Edgar Filing: TRANS ENERGY INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if smaller reporting company)

Smaller reporting company

Form 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 March 31, 2014

¨	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 June 12, 2014
Common Stock, $0.001 par value		13,619,309

Table of Contents


Heading	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

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

Condensed Consolidated Statements of Operations — Three Months Ended March 31, 2014 and 2013		F-3

Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 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		4

PART II OTHER INFORMATION

Item 1. Legal Proceedings		5

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		6

Item 3. Defaults Upon Senior Securities		6

Item 4. Mine Safety Disclosures		6

Item 5. Other Information		6

Item 6. Exhibits		6

Signatures		7

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

Unaudited


	March 31, 2014			December 31, 2013
	Unaudited			Audited
ASSETS
CURRENT ASSETS
Cash	$	1,846,903		$	2,727,832
Accounts receivable, trade		7,663,815			4,460,535
Accounts receivable, related parties		18,500			18,500
Advance royalties		12,032			16,937
Prepaid expenses		1,068,386			1,065,061
Deferred financing costs, net of amortization of $1,513,302 and $1,308,817, respectively		752,529			817,938

Total current assets		11,362,165			9,106,803
OIL AND GAS PROPERTIES, USING SUCCESSFUL EFFORTS ACCOUNTING
Proved properties		81,059,386			77,961,183
Unproved properties		16,092,722			15,092,783
Pipelines		1,397,440			1,397,440
Accumulated depreciation, depletion and amortization		(16,563,032	)		(14,473,069	)

Oil and gas properties, net		81,986,516			79,978,337
PROPERTY AND EQUIPMENT, net of accumulated depreciation of $339,466 and $317,704, respectively		565,455			587,218
OTHER ASSETS
Deferred financing costs		—			139,076
Other assets		304,376			303,887

Total other assets		304,376			442,963

TOTAL ASSETS	$	94,218,512		$	90,115,321

See notes to unaudited condensed consolidated financial statements.

F-1

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (continued)

Unaudited


	March 31, 2014			December 31, 2013
	Unaudited			Audited
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable, trade	$	379,074		$	632,795
Accounts payable due to drilling operator		6,584,668			2,698,302
Accounts payable, related party		1,500			1,500
Accrued expenses		5,099,185			5,302,816
Revenue payable		164,570			127,106
Commodity derivative liability		431,423			58,176
Notes payable — current		15,063			14,897
Notes payable, related party		—			205,314

Total current liabilities		12,675,483			9,040,906
LONG-TERM LIABILITIES
Notes payable, net		90,833,888			89,204,102
Asset retirement obligations		53,812			41,440
Commodity derivative liability		—			67,597

Total long-term liabilities		90,887,700			89,313,139

Total liabilities		103,563,183			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; 13,621,309 and 13,457,978 shares issued, respectively, and 13,619,309 and 13,455,978 shares outstanding, respectively		13,621			13,458
Additional paid-in capital		42,978,416			42,556,292
Treasury stock, at cost, 2,000 shares		(1,950	)		(1,950	)
Accumulated deficit		(52,334,758	)		(50,806,524	)

Total stockholders’ equity (deficit)		(9,344,671	)		(8,238,724	)

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	94,218,512		$	90,115,321

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 March 31,
	2014			2013
OPERATING REVENUES
Oil and gas sales	$	9,716,422		$	3,573,883
Gas transportation, gathering, and processing		54,789			35,443
Other income		5,131			—

Total operating revenues		9,776,342			3,609,326
OPERATING COSTS AND EXPENSES
Production costs		3,255,950			2,319,640
Depreciation, depletion, amortization and accretion		2,111,726			639,449
Selling, general and administrative		1,447,819			1,560,338

Total operating costs and expenses		6,815,495			4,519,427
Gain (loss) on sale of assets		207,396			(8,787	)

