TRANS ENERGY INC - FORM 10-Q - November 10, 2016

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EX-32.2 - EX-32.2 - TRANS ENERGY INC	d69875dex322.htm
EX-32.1 - EX-32.1 - TRANS ENERGY INC	d69875dex321.htm
EX-31.2 - EX-31.2 - TRANS ENERGY INC	d69875dex312.htm
EX-31.1 - EX-31.1 - TRANS ENERGY INC	d69875dex311.htm
EX-10.1 - EX-10.1 - TRANS ENERGY INC	d69875dex101.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2016

☐	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 ☒ 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 ☒ 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 ☒

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 10, 2016
Common Stock, $0.001 par value		16,131,648

Table of Contents


Heading	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

Condensed Consolidated Balance Sheets —September 30, 2016 and December 31, 2015		F-1

Condensed Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2016 and 2015		F-3

Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2016 and 2015		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		8

PART II OTHER INFORMATION

Item 1. Legal Proceedings		9

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		10

Item 3. Defaults Upon Senior Securities		11

Item 4. Mine Safety Disclosures		11

Item 5. Other Information		11

Item 6. Exhibits		11

Signatures		12

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets


	September 30, 2016			December 31, 2015
	Unaudited			Audited
ASSETS
CURRENT ASSETS
Cash	$	389,003		$	473,081
Restricted cash		18,839			231,916
Accounts receivable, trade		2,377,335			1,730,426
Accounts receivable due from drilling operator, net		258,892			—
Commodity derivatives		1,091,835			3,417,887
Advance royalties		501,570			337,133
Prepaid expenses		616,827			642,740

Total current assets		5,254,301			6,833,183
OIL AND GAS PROPERTIES, USING SUCCUSSFUL EFFORTS ACCOUNTING
Proved properties		101,908,062			84,956,392
Unproved properties		8,204,423			6,829,029
Pipelines		4,151,744			4,435,421
Accumulated depreciation, depletion and amortization		(43,481,119	)		(26,442,766	)

Oil and gas properties, net		70,783,110			69,778,076
PROPERTY AND EQUIPMENT, net of accumulated depreciation of $431,545 and $404,669, respectively		403,028			426,601
OTHER ASSETS
Assets held for sale		—			13,460,614
Commodity derivatives		1,104,800			2,423,508
Other assets		392,477			390,925

Total other assets		1,497,277			16,275,047

TOTAL ASSETS	$	77,937,716		$	93,312,907

See notes to unaudited condensed consolidated financial statements.

F-1

TRANS ENERGY, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (continued)


	September 30, 2016			December 31, 2015
	Unaudited			Audited
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES
Accounts payable, trade	$	1,329,300		$	1,321,852
Accounts payable due to drilling operator, net		—			548,086
Accounts payable, related party		1,500			1,500
Accrued expenses		1,770,947			1,954,257
Environmental settlement and related costs		1,750,000			2,000,000
Revenue payable		8,720			8,578
Commodity derivatives		28,234			474,696
Notes payable, net — current (Note 7)		138,671,655			117,512,487

Total current liabilities		143,560,356			123,821,456
LONG-TERM LIABILITIES
Notes payable, net		2,439,422			2,134,018
Asset retirement obligations		76,785			39,669
Environmental settlement and related costs		3,000,000			3,000,000
Commodity derivatives		344,246			1,253,024
Deferred revenue		—			62,510

Total long-term liabilities		5,860,453			6,489,221

Total liabilities		149,420,809			130,310,677
COMMITMENTS AND CONTINGENCIES		—			—
STOCKHOLDERS’ DEFICIT
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; 16,131,648 and 15,263,977 shares issued, and 16,129,648 and 15,261,977 shares outstanding, respectively		16,132			15,264
Additional paid-in capital		47,033,432			45,965,168
Treasury stock, at cost, 2,000 shares		(1,950	)		(1,950	)
Accumulated deficit		(118,530,707	)		(82,976,252	)

Total stockholders’ deficit		(71,483,093	)		(36,997,770	)

TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$	77,937,716		$	93,312,907

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,
	2016			2015			2016			2015
OPERATING REVENUES
Oil and gas sales	$	1,711,185		$	2,228,503		$	6,069,756		$	9,104,392
Natural gas liquid sales		503,720			434,008			1,493,368			1,563,783
Gas transportation, gathering, and processing		23,166			45,844			66,331			129,733
Other income		13,033			2,766			14,028			8,680

Total operating revenues		2,251,104			2,711,121			7,643,483			10,806,588
OPERATING COSTS AND EXPENSES
Production costs		1,441,826			2,381,999			6,756,404			9,559,963
Depreciation, depletion, amortization and accretion		1,762,731			979,566			12,288,835			5,371,023
General and administrative		1,678,878			755,637			3,519,141			3,781,091
Gain on sale of assets		(3,083	)		—			(133,083	)		—

Total operating costs and expenses		4,880,352			4,117,202			22,431,297			18,712,077

