initial agreement to, among other things, restructure the maturity date, confirm the principal amount following certain payments, and grant to CIT a 1.5% overriding royalty interest in each of the Stout #2H, Groves #1H and Lucey #1H wells, as well as a 1.5% overriding royalty interest in the next three horizontal wells drilled in the Marcellus Shale, which have commercial production for a period of at least 30 consecutive days and in which Trans Energy, or any of its subsidiaries, has an interest. Each 1.5% overriding royalty interest is to be proportionately reduced to the extent we or our subsidiary owns less than the full working interest in the leases, or to the extent such oil and gas leases cover less than the full mineral interest.

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

F-9

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 will lend American Shale up to $50 million, which funds would be used to develop wells and properties that we transferred to American Shale. In order to accommodate the terms of the ASD Credit Agreement Trans Energy transferred certain assets and properties to American Shale. Trans Energy is not a direct party to the ASD Credit Agreement, but is a guarantor of loans to be made thereunder as is Prima, another of our 100% wholly owned subsidiaries. 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 consist of working interests in 13 gross (7.60 net) producing Marcellus shale liquids-rich gas wells and approximately 22,000 net acres of Marcellus shale leasehold rights, located in Northwestern West Virginia in the counties of Wetzel, Marshall, Marion, Tyler, and Doddridge.

The ASD Credit Agreement was originally for a notional amount of $50 million, which was received at closing net of a $3 million Original Issue Discount (“OID”) and a $50,000 administrative fee. These OID costs are netted against notes payable and are being amortized over the life of the loan using the straight-line method, which approximates the effective interest method. Interest related to Tranche A for the three months ended September 30, 2013, was $2,424,322. For the nine months ended September 30, 2013, interest related to Tranche A was $7,280,196. Total accumulated OID amortization is $1,500,000 as of September 30, 2013. The administrative fee is due annually.

On February 28, 2013, American Shale, the Lenders and the Agent amended and restated the ASD Credit Agreement (as amended, the “A&R Credit Agreement”) in order to facilitate an increase in the principal amount of the borrowings under the facility to $75 million. The additional funds were received February 28, 2013. The other terms of the credit agreement were unchanged. Interest related to Tranche B for the three months ended September 30, 2013, was $786,793. For the nine months ended September 30, 2013, interest related to Tranche B was $1,726,376.

Interest is due monthly at 10% plus the greater of 1% or the 3 month LIBOR rate (11% at September 30, 2013). Principal is due at maturity, February 28, 2015. We have to pay interest through April 26, 2014, on any principal prepayments with respect to the original $50 million loan at the time of the prepayment prior to April 26, 2014. There is no make-whole amount with respect to the $25 million loan in the event of a prepayment. American Shale will be required to pay a “Termination Fee” with respect to the $25 million loan upon the earliest to occur of (I) a Change of Control (as defined in the A&R Credit agreement), (ii) the exercise of the Warrant Put Option (as defined in the Warrants) and (iii) certain defaults under the A&R Credit Agreement related to seeking relief from creditors or generally being unable to repay debts as they come due. The Termination Fee will be equal to $12.5 million less all interest payments actually made with respect to the $25 million loan prior to such date.

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

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

During the three months ended September 30, 2013, the Company recorded interest expense of approximately $2 million related to the cumulative amortization of the Termination Fee Debt Discount since February 28, 2013. The table below summarizes the effect on prior quarterly periods had such amortization expense been previously recorded:


	Expense Attributable to the Three Months Ended						Total
	March 31,		June 30,		September 30,
	2013		2013		2013

Amortization expense — Termination Fee Debt Discount	$	288,114	$	845,755	$	855,049	$	1,988,918

F-10

The A&R Credit Agreement is collateralized by American Shale’s natural gas and oil reserves and the guarantees discussed earlier. The A&R Credit Agreement includes reporting, financial and other restrictive covenants, as well as a contingent interest provision that adds 1% of the outstanding principal amount of the loan to the loan balance for any quarter in which American Shale’s Consolidated Leverage 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 has been applied and $1,515,000 was added to the principal balance and interest expense in 2013. A contingent interest amount of $532,388 is included in accrued expenses in anticipation of exceeding the September 30, 2013 level.