INCOME (LOSS) FROM OPERATIONS		3,168,243			(918,888	)
OTHER INCOME (EXPENSES)
Interest income		908			4,821
Interest expense		(4,131,193	)		(1,902,746	)
Gain on warrant derivatives		—			124,316
Loss on commodity derivative		(566,192	)		(639	)

Total other income (expenses)		(4,696,477	)		(1,774,248	)

NET LOSS BEFORE INCOME TAXES		(1,528,234	)		(2,693,136	)
INCOME TAX		—			—

NET LOSS	$	(1,528,234	)	$	(2,693,136	)

NET LOSS PER SHARE — BASIC AND DILUTED	$	(.11	)	$	(.20	)

WEIGHTED AVERAGE SHARES — BASIC AND DILUTED		13,516,199			13,236,228

See notes to unaudited condensed consolidated financial statements.

F-3

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	For the Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,528,234	)	$	(2,693,136	)
Adjustments to reconcile net loss to net cash used by operating activities:
Depreciation, depletion, amortization and accretion		2,111,726			639,449
Amortization of financing costs and debt discount		1,305,651			427,604
Share-based compensation		198,541			310,062
(Gain) loss on sale of assets		(207,396	)		8,787
Interest and legal expense added to principal		534,571			—
Unrealized gain on warrant derivative		—			(124,316	)
Unrealized loss on commodity derivative assets		305,650			—
Realized loss on commodity derivative assets		260,542			639
Changes in operating assets and liabilities:
Accounts receivable, trade		(3,203,280	)		851,418
Accounts receivable due from operator, net		269,558			—
Prepaid expenses and other current assets		1,580			(420,182	)
Other assets		(489	)		(481	)
Accounts payable and accrued expenses		747,804			(183,663	)
Revenue payable		37,464			59,943

Net cash provided (used) by operating activities		833,688			(1,123,876	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets		259,543			2,618,025
Expenditures for oil and gas properties		(1,986,807	)		(1,377,891	)
Expenditures for property and equipment		—			(5,251	)

Net cash (used) provided by investing activities		(1,727,264	)		1,234,883
CASH FLOWS FROM FINANCING ACTIVITIES:
Financing costs paid		—			(110,365	)
Payments on notes payable		(211,099	)		(5,571	)
Proceeds from notes payable		—			25,000,000
Stock options exercised		223,746			—

Net cash provided by financing activities		12,647			24,884,064

NET CHANGE IN CASH		(880,929	)		24,995,071

CASH, BEGINNING OF PERIOD		2,727,832			1,009,084

CASH, END OF PERIOD	$	1,846,903		$	26,004,155

SUPPLEMENTAL DISCLOSURES FOR CASH FLOW INFORMATION:
CASH PAID FOR:
Interest	$	2,409,018		$	1,638,040
Income taxes		—			—
Non-cash investing and financing activities:
Accrued expenditures for oil and gas properties	$	3,509,412		$	1,211,010
Increase in asset retirement obligation	$	12,372		$	27,000

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, 2013 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

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 2013 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 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.

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 (“Tranche A”) with Chambers Energy Capital (“Chambers”). We recorded $401,625 in financing fees related to the settlement. The Opco financing fees are being amortized over the same 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 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 March 31, 2014 and 2013 were $204,484 and $162,901, 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. Additions are capitalized and maintenance and repairs are charged to expense as incurred.

Oil and Gas Properties

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

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

On the sale or retirement of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually.

If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Impairments

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

No impairments were recorded through March 31, 2014 or 2013.

Derivatives

We may enter into derivative commodity contracts at times to manage or reduce commodity price risk related to our production. Derivatives and embedded derivatives, if applicable, are measured at fair value and recognized in the consolidated balance sheets as assets or liabilities. Derivatives are classified in the consolidated balance sheets as current or non-current based on whether net-cash settlement is expected to be required within 12 months of the balance sheet date. These commodity contracts are not designated as cash flow hedges, so changes in the fair value are recognized immediately in other income (expense) in the consolidated statement of operations. The pricing models used for valuation often incorporate significant estimates and assumptions, which may impact the level of precision in the financial statements.