LOSS FROM OPERATIONS		(2,629,248	)		(1,406,081	)		(14,787,814	)		(7,905,489	)
OTHER INCOME (EXPENSES)
Interest income		543			556			1,650			1,637
Interest expense		(7,449,490	)		(6,117,014	)		(21,471,662	)		(12,280,494	)
Gain on derivative assets		2,100,443			2,922,063			703,371			9,770,324

Total other expenses		(5,348,504	)		(3,194,395	)		(20,766,641	)		(2,508,533	)

NET LOSS BEFORE INCOME TAXES		(7,977,752	)		(4,600,476	)		(35,554,455	)		(10,414,022	)
INCOME TAX		—			—			—			—

NET LOSS	$	(7,977,752	)	$	(4,600,476	)	$	(35,554,455	)	$	(10,414,022	)
NET LOSS PER SHARE — BASIC AND DILUTED	$	(.50	)	$	(.30	)	$	(2.27	)	$	(.69	)
WEIGHTED AVERAGE SHARES — BASIC AND DILUTED		16,109,380			15,161,727			15,634,107			15,057,403

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(35,554,455	)	$	(10,414,022	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion, amortization and accretion		12,288,835			5,371,023
Amortization of financing costs and debt discount		4,269,825			2,080,632
Share-based compensation		289,113			817,030
Professional fees paid by common stock issuance		780,019			270,000
Gain on sale of assets		(133,083	)		—
Interest and legal expense added to principal		17,194,747			4,917,077
Total gain on commodity derivatives		(703,371	)		(9,770,324	)
Cash settlement of commodity derivatives		2,992,891			14,238,371
Changes in operating assets and liabilities:
Changes in restricted cash		213,077			(786,581	)
Accounts receivable, trade		(665,409	)		1,662,134
Accounts receivable due from operator		(258,892	)		—
Accounts receivable, related party		18,500			—
Prepaid expenses and other current assets		(138,524	)		(64,152	)
Other assets		(1,552	)		(1,528	)
Accounts payable and accrued expenses		(175,862	)		(2,873,250	)
Accounts payable due to operator		(548,086	)		(6,031,736	)
Environmental settlement and related costs		(250,000	)		(1,600,000	)
Deferred revenue		(62,510	)		—
Revenue payable		142			9,492

Net cash used in operating activities		(444,595	)		(2,175,834	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets		150,000			—
Expenditures for oil and gas properties		223,820			(114,515	)
Expenditures for property and equipment		(13,303	)		(5,168	)

Net cash provided by (used in) investing activities		360,517			(119,683	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Financing costs paid		—			(1,436,218	)
Payments on notes payable		—			(796,313	)
Proceeds from notes payable		—			3,050,000
Stock options exercised		—			327,016

Net cash provided by financing activities		—			1,144,485

NET DECREASE IN CASH		(84,078	)		(1,151,032	)

CASH, BEGINNING OF PERIOD		473,081			1,585,530

CASH, END OF PERIOD	$	389,003		$	434,498

SUPPLEMENTAL DISCLOSURES FOR CASH FLOW INFORMATION:
CASH PAID FOR:
Interest	$	2,091		$	6,282,782
Income taxes		—			—
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued expenditures for oil and gas properties	$	548,086		$	5,777,983
Increase in asset retirement obligation	$	28,777		$	34,116

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 States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. Accordingly, they do not include certain information and footnote disclosures normally included in a full set of financial statements prepared in accordance with GAAP. The information furnished in the interim condensed consolidated financial statements includes normal recurring adjustments and reflects all adjustments, which, in the opinion of management, are necessary for a fair presentation of such financial statements. Although management believes the disclosures and information presented are adequate to make the information not misleading, these interim condensed consolidated financial statements should be read in conjunction with our most recent audited condensed consolidated financial statements and notes thereto included in our December 31, 2015 Annual Report on Form 10-K. Operating results for the nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

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 2015 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, 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 development 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 generally accepted accounting principles (“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.

Restricted Cash

On September 3, 2015, American Shale entered into a Deposit Account Control Agreement (“DACA”) with Morgan Stanley Capital Group, Inc., administrative agent for the Lenders (“Agent”) and United Bank, Inc. Currently, the settlements related to the Company’s derivative and hedge financial instruments are deposited directly into depository accounts subject to the DACA. The agent exercises control of the depository accounts subject to the DACA and has the ability to prevent disbursements from those restricted accounts to our unrestricted cash accounts. Amounts deposited into these accounts are generally released to us in a timely manner. As of September 30, 2016, current restricted cash includes $18,839 of cash temporarily held in accounts controlled by our agent. See Note 7 for a more detailed discussion of the Forbearance Agreement.

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

The Company follows the successful efforts method of accounting for its oil and gas exploration and production activities. Under this method, all property acquisition costs, and costs of exploratory and development wells are capitalized until a determination is made that the well has found proved reserves or is deemed noncommercial. If an exploratory well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole costs. Exploration expenses include dry hole costs and geological and geophysical expenses. Noncommercial development well costs are charged to impairment expense if circumstances indicate that a decline in the recoverability of the carrying value may have occurred.

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. Depreciation, depletion, and amortization (“DD&A”) of capitalized costs related to proved oil and gas properties is calculated on a field-by-field basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the estimated proceeds from salvaging equipment. 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.