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 is being amortized over the three month period. August and September 2013 interest of $1,439,349 has been added to the principal balance of the loan.

The following table summarizes the components of total debt recorded on the Company’s consolidated balance sheets as of September 30, 2013 and December 31, 2012:


	September 30,			December 31,
	2013			2012
	(unaudited)			(audited)

ASD Credit Agreement	$	50,000,000		$	50,000,000
Original Issuance Discount — ASD		(1,500,000	)		(2,294,118	)
Contingent Interest		2,015,000			500,000
A&R Credit Agreement		25,000,000			—
Termination Fee — A&R		6,784,626			—
Termination Fee Debt Discount – A&R		(4,795,708	)		—
PIK Interest fee		375,000			—
PIK Interest — A&R		1,439,349			—
Other loans — vehicles		23,579			39,791

Total debt	$	79,341846		$	48,245,673

NOTE 6 — DERIVATIVE AND HEDGING FINANCIAL INSTRUMENTS

As a part of the ASD Credit Agreement, we entered into a warrant agreement with Chambers which required American Shale to sell the Lenders for a total of $2 million a warrant for 19,500 shares representing 19.5% of American Shale’s stock at $263.44 per share. The warrant expires on February 28, 2015. The warrant includes a put option whereby the Lenders can require American Shale to repurchase the warrant as of February 28, 2015, or earlier if certain events occur . Under the put option, American Shale would pay the excess of the fair value per share of the stock over $263.44 times the number of shares exercisable less any distributions or similar payments defined by the agreement. In certain circumstances, American Shale has the option to transfer working interest in all of its wells equal to the value of the put option instead of paying in cash. 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 May 9, 2013 our subsidiary, American Shale , entered into costless collars covering approximately 85% of its expected natural gas production from wells that were considered proved developed producing (“PDP”) as of that date. Neither oil nor natural gas liquids have been hedged, but the BTU associated with our ethane production was essentially hedged, since it is sold as part of the natural gas stream. The costless collars consist of long put options (floor) with a strike price of $4.00 per MMBtu and offsetting short calls (ceiling) with a strike price of $4.28 per MMBtu. The aforementioned volumes are hedged beginning with the June 2013 contract and ending with the April 2015 contract. A total of 3.4 MMBtu are hedged over this period, with monthly volumes declining from a high of approximately 207,000 MMBtu in June 2013 to 113,000 MMBtu in April 2015. The fair value of these commodity contracts was $522,733 at September 30, 2013.

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.

F-11

The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of September 30, 2013:


Gas Collars
Contract Period	Volumes		Weighted- Average Floor Price		Weighted- Average Ceiling Price
	(MMBtu)		(per MMBtu)		(per MMBtu)

Remainder of 2013		504,061	$	4.00	$	4.28

2014		1,650,248	$	4.00	$	4.28

2015		464,825	$	4.00	$	4.28


All gas collars*		2,619,134

*	Gas collars are comprised of IF Henry Hub (100%).

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


	As of September 30, 2013
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Commodity derivative	Current assets	$	464,874	Current liabilities	$	—
Commodity derivative	Noncurrent assets		57,859	Noncurrent liabilities		—

Warrant derivative liability			—	Noncurrent liabilities		2,213,033

		$	522,733		$	2,213,033


	As of December 31, 2012
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Commodity derivative	Current assets	$	—	Current liabilities	$	—
Commodity derivative	Noncurrent assets		—	Noncurrent liabilities		—

Warrant derivative liability			—	Noncurrent liabilities		2,808,278

		$	—		$	2,808,273

F-12

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, 2013 and 2012.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013		2012
Realized gains on commodity derivative	$	237,419		$	—		$	237,419	$	639
Change in fair value of commodity derivative		(136,623	)		—			522,733		—
Change in fair value of warrant derivative liability		3,806			(63,023	)		595,245		780,317

Total realized and unrealized gains recorded	$	104,602		$	(63,023	)	$	1,355,397	$	780,956

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

NOTE 7 — FAIR VALUE MEASUREMENTS

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

Level 1:

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

Level 2:

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

Level 3:

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

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The valuation policies are determined by the Chief Financial Officer and are approved by the President. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, an outside consulting firm updates the inputs used in the fair value calculations 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, 2013 and December 31, 2012 by level within the fair value hierarchy


	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
September 30, 2013

ASSETS:
Commodity contracts		—	$	522,733		—	$	522,733
LIABILITIES:
Warrant derivative liability		—		—		2,213,033		2,213,033

December 31, 2012

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

F-13

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 6 — Derivative and Hedging Financial Instruments). The fair value of the commodity derivative assets and liabilities are 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 September 30, 2013, the Company’s warrant derivative financial instrument issued as a part of the ASD Credit Agreement is comprised of the warrants issued by the Company to purchase 19,500 shares of American Shale common stock with a put option (See Note 6 — Derivative and Hedging Financial Instruments). The warrants are valued by third parties using a binomial lattice-based valuation model and are classified as Level 3 in the fair value hierarchy. The lattice-based valuation technique is utilized because it embodies all of the requisite assumptions (including the underlying price, exercise price, term, volatility, and risk-free interest-rate) that are necessary to measure the fair value of these instruments. The valuation policies are determined by the Chief Financial Officer and approved by the President. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, the Chief Financial Officer reviews the updated inputs used in the fair value calculations and internally reviews the changes from period to period for reasonableness. The Company uses data from its peers as well as from external sources in the determination of the volatility and risk free interest rates used in the fair value calculations. A sensitivity analysis is performed as well to determine the impact of the inputs on the ending fair value estimate. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument due to both internal and external market factors. In addition, option-based techniques are highly sensitive to volatility assumptions. An increase in the volatility would cause an increase in the fair value of the warrants. Likewise, a decrease in the volatility would cause a decrease in the value of the Warrants.

The significant assumptions used in the valuation of the warrant derivative liability as of September 30, 2013 Based on the Company’s stock are as follows:


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

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


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012

Balance as of beginning of period	$	(2,216,839	)	$	(1,156,660	)	$	(2,808,278	)	$	—
Total unrealized gains (losses)
Included in earnings		3,806			(63,023	)		595,245			780,317
Issuances		—			—			—			(2,000,000	)
Settlements		—			—			—			—
Transfers in and out of Level 3		—			—			—			—

Balance as of September 30	$	(2,213,033	)	$	(1,219,683	)	$	(2,213,033	)	$	(1,219,683	)

Change in unrealized gains included in earnings Relating to instruments still held as of September 30,	$	(3,806	)	$	63,023		$	(595,245	)	$	(780,317	)

F-14

NOTE 8 — STOCKHOLDERS’ EQUITY

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

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

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

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 2013 was determined using the following assumptions:


Expected volatility		70% - 89%
Risk free interest rate		0.80% - 1.72%
Expected term (years)		5
Dividend yield		0%

As a result of the above stock and option transactions, we recorded total stock-based compensation of $283,892, $919,755, $517,370 and $1,533,855 for the three and nine months ended September 30, 2013 and 2012, respectively.

Stock option activity is as follows:


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

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

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

Granted		446,000		$	2.61
Exercised		(5,000	)	$	2.75
Forfeited		—			—
Expired		—			—

Outstanding September 30, 2013		4,081,324		$	1.85	2.31 Years	$	7,550,449

Exercisable at September 30, 2013		3,226,658		$	1.70		$	5,485,319
Available for grant at September 30, 2013		854,666

F-15

NOTE 9 — EARNINGS PER SHARE

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income (loss) per share of common stock includes both vested and unvested shares of restricted stock. Diluted net income (loss) per common share of stock is computed by dividing net income by the diluted weighted-average common shares outstanding. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had losses for the three and nine-month periods ended September 30, 2013 and 2012, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of September 30, 2013, potentially dilutive securities included (i) 134,000 unvested shares of restricted common stock and (ii) 3,101,000 in-the-money outstanding options.