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

F-6

Notes Payable

We record notes payable at fair value and recognize interest expense for accrued interest payable under the terms of the agreements. Principal and interest payments due within one year are classified as current, whereas principal and interest payments for periods beyond one year are classified as long term.

Asset Retirement Obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. These obligations include dismantlement, plugging and abandonment of oil and gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset which has been determined to be 40 years for Marcellus Shale wells.

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


	2014		2013
Asset retirement obligations at beginning of period	$	41,440	$	416,322
Liabilities incurred during the period		11,372		—
Accretion expense		1,000		920
Liabilities held for sale		—		(388,005	)

Asset retirement obligations at end of period	$	53,812	$	29,237

At March 31, 2014 and December 31, 2013, 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 $388,005 at December 31, 2012.

Income Taxes

At March 31, 2014, the Company had net operating loss carry forwards (“NOLs”) for future years of approximately $54.0 million. These NOLs will expire at various dates through 2033. There is no current tax provision for the three months ended March 31, 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 March 31, 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 2009 remain open to examination by U.S. federal and state tax jurisdictions, however prior year net operating losses remain open for examination.

Revenue and Cost Recognition

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

F-7

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 07 - Derivative and Hedging Financial Instruments 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 $198,541 and $310,062 for the three months ended March 31, 2014 and 2013, respectively.

New Accounting Standards

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.

Reclassification

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

NOTE 2 — OPERATIONS

We have incurred net losses for the three months ended March 31, 2014 and 2013 of $(1,528,234) and $(2,693,136), 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 three months ended March 31, 2014 and 2013 were primarily funded using net proceeds from notes payable to Chambers (see Note 6), in addition to proceeds from the sale of certain oil and gas properties (see Note 5).

NOTE 3 —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 $6,584,668 and $2,698,302 for charges incurred, but not paid, as of March 31, 2014 and December 31, 2013, respectively. The amount due to the operator reported at March 31, 2014 and December 31, 2013, is net of a $837,443 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.

NOTE 4 — OIL AND GAS PROPERTIES

Total additions for oil and gas properties for the three months ended March 31, 2014 and 2013 were $1,986,807 and $1,377,891, respectively. Depreciation, depletion, and amortization expenses on oil and gas properties were $2,089,607 and $616,314 for the three months ended March 31, 2014 and 2013, respectively.

F-8

NOTE 5 – SALE OF OIL AND GAS PROPERTIES

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

On December 13, 2013, the Company and our JV Partner, Republic Energy Ventures, LLC (“Republic”), closed a transaction pursuant to a Purchase and Sale Agreement (the “PSA”) dated September 30, 2013. The Company owned 1,114.8 lease acres of the total 4,650 lease acres and leasehold working interests in certain partially completed well sites, located in Tyler County, West Virginia. At closing, the Company received cash of approximately $10.6 million 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 at March 31, 2014.

NOTE 6 — 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. 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.

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

On April 26, 2012, our newly created, wholly owned subsidiary, American Shale , closed a Credit Agreement transaction (hereafter the “ASD Credit Agreement”) with several banks and other financial institutions or entities that from time-to-time will be parties to the ASD Credit Agreement (the “Lenders”), and Chambers Energy Management, LP as the administrative agent (“Agent” or “Chambers”).

The ASD Credit Agreement provided that the Lenders will lend American Shale up to $50 million, which funds would be used to develop wells and properties that we transferred to American Shale. In order to accommodate the terms of the ASD Credit Agreement Trans Energy transferred certain assets and properties to American Shale. Trans Energy and Prima are not direct parties to the ASD Credit Agreement, but are guarantors of loans to be made there under. We received a portion of the loan proceeds to repay CIT and certain other outstanding debts. The assets and properties transferred are referred to herein as the “Marcellus Properties,” which at the time of the transfer consisted of working interests in 13 gross (7.60 net) producing Marcellus shale liquids-rich gas wells and approximately 22,000 net acres of Marcellus shale leasehold rights, located in Northwestern West Virginia in the counties of Wetzel, Marshall, Marion, Tyler, and Doddridge.