Depreciation, depletion, and amortization expenses on oil and gas properties were $12,166,002 and $5,313,113 for the nine months ended September 30, 2016 and 2015, respectively.

Total additions for oil and gas properties for the nine months ended September 30, 2016 and 2015 were $(223,820) and $114,515, respectively. During 2016 the additions for oil and gas properties of $1,378,032 were reduced by $1,601,852 as a result of change in ownership percentage due to unitization of various leases.

The sale of a partial interest in a proved oil and gas property is accounted for as a normal retirement, and no gain or loss is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. A gain or loss is recognized for all other sales of producing properties. The sale of a partial interest in an unproved oil and gas property is accounted for as a recovery of cost, with any excess of the proceeds over such cost or related carrying amount recognized as gain.

Impairments

GAAP requires that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate 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 an impairment for the difference between the carrying value and fair market value of the properties.

No impairments were recorded for the three and nine month periods ended September 30, 2016 and 2015.

F-6

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 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. 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 condensed consolidated statements of operations. The pricing models used for valuation often incorporate significant estimates and assumptions, which may impact the level of precision in the condensed consolidated financial statements. Under the terms of each derivative contract, these are in cross-default with the Company’s default on its notes with Morgan Stanley as further discussed in Note 7. Under the terms of the Forbearance Agreement discussed in Note 7, because the affiliate counterparty of the derivative contracts has also agreed to forbear on exercising its rights it is entitled to under default, we believe the classifications disclosed in the condensed consolidated balance sheets is appropriate.

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 equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset which has been determined to be 40 years for Marcellus Shale wells.

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


	2016		2015
Asset retirement obligations at beginning of period	$	39,669	$	90,928
Liabilities incurred during the period		28,777		34,116
Accretion expense		8,339		3,000

Asset retirement obligations at end of period	$	76,785	$	128,044

At September 30, 2016 and December 31, 2015, our current portion of the asset retirement obligation was $0.

Income Taxes

At September 30, 2016, the Company had net operating loss carry forwards (“NOLs”) for future years of approximately $121.2 million. These NOLs will expire at various dates through 2035. There is no current tax expense for the three or nine months ended September 30, 2016 due to a net operating loss for the period. No tax benefit has been recorded in the consolidated financial statements for the remaining NOLs or Alternative Minimum Tax (“AMT”) credit since the potential tax benefit is offset by a valuation allowance of the same amount. Utilization of the NOLs could be limited if there is a substantial change in ownership of the Company and is contingent on future earnings.

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

The Company has no material unrecognized tax benefits. No tax penalties or interest expense were accrued as of September 30, 2016 or December 31, 2015 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 2012 remain open to examination by U.S. federal and state tax jurisdictions, however prior year net operating losses remain open for examination.

F-7

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, 2016 and December 31, 2015. 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.

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 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 $91,124 and $125,027 for the three months ended September 30, 2016 and 2015, respectively. We recorded total share-based compensation expense of $289,113 and $817,030 for the nine months ended September 30, 2016 and 2015, respectively.

New Accounting Standards

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which simplifies several aspects of the accounting for share-based payment award transactions including accounting for income taxes and classification of excess tax benefits on the statement of cash flows, forfeitures and minimum statutory tax withholding requirements. For the Company, ASU 2016-09 is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any interim or annual period. The Company is currently evaluating the potential impact on the financial statements.

In February 2016, the FASB issued ASU 2016-02, “Leases” (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating the potential impact on the financial statements.

In January 2016, the FASB issued ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities” (“ASU 2016-01”), which amended its standards related to the accounting of certain financial instruments. This amendment addresses certain aspects of recognition, measurement, presentation and disclosure. The new rules will become effective for annual and interim periods beginning after December 15, 2017. Early adoption is not permitted. The Company is currently evaluating the potential impact on the financial statements.

In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”). The purpose of the standard update was to simplify presentation of debt issuance costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Amortization of the discount or premium shall be reported as interest expense in the case of liabilities or as interest income in the case of assets. Amortization of debt issuance costs also shall be reported as interest expense. ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Company adopted this standard effective January 1, 2016 and the impact of adopting this standard is discussed further in Note 7.

F-8

In May 2014, the FASB issued ASU 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 principle 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. In March 2016, the FASB issued ASU 2016-08, “Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” (“ASU 2016-08”), which clarifies principal versus agent when another party, along with the entity, is involved in providing a good or service to a customer. In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing.” This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09. In May 2016, the FASB issued ASU No. 2016-12, “Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients.” This ASU amends certain issues in ASU 2014-09 on transition, collectability, noncash consideration, and the presentation of sales taxes and other similar taxes. Topic 606, “Revenue from Contracts with Customers”, requires an entity to determine whether the nature of its promise is to provide that good or service to the customer (i.e., the entity is a principal) or to arrange for the good or service to be provided to the customer by the other party (i.e., the entity is an agent). The original effective date for financial statements issued by public companies was for annual reporting periods beginning after December 15, 2016. In July 2015, the FASB deferred the effective date for annual reporting periods beginning after December 15, 2017 (including interim reporting periods within those periods). Early adoption is permitted to the original effective date. The Company is currently evaluating which method of adoption will be used as well as the potential impact on the financial statements.