NOTE 10 — SALE OF ASSETS

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

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

The assets and liabilities related to the wells and equipment sold were reported as assets and liabilities held for sale at December 31, 2012. We wrote the assets down to their fair value less costs to sell as of December 31, 2012 based on the sale proceeds and recorded an impairment on the assets of $10,132,702. A loss on sale of assets of $8,787 reported in 2013 is due to actual sale expenses being greater than the expenses accrued as of December 31, 2012.

NOTE 11 — BUSINESS SEGMENTS

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

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


	For the Three Months Ended September 30	Exploration and Production		Pipeline Transmission			Corporate			Total

Revenue	2013	$	4,343,739	$	35,203		$	25,801		$	4,404,743
	2012		783,045		98,288			2,363			883,696
Income (Loss) from operations	2013		862,737		(10,376	)		(1,855,586	)		(1,003,225	)
	2012		60,758		52,174			(2,021,728	)		(1,908,796	)
Interest expense	2013		5,200,033		—			595			5,200,628
	2012		1,659,934		—			—			1,659,934
Depreciation, depletion, amortization and accretion	2013		986,393		277			—			986,670
	2012		550,679		80			—			550,759
Property and equipment acquisitions, including oil and gas properties	2013		12,242,765		10,000			—			12,252,765
	2012		2,634,201		—			—			2,634,201

F-16


	For the Nine Months Ended September 30	Exploration and Production		Pipeline Transmission		Corporate			Total

Revenue	2013	$	12,559,344	$	97,093	$	28,790		$	12,685,227
	2012		5,692,389		285,976		57,561			6,035,926
Income (Loss) from operations	2013		2,900,923		21,153		(4,701,132	)		(1,779,056	)
	2012		66,835		159,047		(4,487,841	)		(4,261,959	)
Interest expense	2013		10,995,490		—		6,512			11,002,002
	2012		3,530,819		—		—			3,530,819
Depreciation, depletion, amortization and accretion	2013		2,364,950		330		—			2,365,280
	2012		2,303,566		241		—			2,303,807
Property and equipment acquisitions, including oil and gas properties	2013		24,942,086		10,000		—			24,952,086
	2012		16,974,319		—		—			16,974,319
Total assets, net of intercompany accounts:
September 30, 2013			83,050,718		15,705					83,066,423
December 31, 2012			62,408,692		29,769					62,438,461

Property and equipment acquisitions include accrued amounts and reclassifications.

F-17

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

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

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

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

Results of Operations

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

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, 2013 and 2012.


	Three months ended September 30,
	2013			2012
Total revenues	$	4,404,743		$	883.696
Total costs and expenses		(5,414,855	)		(2,836,328	)
Gain on sale of assets		6,887			43,836

Loss from operations		(1,003,225	)		(1,908,796	)
Other expenses, net		(5,092,563	)		(1,718,989	)
Income tax benefit		—			58,013

Net loss	$	(6,095,788	)	$	(3,569,772	)

The following table is a summary of revenues, volumes, and pricing for the three months ended September 30, 2013 and 2012.

Three Months Ended September 30, 2013 compared to the Three Months Ended September 30, 2012


	Three Months Ended
	September 30,					Increase/
	2013		2012			(Decrease)
Natural gas sales	$	3,541,101	$	630,733		$	2,910,368		461.4	%
Oil sales	$	17,277	$	270,712		$	(253,435	)	-93.6	%
Natural gas liquid sales	$	785,361	$	(118,400	)	$	903,761		-763.3	%

Total Oil & Gas Sales	$	4,343,739	$	783,045		$	3,560,694		454.7	%
Transportation and other revenue	$	61,004	$	100,651		$	(39,647	)	-39.4	%
Net Production
Natural gas sales (MCF)		958,706		404,080			554,626		137.3	%
Oil sales ((Bbls)		193		3,957			(3,764	)	-95.1	%
Natural gas liquids (gallons)		1,061,830		559,013			502,817		89.9	%
Natural Gas Equivalent ( MCFe)		1,111,554		507,681			603,873		118.9	%
Average Sales Price per Unit
Natural Gas (MCF)	$	3.69	$	1.56		$	2.13		136.5	%
Oil(Bbl)	$	89.52	$	68.41		$	21.11		30.9	%
Natural gas liquids (gallons)	$	0 .74	$	(0.21	)	$	0.95		-452.4	%
Natural Gas Equivalent (MCFe)	$	3.91	$	1.54		$	2.37		153.9	%