The ASD Credit Agreement was originally for a notional amount of $50 million, which was received at closing net of a $3 million Original Issue Discount (“OID”) and a $50,000 administrative fee. These OID costs are netted against notes payable and are being amortized over the life of the loan using the straight-line method, which approximates the effective interest method. For the three months ended March 31, 2014 and 2013, $264,706 and $264,706 of the OID was amortized as interest expense, respectively. The administrative fee is due annually.

F-9

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

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

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

The Termination Fee Liability is recorded on the Company’s 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 prior to such date.

During the three months ended March 31, 2014, the Company recorded interest expense of $836,459 related to the amortization of the Termination Fee Debt Discount. During the year ended December 31, 2013, the Company recorded interest expense of approximately $2.8 million related to the cumulative amortization of the Termination Fee Debt Discount.

The A&R Credit Agreement is collateralized by American Shale’s oil and natural gas reserves and the guarantees discussed earlier. The A&R Credit Agreement includes reporting, financial and other restrictive covenants, as well as a contingent interest provision that adds 1% of the outstanding principal amount of the loan to the loan balance for any quarter in which American Shale’s Consolidated Leverage 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 $532,388 and $2,030,050 was added to the principal balance and interest expense in 2014 and 2013, respectively. A contingent interest amount of $617,581 is included in accrued expenses in anticipation of exceeding the March 31, 2014 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, September and October 2013 interest of $2,186,038 has been added to the principal balance of the loan.

On December 20, 3013, American Shale amended the A&R Credit Agreement to increase the principal amount of the borrowings by $7.5 million to pay a portion of the cost to purchase an outstanding warrant held by Chambers (See Note 7). There were no other changes to the terms of the loan. The additional funds were received December 20, 2013.

On May 21, 2014 (“Funding Date”), American Shale entered into a credit agreement (hereafter the “Credit Agreement”) by and among American Shale, several banks and other financial institutions or entities that from time-to-time will be parties to the Credit Agreement (the “Lenders”), and Morgan Stanley Capital Group Inc. as the administrative agent (“Agent ”). Trans Energy is a guarantor of the Credit Agreement as is Prima, another of our wholly owned subsidiaries. The Credit Agreement provides that the Lenders will lend American Shale up to $200 million, including an initial draw of $102.5 million, a contingent committed amount of $47.5 million and an uncommitted amount of $50 million (the “Loans”). The initial draw under the facility was used primarily to repay all of the outstanding debt under the A&R Credit Agreement, as well as to fund certain fees and expenses incurred in connection with the Credit Agreement. All principal will be due on December 31, 2018 (the “Maturity Date”), if not accelerated before that date (See Note 13, Subsequent Events)

F-10

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


	March 31,			December 31,
	2014			2013
	(unaudited)			(audited)
ASD Credit Agreement	$	50,000,000		$	50,000,000
Unamortized Original Issuance Discount - ASD		(970,588	)		(1,235,294	)
PIK Contingent Interest Expense		3,062,438			2,530,050
A&R Credit Agreement-February 2013		25,000,000			25,000,000
Termination Fee – A&R		6,784,626			6,784,626
Termination Fee Debt Discount – A&R		(3,104,200	)		(3,940,659	)
PIK Interest Fee-ASD		375,000			375,000
PIK Interest – A&R		2,186,038			2,186,037
A&R Credit Agreement -December 2013		7,500,000			7,500,000
Other loans - related party		—			205,314
Other loans - vehicles		15,637			19,239