On August 27, 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern” (“ASU 2014-15”). ASU 2014-15 will require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU 2014-15 becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company is currently evaluating the potential impact 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.

Reclassifications

Certain amounts in the 2015 condensed consolidated financial statements have been reclassified to conform to the 2016 presentation. This reclassification included reclassifying natural gas liquid sales from oil and gas sales given its significant balances. These sales are presented as a separate line item in the condensed consolidated statements of operations of $503,720 and $434,008 for the three months ended September 30, 2016 and 2015, respectively, and $1,493,368 and $1,563,783 for the nine months ended September 30, 2016 and 2015, respectively. This reclassification also included reclassifying restricted cash to cash. The amount reclassified was $238,457 at December 31, 2015 on the condensed consolidated balance sheets and $786,581 on the condensed consolidated statements of cash flow for the nine months ended September 30, 2015. This reclassification also included reclassifying accounts receivable, related parties to accounts receivable, trade. The amount reclassified was $18,500 at December 31, 2015. These changes had no impact to previously reported total operating revenues or net income.

NOTE 2 — GOING CONCERN

The Company has incurred losses from operations of approximately $35.6 million, and has experienced negative cash flows from operations of approximately $445,000 for the nine months ended September 30, 2016. In addition, the Company has negative working capital of approximately $138.3 million and its cash balance was approximately $389,000 as of September 30, 2016. Additionally, during the third quarter of the year, the Company entered into a forbearance agreement (Note 7) with its lender. As a result of these conditions and events, there is substantial doubt about the Company’s ability to continue as a going concern. On October 24, 2016, the Company entered into a Merger Agreement with EQT Corporation and WV Merger Sub, Inc., as discussed in Note 15 to the Company’s financial statements. If the transactions contemplated therein are consummated in accordance with their terms, the Company will become a wholly owned subsidiary of EQT Corporation and will cease filing reports with the SEC.

F-9

NOTE 3 — ACCOUNTS RECEIVABLE DUE FROM DRILLING OPERATOR AND ACCOUNTS PAYABLE DUE TO DRILLING OPERATOR

Prior to 2012, we had 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.

The amount due from the drilling operator as of September 30, 2016 and December 31, 2015, respectively, is $258,892 and $218,456 for charges related to employee salary reimbursements, travel expenses and lease costs.

The amount due to the drilling operator as of December 31, 2015 was $766,542 for charges incurred, but not paid.

NOTE 4 — ASSETS AND LIABILITIES HELD FOR SALE

On April 3, 2015, Trans Energy, and its wholly owned subsidiaries American Shale and Prima, along with Republic Energy Ventures, LLC, Republic Partners VIII, LLC, Republic Partners VI, LP, Republic Partners VII, LLC, and Republic Energy Operating, LLC (collectively, the “Sellers”) entered into a Purchase and Sale Agreement (the “PSA”), pursuant to which the Sellers agreed to sell certain interests located in Wetzel County, West Virginia, including 5,159 net acres held by the Company and the Company’s interest in twelve Marcellus producing wellbores, to TH Exploration, LLC (“Buyer”). On July 30, 2015, the Buyer elected to formally extend the expiration date of the PSA until August 14, 2015 (the “Extension Period”). During the Extension Period, the Buyer provided notice to the Company that the PSA would terminate on August 13, 2015. The Company believes that the PSA terminated as a result of such notice. Because of uncertainty surrounding whether the Buyer would contest the termination of the PSA along with Management’s intention to sell the underlying assets as soon as such uncertainty was definitively resolved, the Wetzel county assets were reported as assets held for sale at December 31, 2015. In January 2016, the Wetzel county assets were reclassified to proved oil and gas properties and a catch-up entry for the depletion was booked by the Company in the amount of $4,372,965. No assets were ultimately sold under this PSA.

Total assets held for sale as of September 30, 2016 and December 31, 2015 were $0 and $13,460,614, respectively.

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 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 May 21, 2014 (“Funding Date”), American Shale entered into a purchase and sale agreement (the “Republic PSA”) with its joint development partner, Republic Energy Ventures (“Republic”). As part of the Republic PSA, Republic agreed to amend the Amended Joint Development Agreement with American Shale (the “AJDA”). Under the revised AJDA, Republic agreed to fund all costs associated with new leasehold acquisitions subsequent to April 1, 2014. American Shale has the right to buy a 25% interest in any such leasehold at Republic’s cost, plus 12% interest, in the event that Republic sells its interest in the leasehold or permits a third party to drill a well on the leasehold. In the event that American Shale repays Republic under the terms of the Republic PSA, American Shale will have the option to fund a 50% portion of any future leasehold expenditures, upon providing satisfactory evidence of its ability to continue such funding on a go-forward basis.