Expenses

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


	Three Months Ended September 30,
	2013		2012
Costs and Expenses Per MCFE of Production:
Production Expenses	$	2.39	$	1.35
Production Taxes		0.12		0.29
G&A Expenses (Excluding Share-Based Compensation)		1.21		1.85
Non-Cash Shared-Based Compensation		0.26		1.02
Depletion of Oil and Natural Gas Properties		0.87		0.96
Impairment of Oil and Natural Gas Properties		—		—
Depreciation and Amortization		0.02		0.12
Accretion of Discount on Asset Retirement Obligation		—		0.01

Total revenues increased primarily due to an increase in natural gas and natural gas liquid (NGL) production volumes as well as an increase in natural gas prices. The increase in natural gas and NGL volumes was the result of our 2012 drilling. For the three months ended September 30, 2013 and 2012, respectively, we had 22 gross wells and 9.13 net wells compared to 17 gross wells and 6.92 net wells for the same period. This increase in revenue was offset by a decrease in oil production volumes due to the sale of our shallow wells in January 2013. Our pipeline transmission and corporate revenue decreased from $100,651 to $61,004 primarily due to the sale of most of our transmission lines with the sale of our shallow wells in January 2013.

Production costs increased $1,965,817 for the three months ended September 30, 2013 as compared to the same period for 2012, primarily due to an increase in natural gas liquid transportation and processing fees associated with the increased production in 2013, higher ad valorem taxes, and higher water disposal costs.

Depreciation, depletion, amortization and accretion expense increase by $435,911 or 79% the three months ended September 30, 2013 compared to the same period for 2012, primarily due to the increased production volumes.

Selling, general and administrative expense increased $179,799 or 12% for the three months ended September 30, 2013 as compared to the same period for 2012, primarily due to an increase in legal and professional fees.

Interest expense increased $3,540,694 or 213% for the three months ended September 30, 2013 as compared to the same period for 2012 due to a higher loan balance and the termination fee on A&R Credit Agreement. Stated interest rate was 11% for both periods. For the three months ended September 30, 2013 the average loan balance was $77,006,006 compared to $50,046,124 for the same period in 2012. Interest expense of $1,988,918 was incurred related to the 2013 Termination Fee Liability for this period.

Gain on warrant derivative for the three months ended September 30, 2013 was $3,806 as compared to a loss of $63,023 for the same period last year. This represents the change in value of the put option associated with our warrant derivative liability.

Gain on derivative assets for the three months ended September 30, 2013 was $100,796. This represents the increase in the fair value of our gas hedges.

Net loss for the three months ended September 30, 2013 was $6,095,788 compared to a net loss of $3,569,772 for the same period of 2012. This increase in net loss is due primarily to the increase in interest expense which was offset partially by a decrease in loss from operations as discussed above.

Nine months ended September 30, 2013 compared to September 30, 2012

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


	Nine months ended September 30,
	2013			2012
Total revenues	$	12,685,227		$	6,035,926
Total costs and expenses		(14,462,383	)		(10,410,783	)
(Loss) gain on sale of assets		(1,900	)		112,898

Loss from operations		(1,779,056	)		(4,261,959	)
Other expenses, net		(9,628,463	)		(2,732,716	)
Income tax benefit		—			58,013

Net (loss) income	$	(11,407,519	)	$	(6,936,662	)

The following table is a summary of revenues, volumes, and pricing for the nine months ended September 30, 2013 and 2012.