Total debt	$	90,848,951		$	89,424,313

NOTE 7 — DERIVATIVE AND HEDGING FINANCIAL INSTRUMENTS

On May 9, 2013 our subsidiary, American Shale, entered into costless collars covering approximately 85% of its expected natural gas production from wells that were considered proved developed producing (“PDP”) as of that date. Neither oil nor natural gas liquids have been hedged, but the BTU associated with our ethane production was essentially hedged, since it is sold as part of the natural gas stream. The costless collars consist of long put options (floor) with a strike price of $4.00 per MMBtu and offsetting short calls (ceiling) with a strike price of $4.28 per MMBtu. The aforementioned volumes are hedged beginning with the June 2013 contract and ending with the April 2015 contract. A total of 3.4 MMBtu are hedged over this period, with monthly volumes declining from a high of approximately 207,000 MMBtu in June 2013 to 113,000 MMBtu in April 2015. The fair value of these commodity contracts was $(431,423) and $(125,773) at March 31, 2014 and December 31, 2013, respectively.

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 as of March 31, 2014:

Gas Collars


Contract Period	Volumes		Weighted- Average Floor Price		Weighted- Average Ceiling Price
	(MMBtu)		(per MMBtu)		(per MMBtu)
2014		1,046,420	$	4.00	$	4.28
2015		464,825	$	4.00	$	4.28

All gas collars*		1,511,245

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

F-11

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

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


	As of March 31, 2014
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
Commodity derivative	Current assets	$	—	Current liabilities	$	431,423
Commodity derivative	Noncurrent assets		—	Noncurrent liabilities		—


		$			$	431,423


	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

The table below summarizes the realized and unrealized gains and losses related to our derivative instruments for the three months ended March 31, 2014 and 2013.


	Three Months Ended March 31,
	2014			2013
Realized gains (loss) on commodity derivative	$	(260,542	)	$	639
Change in fair value of commodity derivative		(305,650	)		—
Change in fair value of warrant derivative liability		—			(124,316	)

Total realized and unrealized gains recorded	$	(566,192	)	$	(123,677	)

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

F-12

NOTE 8 — FAIR VALUE MEASUREMENTS

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


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

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

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

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

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013 by level within the fair value hierarchy


	Level 1		Level 2		Level 3		Total
March 31, 2014
ASSETS:
Commodity contracts		—		—		—		—
LIABILITIES:
Commodity contracts		—	$	431,423		—	$	431,423

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

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.

F-13

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:


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:


	March 31, 2014		March 31, 2013
Balance as of beginning of period	$	—	$	(2,808,278	)
Total realized and unrealized gains (losses)
Included in earnings		—		123,677
Issuances		—		—
Settlements		—		—
Transfers in and out of Level 3		—		—

Balance as of March 31	$	—	$	(2,684,601	)

Change in unrealized gains included in earnings Relating to instruments still held as of March 31	$	—	$	123,677

NOTE 9 — STOCKHOLDERS’ EQUITY

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.

F-14

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 during the three months ended March 31, 2013 was determined using the following assumptions:


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

As a result of the above stock and option transactions, we recorded total stock-based compensation of $198,541 and $310,062 for the three months ended March 31, 2014 and 2013, 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, 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		—			—
Exercised		(163,331	)	$	1.37
Forfeited		—			—
Expired		—			—

Outstanding March 31, 2014		3,881,993		$	1.87		1.86 Years	$	7,259,326

Exercisable at March 31, 2014		3,728,329		$	1.84			$	6,860,125
Unvested at March 31, 2014		584,332

F-15

NOTE 10 — 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 month periods ended March 31, 2014 and 2013, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.

As of March 31 2014, potentially dilutive securities included (i) 62,000 unvested shares of restricted common stock and (ii) 3,881,993 in-the-money outstanding options.