F-10

On December 24, 2014, American Shale closed a transaction pursuant to a Purchase and Sale Agreement (the “PSA”) executed as of December 24, 2014 with Wellbore Capital, LLC, a Delaware limited liability company (“Wellbore”). Pursuant to the PSA, American Shale granted to Wellbore overriding royalty interests in certain leases (the “Oil and Gas Properties”) located in Wetzel and Marion Counties, West Virginia (collectively, the “ORRI”). Under the PSA, the purchase price for the ORRI was $11.0 million, of which the Company received approximately $10.7 million in cash at closing. The PSA provides Wellbore the right to sell its interests in the ORRI to a third party acquiror in the event that American Shale sell all of its interests in the oil and gas properties to such acquiror. If such sale occurs prior to December 31, 2017, Wellbore alternatively has the right to require American Shale to repurchase the ORRI for a certain return on its investment in the ORRI.

On April 27, 2015, American Shale entered into an agreement with Republic Energy Operating, LLC. Under this agreement, American Shale agreed to the disposition of a portion of American Shale’s working and net revenue interests in wells in Marion County, West Virginia (the “Working Interests”) that have been recently drilled but not completed. American Shale reserved the option to reacquire the Working Interests pursuant to a notice of election at agreed upon prices set forth in the agreement.

NOTE 6 — ENVIRONMENTAL SETTLEMENT AND RELATED COSTS

On October 1, 2014, Trans Energy, Inc. pleaded guilty to three misdemeanor charges related to Unauthorized Discharge into a Water of the United States in violation of the Clean Water Act. In connection with this plea, the Company agreed to pay a $600,000 fine and was placed on probation for a period of two years.

On August 25, 2014, we entered into a civil Consent Decree with the EPA with respect to the Clean Water Act matter and related issues that were discovered based upon an internal audit that we conducted. The Consent Decree requires us to pay a $3,000,000 civil penalty in two installments. The Company paid the first installment on its penalty in the amount of $1 million, plus interest, on July 20, 2015. Under an agreement with the United States and the State of West Virginia, the Company paid a second installment on its penalty in the amount of $250,000 on April 8, 2016, and a third installment in the amount of $1,750,000, plus interest, is now due on April 21, 2017. The Consent Decree requires us to perform certain restoration activities at the affected pond, well pad and access road sites over a period of three construction seasons. The Company is in the process of submitting delineation reports and restoration plans, with corresponding timelines for performing restoration activities, to the EPA for approval. The EPA has estimated that the restoration will cost as much as $13 million, but we intend to perform the work in a manner that will cause our costs to be significantly below this estimate. Management has recorded a $3,000,000 long-term environmental settlement and related costs liability as of September 30, 2016 and December 31, 2015 to reflect its best estimate of what the restoration costs will actually be. The Consent Decree also requires us to put in place and maintain an environmental compliance program. Finally, on December 21, 2015, the Company entered into an Administrative Agreement with the EPA Suspension and Debarment Division to resolve all matters relating to suspension, debarment, and statutory disqualification arising from the Company’s Clean Water Act misdemeanor plea. The Agreement requires that the Company comply with its plea agreement and Consent Decree, establish and review with employees a Code of Business Conduct and Ethics, establish an ethics hotline, prepare semiannual compliance reports, and retain an independent monitor to certify the Company’s compliance.

F-11

NOTE 7 — NOTES PAYABLE

On May 21, 2014, American Shale, entered into a credit agreement (hereafter the “Credit Agreement”) by and among American Shale, several lenders (the “Lenders”), and Morgan Stanley Capital Group Inc. as the administrative agent (“Agent”). Trans Energy is a guarantor of the Credit Agreement as is Prima, another of our wholly owned subsidiaries. The Credit Agreement initially provided that the Lenders would lend American Shale up to $200 million, including an initial draw of $102.5 million plus a PIK fee of $593,750, a contingent committed amount of $47.5 million and an uncommitted amount of $50 million (the “Loans”). The initial draw under the facility was used primarily to repay all of the outstanding debt under a previous Credit Agreement, as well as to fund certain fees and expenses incurred in connection with the Credit Agreement. Additional amounts up to $47.5 million were originally allowed to 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 PV-9 that was projected six months from the date of each drawdown, met certain pre-defined targets.

In connection with obtaining financing in May 2014 and subsequent borrowings, we incurred fees and costs of $6,242,874. Per the guidance of ASU 2015-03 the loan costs are presented as a reduction to the notes payable - current on the accompanying Condensed Consolidated Balance Sheets and will be amortized to interest expense over the life of the note using the interest rate method (see Note 1). At September 30, 2016 and December 31, 2015, the balance of the notes payable - current was reduced by $887,546 and $3,550,184 related to the loan costs, respectively, and the Company had recognized $5,355,328 and $2,692,690, respectively, of cumulative interest expense related to the amortization of the loan costs.

The Loans initially bore 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 has subsequently increased in connection with the First Amendment and Waiver, as more fully described below. Interest is due and payable monthly in arrears. For the three and nine months ended September 30, 2016, the Company recorded interest expense of $5,914,048 and $16,889,343, related to the Credit Agreement, respectively.