Nine Months Ended September 30, 2013 compared to the Nine Months Ended September 30, 2012


	Nine Months Ended
	September 30,				Increase/
	2013		2012		(Decrease)
Natural gas sales	$	10,142,664	$	3,459,127	$	6,683,537		193.2	%
Oil sales	$	125,180	$	836,865	$	(711,685	)	-85.0	%
Natural gas liquid sales	$	2,291,500	$	1,396,397	$	895,103		64.1	%

Total Oil & Gas Sales	$	12,559,344	$	5,692,389	$	6,866,955		120.6	%
Transportation and other revenue	$	125,883	$	343,537	$	(217,654	)	-63.4	%
Net Production
Natural gas sales (MCF)		2,499,111		1,112,174		1,386,937		124.7	%
Oil sales ((Bbls)		1,451		8,931		(7,480	)	-83,8	%
Natural gas liquids (gallons)		3,143,936		1,643,585		1,500,351		91,3	%
Natural Gas Equivalent (MCFe)		2,956,951		1,400,558		1,556,393		111.1	%
Average Sales Price per Unit
Natural Gas (MCF)	$	4.06	$	3.11	$	0.95		30.5	%
Oil(Bbl)	$	86.27	$	93.70	$	(7.43	)	-7.9	%
Natural gas liquids (gallons)	$	0 .73	$	0.85	$	(0.12	)	-14.1	%
Natural Gas Equivalent (MCFe)	$	4.25	$	4.06	$	0.19		4.7	%

Expenses

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


	Nine Months Ended September 30,
	2013		2012
Costs and Expenses Per MCFE of Production :
Production Expenses	$	0.57	$	2.23
Production Taxes		0.37		0.31
G & A Expenses (Excluding Share-Based Compensation)		1.29		2.15
Non-Cash Shared-Based Compensation		0.31		1.10
Depletion of Oil and Natural Gas Properties		0.78		1.50
Impairment of Oil and Natural Gas Properties		—		—
Depreciation and Amortization		0.02		0.13
Accretion of Discount on Asset Retirement Obligation		—		0.01

Total revenues increased due to an increase in natural gas and natural gas liquid (NGL) production volumes as well as an increase in natural gas prices. The increase in natural gas and NGL volumes was the result of our 2012 drilling. For the nine months ended September 30, 2013 and 2012, respectively, we had 22 gross wells and 9.13 net wells compared to 17 gross wells and 6.92 net wells for the same period. This increase in revenue was offset by a decrease in NGL prices and oil production volumes due to the sale of our shallow wells in January 2013. Our pipeline transmission and corporate revenue decreased from $343,537 to $125,833 primarily due to the sale of most of our transmission lines with our shallow wells in January 2013.

Production costs increased $3,804,890 for the nine months ended September 30, 2013 as compared to the same period for 2012, primarily due to an increase in transportation fees and natural gas liquid processing fees and production taxes, associated with the increased production in 2013.

Depreciation, depletion, amortization and accretion expense remained fairly consistent for the nine months ending September 30, 2013 compared to the same period for 2012, primarily due to the selling of the shallow assets in January 2013, which offset the higher depletion on producing wells.

Selling, general and administrative expense increased $185,237 or 4% for the nine months ended September 30, 2013 as compared to the same period for 2012, primarily due to higher legal and professional fees and , investor relation costs which was offset by the $400,000 of share-based compensation related to 2012 employee separation agreements.

Interest expense increased $7,471,183 or 212% for the nine months ended September 30, 2013 as compared to the same period for 2012 due to higher loan balance and the termination fee on A& R Credit Agreement. The average loan balance for the nine months ended September 30, 2013 was $70,942,773 compared to $35,160,850 for the same period in 2012. Stated interest rate was 11% for both periods. Interest expense of $1,988,918 was incurred related to the 2013 Termination Fee Liability for this period.

Gain on warrant derivative for the nine months ended September 30, 2013 was $595,245 as compared to $780,956 for the same period last year. This represents the change in value of the put option associated with our warrant derivative liability.

Gain on derivative assets for the nine months ended September 30, 2013 was $760,152. This represents the increase in the fair value of our gas hedges.

Net loss for the nine months ended September 30, 2013 was $11,407,519 compared to a net loss of $6,936,662 for the same period of 2012. This increase in the net loss is due primarily to the increase in interest expense which was offset partially by a decrease in loss from operations as discussed above.