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 March 31	Exploration and Production		Pipeline Transmission		Corporate			Total
Revenue	2014	$	9,716,422	$	54,789	$	5,131		$	9,776,342
	2013		3,573,883		35,443		—			3,609,326
Income (Loss) from operations	2014		4,554,604		56,327		(1,442,688	)		3,168,243
	2013		607,258		32,554		(1,558,700	)		(918,888	)
Interest expense	2014		4,127,501		—		3,692			4,131,193
	2013		1,897,900		—		4,846			1,902,746
Depreciation, depletion, amortization and accretion	2014		2,111,370		356		—			2,111,726
	2013		639,395		54		—			639,449
Property and equipment acquisitions, including oil and gas properties	2014		1,986,807		—		—			1,986,807
	2013		13,377,891		—		5,281			13,383,172

Total assets, net of intercompany accounts:
March 31, 2014			94,198,338		20,174					94,218,512
December 31, 2013			90,098,192		17,129					90,115,321

Property and equipment acquisitions include accrued amounts and reclassifications.

NOTE 12 - RELATED PARTY TRANSACTIONS

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 $16,000 and $16,000 for 2013 and 2014, respectively.

F-16

NOTE 13 - SUBSEQUENT EVENTS

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

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

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

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

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

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

•

financial condition;

•

material adverse effects;

•

corporate existence;

•

corporate authorizations and powers;

•

enforceable obligations; and

•

existing indebtedness and material litigation.

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

F-17

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

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

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

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

The NPI Agreement provides the Agent with the option to sell its NPI for fair value, as defined in the NPI Agreement, alongside American Shale or Trans Energy in the event that either American Shale or Trans Energy sells interests, including partial interests, in the subject properties at a fair value for the NPI that meets or exceeds $1.5 million for each 1.0% of NPI earned by Agent prior to such date. In such event, American Shale can also require the Agent to sell all of its NPI to American Shale (or, alternatively, to the buyer of any subject interests) for fair value. In the event of a sale of all or substantially all of the assets of American Shale, fair value is defined as the net cash received that is attributable to the equity interests of either American Shale or Trans Energy in such transaction.

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

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

On April 30, 2014, the Company’s Compensation Committee approved an annual grant under the long-term incentive bonus program of 43,000 shares of common stock and 288,000 stock options, at a strike price of $3.80/share, to certain of the Company’s employees and Board Members and subject to vesting semi-annually over a three year period. The term of the stock options awarded is five years.

F-18

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 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 2013 Form 10-K.

Results of Operations

Three months ended March 31, 2014 compared to March 31, 2013

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 March 31, 2014 and 2013.


	Three months ended March 31,
	2014			2013
Total revenues	$	9,776,342		$	3,609,326
Total costs and expenses		(6,815,495	)		(4,519,427	)
Gain (loss) on sale of assets		207,396			(8,787	)

Income (loss) from operations		3,168,243			(918,888	)
Other expenses, net		(4,696,477	)		(1,774,248	)
Income tax		—			—

Net loss	$	(1,528,234	)	$	(2,693,136	)

The following table is a summary of revenues, volumes, and pricing for the three months ended March 31, 2014 and 2013.

Three Months Ended March 31, 2014 compared to the Three Months Ended March 31, 2013


	Three Months Ended March 31,				Increase/
	2014		2013		(Decrease)
Natural gas sales	$	7,937,764	$	2,796,438	$	5,141,326		183.9	%
Oil sales	$	61,302	$	71,723	$	(10,421	)	-14.5	%
Natural gas liquid sales	$	1,717,356	$	705,722	$	1,011,634		143.3	%

Total Oil & Gas Sales	$	9,716,422	$	3,573,883	$	6,142,539		171.9	%
Transportation and other revenue	$	59,920	$	35,443	$	24,477		69.1	%

Total revenue	$	9,776,342	$	3,609,326	$	6,167,016		170.9	%
Net Production
Natural gas sales (MCF)		1,444,304		708,520		735,784		103.8	%
Oil sales (Bbls)		788		813		(25	)	-3.0	%
Natural gas liquids (gallons)		1,467,191		1,045,943		421,248		40.3	%
Natural Gas Equivalent ( MCFe)		1,658,630		862,815		795,815		92.2	%
Average Sales Price per Unit
Natural Gas (MCF)	$	5.50	$	3.95	$	1.55		39.2	%
Oil(Bbl)	$	77.81	$	88.27	$	(10.46	)	-11.9	%
Natural gas liquids (gallons)	$	1.17	$	0.67	$	0.50		74.6	%
Natural Gas Equivalent (MCFe)	$	5.86	$	4.14	$	1.72		41.5	%