On the Funding Date, American Shale also entered into a Net Profits Interest Agreement (the “NPI Agreement”) with the Agent. The NPI Agreement provides that subsequent to the repayment of the Loans, American Shale will pay a net profits interest to the Agent (the “NPI”). The NPI is to be calculated based on production revenues less certain expenditures, including operating costs, general and administrative expenses, interest and capital expenditures. The amount of interest expense and general and administrative expenses that can be charged are limited based on the amounts that were previously expensed prior to repayment of the Loans. The NPI is earned based on amounts borrowed under the Credit Agreement. As of the Funding Date, a NPI of 6.5% of the net profits, as defined under the NPI Agreement, has been earned. The Agent will earn up to an additional 2.5% of the net profits pro rata for any subsequent borrowing by American Shale under the $47.5 million contingent commitment. At June 30, 2014, the Company recorded a discount related to the NPI of $3,339,376 on proved property and $733,034 on unproved property. The total value recorded as a discount on loan payable related to the NPI was $4,072,410. For the three months and nine months ended September 30, 2016, the Company recorded interest expense related to accretion of the NPI discount in the amount of $535,729 and $1,607,187 respectively, which is computed using the straight line method (as it approximated the effective interest method) over the life of the loan (see below for details regarding the First Amendment and Waiver).

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

On April 27, 2015, American Shale entered into a consent and agreement (the “Consent and Agreement”) that amended the Credit Agreement and the associated NPI agreement. The Consent and Agreement reduced the contingent borrowing availability under the Tranche B facility from $47.5 million to $10.0 million, and eliminated the Tranche C facility. Potential borrowings under the Tranche B facility had been contingent on American Shale’s ability to meet certain levels of PV-9 value for its producing properties, and as such there was no additional availability under Tranche B as of the signing of the Consent and Agreement. There were no other changes to the terms of the Tranche A facility loans under the Credit Agreement. The NPI agreement was amended to set the contingent NPI percentage at approximately 2.53%.

Under the Consent and Agreement, the administrative agent also consented to the monetization of a portion of American Shale’s natural gas hedges and the disposition of a portion of American Shale’s working and net revenue interests in wells in Marion County, West Virginia (the “Working Interests”) that have been recently drilled but not completed.

F-12

On the same date, American Shale entered into an agreement with Republic Energy Operating, LLC. Under this agreement, American Shale agreed to use the proceeds from the hedge monetization as well as the sale of the Working Interests to pay all amounts due under the March 2015 joint interest billing statement provided by Republic Energy Operating, LLC in the amount of approximately $13.8 million. American Shale reserved the option to reacquire the Working Interests pursuant to a notice of election at agreed upon prices set forth in the agreement.

On July 31, 2015, American Shale entered into an amendment and waiver (the “First Amendment and Waiver”) that amended the Credit Agreement and the associated NPI agreement. Under the terms of the First Amendment and Waiver, the parties agreed to:

•

Increase the Applicable Margin to 12% in the event that interest is paid in cash, and 14% if paid in kind (which represented a change from the 9% Applicable Margin then currently payable in cash);

•

Change the Maturity Date to December 31, 2016;

•

Remove the Leverage Ratio covenant;

•

Add a covenant requiring the PV-9 of American Shale’s proved reserves to be greater than 1.5 times the net debt, with a minimum PDP component of proved reserves that increases over time;

•

Eliminate the make-whole premium and any other prepayment penalties related to debt paydowns;

•

Require American Shale to limit its capital expenditures and other monthly expenditures to amounts agreed upon in the First Amendment and Waiver;

•

Require American Shale to close the sale of assets in Wetzel County and pay down at least $30 million of debt by September 30, 2015;

•

Allow American Shale to use the next $17 million of proceeds from the Wetzel County sale, plus 50% of any proceeds thereafter, primarily for expenditures in connection with an approved plan of development;

•

Begin a process to refinance the debt facility, or otherwise effect its paydown through a sale of assets, during the first quarter of 2016;

•

Defer any payment related to the NPI on the Wetzel County assets until the loans are repaid in full;

•

Increase the NPI on the assets remaining after the Wetzel County sale by 2%, to approximately 11%;

•

Pay total fees to the administrative agent of $4 million, of which $1 million was added to the loan balance upon execution of the First Amendment and Waiver. The remainder was to be added to the loan balance upon the closing of the sale of the Wetzel County assets.

In accordance with the First Amendment and Waiver, interest of $3,917,077 for the months of July, August, and September 2015, was added to the principal balance of the loan. In addition, $1,000,000 was added to the principal balance of the loan upon execution of the First Amendment and Waiver. 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.

In accordance with the First Amendment and Waiver, interest of $5,194,760 for the months of October, November and December, 2015, $5,370,581 for the months of January, February, and March, $5,604,715 for the months of April, May and June, and $5,914,048 for the months of July, August, and September 2016 was added to the principal balance of the loan. Effective October 1, 2015, the Company is paying a default interest rate of 17%.