Liquidity and Capital Resources

Historically, we have satisfied our working capital needs with borrowed funds and the proceeds of acreage sales. At September 30, 2013, we had positive working capital of $2,854,116 compared to positive working capital of $2,487,924 at December 31, 2012. This increase in working capital is due to the increased value of our gas hedges.

During the first nine months of 2013, net cash used by operating activities was $3,657,984 compared to $16,699,080 of net cash used for the same period of 2012. This increase in cash flow from operations was due to a decrease in the amount paid on our accounts payable and accounts receivable due from operator change the first nine months of 2013.

We expect our cash flow from operations for 2013, compared to the comparable period in 2012, to improve because of higher projected production from the drilling program due to 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 2013, net cash used by investing activities was $21,213,299 compared to net cash used of $17,887,524 in the same period in 2012. The change was due to higher capital expenditures in 2013 which was offset by increased proceeds from the sale of assets in 2013.

During the first nine months of 2013, net cash provided by financing activities was $24,875,308 compared to net cash provided of $32,713,138 for the same period in 2012. This decrease was due to lower proceeds from borrowing in 2013 which was offset by higher loan payments in 2012.

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

Critical accounting policies

We consider accounting policies related to our estimates of proved reserves, accounting for derivatives, share-based payments, accounting for oil and natural gas properties, asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2012.

Forward-looking and Cautionary Statements

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:

•

varying demand for oil and gas;

•

fluctuations in price;

•

competitive factors that affect pricing;

•

attempts to expand into new markets;

•

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

•

hiring and retention of key personnel;

•

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

•

new government legislation or regulation.

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

Item 4. Controls and Procedures

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

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

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

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

PART II

Item 1. Legal Proceedings

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

On May 11, 2011, we filed an action in the U.S. District Court for the Northern District of West Virginia against EQT Corporation, a Pennsylvania corporation (Trans Energy, Inc., et al. v. EQT Corporation). The action relates to our attempt to quiet title to certain oil and gas properties referred to as the Blackshere Lease, consisting of approximately 22 oil and/or gas wells on the Blackshere Lease. The defendant, EQT Corporation, has filed with the Court an answer and counterclaim wherein it claims it holds title to the natural gas within and underlying the Blackshere Lease. We believe that we will ultimately prevail in the action, but it is too early in the proceedings to accurately assess the final outcome. Currently we have no plans to drill on this acreage. On September 5, 2012, the parties filed competing motions seeking summary judgment in this case. On November 26, 2012, the Court granted our motion for summary judgment and denied the defendant’s motions for declaratory judgment and summary judgment. At this time, the defendant has appealed the Court’s decision. The Court is scheduled to announce a decision regarding the defendant’s appeal on December 14, 2013.

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

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

On October 7, 2013 we entered into a settlement agreement with Oppenheimer & Co. Inc. (“Opco”) relating to certain fees that pertain to the ASD credit agreement. Oppenheimer had previously filed an action entitled Oppenheimer & Co. Inc. v. Trans Energy, Inc. and American Shale Development, Inc. 12-cv-4726 (KPF) against us and American Shale in the United States District Court for the Southern District of New York. We have agreed to pay Opco $300,000 in the form of a cash settlement and to issue 37,500 share of common stock which will be transferred in accordance with the settlement agreement. At September 30, 2013, we have reported this liability as a deferred financing costs and an accrued expense in the condensed consolidated balance sheet.

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

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

Not Applicable

Item 3. Defaults Upon Senior Securities

Not Applicable

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

None.

Item 6. Exhibits


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

Exhibit 31.2		Certification of Chief 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 Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 99.1		Purchase and Sale Agreement dated September 30, 2013

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase

**101.DEF		XBRL Taxonomy Extension Definition Linkbase

**101.LAB		XBRL Taxonomy Extension Label Linkbase

**101.PRE		XBRL Taxonomy Extension Presentation Linkbase

Filed herewith. XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed and note filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

SIGNATURES

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.


	TRANS ENERGY, INC.

Date: November 14, 2013	By	/s/ JOHN G. CORP
		JOHN G. CORP
		Principal Executive Officer

Date: November 14, 2013	By	/s/ JOHN S. TUMIS
		JOHN S. TUMIS
		Chief Financial Officer