Total revenue		$ 9,776,342		$ 3,609,326		$ 6,167,016		170.9%

Expenses

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


	Three Months Ended March 31,
	2014		2013
Costs and Expenses Per MCFE of Production:
Production Expenses	$	1.73	$	2.04
Production Taxes		0.22		0.54
G&A Expenses (Excluding Share-Based Compensation)		0.75		1.45
Non-Cash Shared-Based Compensation		0.12		0.36
Depletion of Oil and Natural Gas Properties		1.26		0.71
Impairment of Oil and Natural Gas Properties		—		—
Depreciation and Amortization		0.01		0.03
Accretion of Discount on Asset Retirement Obligation		—		—

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 2013 drilling. For the three months ended March 31, 2014 and 2013, respectively, we had 28 gross wells and 12.08 net wells compared to 21 gross wells and 8.66 net wells.

Production costs increased $936,310 or 40% for the three months ended March 31, 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 $1,472,277 or 230% for the three months ended March 31, 2014 compared to the same period for 2013, primarily due to the increased production volumes and lower year end reserves.

Selling, general and administrative expense decreased $112,519 or 7% for the three months ended March 31, 2014 as compared to the same period for 2013, primarily due to an decrease in legal and professional fees.

Interest expense increased $2,228,447 or 117% for the three months ended March 31, 2014 as compared to the same period for 2013 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 March 31, 2014 the average loan balance was $87,766,550 compared to $58,833,333 for the same period in 2013.

Gain on warrant derivative for the three months ended March 31, 2014 was $0 as compared to a gain of $123,677 for the same period last year. This represents the change in value of the put option associated with our warrant derivative liability.

Loss on commodity derivative for the three months ended March 31, 2014 was $566,192. This represents the decrease in the fair value of our gas hedges.

Net loss for the three months ended March 31, 2014 was $1,528,234 compared to a net loss of $2,693,136 for the same period of 2013. This decrease in net loss is due primarily to the increase in operating income.

Liquidity and Capital Resources

Historically, we have satisfied our working capital needs with borrowed funds and the proceeds of acreage sales. At March 31, 2014, we had negative working capital of $1,313,318 compared to positive working capital of $65,897 at December 31, 2013. The decrease in working capital is primarily due to an increase in accounts payable to drilling operator.

During the first three months of 2014, net cash provided by operating activities was $833,688 compared to $1,123,876 of net cash used for the same period of 2013. This increase in cash flow from operations was primarily due to higher production volumes, higher commodity prices, and an increase in account payable and accruals.

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 three months of 2014, net cash used by investing activities was $1,727,264 compared to net cash provided of $1,234,883 in the same period in 2013. The change was due to higher capital expenditures in 2014 as well as greater proceeds from the sale of assets in 2013.

During the first three months of 2014, net cash provided by financing activities was $12,647 compared to net cash provided of $24,884,064 for the same period in 2013. This change was due to lower proceeds from borrowing 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.

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, 2013.