In December 2014, M3 Appalachia Gathering, LLC (“M3”) completed a waterline to improve water supply and lower completion costs, as compared to trucking, with respect to the Company’s wells in Marion County, West Virginia. The Company’s cost of the waterline is approximately $3.1 million, which was being paid to M3 through 36 monthly payments of $105,730, at an internal rate of return to M3 of 15%. On December 1, 2015, the Company assigned the waterline to M3 with an 18 month Call Right at which time the payments would resume. For a period of the earlier of 18 months or termination of the assignment, the Company will pay M3 a water delivery fee of $2.94 per barrel for all water volumes delivered from the waterline. Since it is the intention of the Company to exercise its call right, an asset and liability continues to be recorded. As of September 30, 2016, the Company has recorded a long-term asset of $3.1 million, net of depreciation of $243,522 and a long-term note payable in the amount of $2,439,422.

F-13

The following table summarizes the components of total debt recorded on the Company’s condensed consolidated balance sheets as of September 30, 2016 and December 31, 2015:


	September 30,			December 31,
	2016			2015
	(unaudited)			(audited)
Credit Agreement - Morgan Stanley	$	139,297,776		$	121,493,646
Credit Agreement - Morgan Stanley PIK Fee		1,946,617			1,711,940
Credit Agreement - Morgan Stanley NPI		(535,729	)		(2,142,915	)
M3 Appalachia Gathering LLC Note Payable		2,439,422			2,134,018
Debt issuance costs		(2,037,009	)		(3,550,184	)

Total debt	$	141,111,077		$	119,646,505

The debt balances under the Credit Agreements are presented as short-term liabilities and long-term liabilities on the Company’s condensed consolidated balance sheet as of September 30, 2016 and December 31, 2015, respectively.

As of September 30, 2016, we were not in compliance with our debt covenants of our debt facility with Morgan Stanley.

On May 20, 2016, we notified the Agent that we determined that we were in default under numerous provisions under the Credit Agreement.

The following defaults currently exist under the Credit Agreement:

1. American Shale has failed to maintain the Asset Coverage Ratio as set forth in Section 6.21 of the Credit Agreement since September 30, 2015;

2. American Shale has failed to timely provide the materials required pursuant to Sections 5.06 (r), (u), and (v) for the months ended December 31, 2015, January 31, 2016, February 29, 2016, March 31, 2016, April 30, 2016, May 31, 2016, and June 30, 2016;

3. American Shale has failed to timely effect the sale of the Wetzel County assets in accordance with Section 5.19;

4. American Shale has failed to timely engage a financial advisor reasonably acceptable to Administrative Agent and to commence the related refinancing activities in accordance with Section 5.20;

5. American Shale has failed to timely provide the annual financial statements pursuant to Section 5.06 (a) for the year ended December 31, 2015 and the quarters ended March 31, 2016 and June 30, 2016;

6. American Shale has failed to timely provide the Reserve Report pursuant to Section 5.06 (d) for the year ended December 31, 2015 and the quarters ended March 31, 2016 and June 30, 2016;

7. American Shale has failed to timely provide the Quarterly Report on Hedging pursuant to Section 5.06 (g) for the quarters ended September 30, 2015 December 31, 2015, March 31, 2016, and June 30, 2016.

On August 17, 2016, (“Effective Date”) Trans Energy and American Shale executed an agreement with the Agent for the Lenders under the Credit Agreement. Under the terms of the agreement (the “Forbearance”), the Agent and the Lenders agreed to forbear from taking any enforcement actions with respect to various defaults under the Credit Agreement, provided that (a) no further defaults occur other than those (i) specified in the Forbearance as having already occurred or (ii) anticipated to occur in the future and (b) the Borrower achieves certain milestones with respect to a process to sell certain assets of the Borrower, with such milestones to be agreed upon among the Borrower and the Agent.

F-14

If these defaults under the Credit Agreement are not resolved in the manner contemplated by the Forbearance, the Administrative Agent will have the right to accelerate all of the outstanding indebtedness under the Credit Facility. Debt issuance costs increased due to $743,609 in legal fees and $405,854 in advisory fees, which were paid by the Lender in connection with the Credit agreement and the Forbearance Agreement and were added to the outstanding loan balance in accordance with the terms of the Forbearance Agreement and are included in the condensed consolidated balance sheet as of September 30, 2016.

In addition, the Forbearance provides for a sharing of the proceeds that might result from any such sale process, according to the following formula:

(i)

first, 100% to the Lenders, until the Lenders have received $80,000,000 plus interest from and after the Effective Date, at a rate of 12.00% per annum;

(ii)

second, 78.75% to the Lenders and 21.25% to the Borrower, until the Lenders have the sum of (a) $57,167,819 plus interest from and after the Effective Date at 15.00% per annum and (b) the amount of any fees and expenses payable by the Borrower pursuant to the Credit Agreement that are incurred after the Effective Date plus interest from and after the Effective Date at 15.00% per annum; and thereafter

(iii)

15.00% to the Lenders and 85.00% to the Borrower.

The Lenders have further agreed to re-convey the NPI to the Borrower with respect to any assets that are sold in accordance with the terms of the Forbearance.

The Forbearance further provides that the Borrower has the option to retire all obligations due to the Lenders, including the NPI, for $142,384,848, provided that the Borrower enters into definitive documentation with a third party by November 15, 2016, to finance the repurchase, and that such repurchase occurs by December 31, 2016 (the “Call Option”). Both dates can be extended by thirty days to accommodate regulatory requirements, if necessary. Such amount will increase to the extent that the Lenders incur professional fees after the Effective Date that are payable by the Borrower under the terms of the Credit Agreement. On November 8, 2016, the Borrower sent notice to the Lenders that it intends to exercise the Call Option in connection with the consummation of the Merger Agreement, as discussed more fully in Note 15.