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

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

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

EQT Corporation

On May 11, 2011, we filed an action in the U.S. District Court for the Northern District of West Virginia against EQT Corporation, a Pennsylvania corporation (Trans Energy, Inc., et al. v. EQT Corporation). The action relates to our attempt to quiet title to certain oil and gas properties referred to as the Blackshere Lease, consisting of approximately 22 oil and/or gas wells on the Blackshere Lease. The defendant, EQT Corporation, has filed with the Court an answer and counterclaim wherein it claims it holds title to the natural gas within and underlying the Blackshere Lease. We believe that we will ultimately prevail in the action, but it is too early in the proceedings to accurately assess the final outcome. Currently the Company has no plans to drill on this acreage. On September 5, 2012, the parties filed competing motions seeking summary judgment in this case. On November 26, 2012, the Court granted our motion for summary judgment and denied the defendant’s motions for declaratory judgment and summary judgment. On February 25, 2014, the United States Court of Appeals for the Fourth Circuit in Richmond Virginia affirmed the summary judgment motion of the U.S. District Court for the Northern District of West Virginia. At this time we are not aware if the defendant plans any further appeals, including an appeal to the Supreme Court of the United States.

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

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

Abcouwer

On March 6, 2012, James K. Abcouwer (“Abcouwer”), former Chief Executive Officer of the Company, filed an action in the Circuit Court of Kanawha County, West Virginia against the Company (James K. Abcouwer vs. Trans Energy, Inc.). The action relates to the Stock Option Agreement (the “Agreement”) entered into between the Company and Abcouwer on February 7, 2008. By his complaint, Abcouwer alleges that the Company has breached the Agreement by not permitting Abcouwer to exercise options that are the subject of the Agreement. The Company believes that according to the terms of the Agreement all options and other rights described in the Agreement terminated ninety (90) days after the termination of Abcouwer’s employment with the Company. Mr. Abcouwer is requesting an amount for his loss of the value of the stock options that are subject to the Agreement. Said amount has not been determined. Trial date has been set for June 23, 2014.

On January 14, 2013, Abcouwer filed an action in the Circuit Court of Kanawha County, West Virginia against the Company, and two individual defendants currently on the Board of Directors of the Company – William F. Woodburn and Loren E. Bagley. In his complaint, Abcouwer alleges that Plaintiff and Defendants entered into a verbal agreement that required the Company to enter into a third party sales transaction which would have allegedly caused Abcouwer to make significant profit as the result of his ownership of Company stock. Abcouwer alleges that he lost approximately $30 million as a result of the fact that no sale of the Company ever took place. The Company believes that no such agreement existed and that Abcouwer’s claims are wholly without merit. On March 25, 2013, the Company filed an answer denying the existence of any liability and asserting, in the alternative, counterclaims for fraud and breach of fiduciary duty. The Company’s counterclaims allege that, to the extent a binding agreement between Abcouwer and the Company existed, Abcouwer failed to disclose such agreement to the Company and the SEC despite a duty to do so. Trial date has been set for November 17, 2014.

EPA

On September 28 and December 17, 2012, the U.S. Environmental Protection Agency (“EPA”) issued to the Company seven administrative compliance orders and a request for information. The orders and request relate to our compliance with Clean Water Act (“CWA”) permitting requirements at seven pond and/or well site locations in Marshall and Wetzel Counties, West Virginia and concern the alleged discharge of dredged and/or fill material into waters of the United States. The Company is actively cooperating with the EPA to resolve these matters in a timely manner. The CWA provides authority for significant civil and criminal penalties for the placement of fill in a jurisdictional stream or

wetland without a permit from the Army Corps of Engineers, including for civil penalties as high as $37,500 per day per violation. Monetary civil and/or criminal penalties can be substantial for non-compliance with CWA requirements. The CWA sets forth criteria, including degree of fault and history of prior violations, which may influence CWA penalty assessments. The EPA may also seek to recover any economic benefit derived from non-compliance with the CWA.

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

Item 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.

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase

**101.DEF		XBRL Taxonomy Extension Definition Linkbase

**101.LAB		XBRL Taxonomy Extension Label Linkbase

**101.PRE		XBRL Taxonomy Extension Presentation Linkbase

**	Filed herewith.

SIGNATURES

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: June 12, 2014	By	/s/ John G. Corp
		JOHN G. CORP
		Principal Executive Officer

Date: June 12, 2014	By	/s/ John S. Tumis
		JOHN S. TUMIS
		Chief Financial Officer