NOTE 8 — DERIVATIVE AND HEDGING FINANCIAL INSTRUMENTS

On May 21, 2014, American Shale, entered into fixed price hedges (“Morgan Stanley Fixed I”), which, when combined with existing hedges covered approximately 90% of its expected natural gas production from PDP wells as of that date. Neither oil nor natural gas liquids have been hedged, but the BTU associated with our ethane production was essentially hedged, since it is sold as part of the natural gas stream. The hedges consist of swaps with strike prices ranging between $4.38 per MMBtu to $4.06 per MMBtu. The hedges begin with the June 2014 contract and end with the December 2018 contract. A total of 13,932,171 MMBtu are hedged over this period, with monthly volumes declining from a high of 444,534 MMBtu in July 2014 to 171,940 MMBtu in November 2018.

On August 20, 2014, American Shale, entered into fixed price hedges (“Morgan Stanley Fixed II”), which, when combined with existing hedges, covered approximately 90% of its expected natural gas production from PDP wells as of that date. Neither oil nor natural gas liquids have been hedged, but the BTU associated with our ethane production was essentially hedged, since it is sold as part of the natural gas stream. The hedges consist of swaps with a fixed strike price of $3.92 per MMBtu. The hedges begin with the September 2014 contract and end with the December 2018 contract. A total of 10,499,038 MMBtu are hedged over this period, with monthly volumes declining from a high of 326,700 MMBtu in January 2015 to 45,854 MMBtu in November 2018.

When the administrative agent consented to the monetization of a portion of American Shale’s natural gas hedges under the April 27, 2015 Consent and Agreement, related to the Credit Agreement, the Fixed I and Fixed II hedge volumes in years 2016 through 2018 were combined (“Morgan Stanley Restrike’). The hedges reflect resetting the strike price from $4.11 and $3.92, respectively, to the then current market price of $3.27. The fair value of these commodity contracts for the hedges volumes in years 2016 through 2018 in total was $1,813,863 and $5,841,395 at September 30, 2016 and December 31, 2015, respectively.

F-15

On December 23, 2014, American Shale, entered into Basis Swap fixed price hedges (“Morgan Stanley Fixed III”) covering approximately 50% of its expected natural gas production from PDP wells as of December 23, 2014. The hedges consist of basis swaps with a fixed strike price of $(1.12) per MMBtu. The hedges begin with the December 2014 contract and end with the December 2018 contract. A total of 7,301,209 MMBtu are hedged over this period, with monthly volumes declining from a high of 266,891 MMBtu in December 2014 to 104,084 MMBtu in November 2018. The fair value of these commodity contracts was $10,292 and $(1,727,720) at September 30, 2016 and December 31, 2015, respectively.

The Company has a master netting agreement on the gas hedges 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. We net our gas hedges separately from our gas basis hedges.

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

The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place for gas hedges and gas basis hedges as of September 30, 2016:


Contract Period Of Morgan Stanley Restrike	Volumes		Weighted- Average Fixed Price
	(MMBtu)		(per MMBtu)
2016		1,251,001	$	3.27
2017		3,248,187	$	3.27
2018		2,542,645	$	3.27

All gas hedges		7,041,833


Contract Period Of Morgan Stanley Fixed III	Volumes		Basis Swap Fixed Price
	(MMBtu)		(per MMBtu)
2016		574,741	$	(1.12	)
2017		1,518,648	$	(1.12	)
2018		1,209,491	$	(1.12	)

All gas basis hedges*		3,302,880

*	Gas basis hedges are based on the difference between TETCO M2 and IF Henry Hub (100%).

F-16

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


	As of September 30, 2016 (unaudited)
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification		Fair Value		Balance Sheet Classification		Fair Value
Commodity derivative		Current assets	$	1,091,835		Current liabilities	$	28,234
Commodity derivative		Noncurrent assets		1,104,800		Noncurrent liabilities		344,246

			$	2,196,635			$	372,480


	As of December 31, 2015
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification		Fair Value		Balance Sheet Classification		Fair Value
Commodity derivative		Current assets	$	3,417,887		Current liabilities	$	474,696
Commodity derivative		Noncurrent assets		2,423,508		Noncurrent liabilities		1,253,024

			$	5,841,395			$	1,727,720

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, 2016 and 2015.


	Three Months Ended September 30, (Unaudited)				Nine Months Ended September 30, (Unaudited)
	2016		2015		2016			2015
Cash settlements on commodity derivatives	$	463,299	$	2,108,934	$	2,992,891		$	14,238,371
Change in fair value of commodity derivatives		1,637,144		813,129		(2,289,520	)		(4,468,047	)

Total contract gains recorded	$	2,100,443	$	2,922,063	$	703,371		$	9,770,324

These gains and losses are recorded in the accompanying unaudited condensed consolidated statements of operations as gain on derivative assets.

Under the terms of each derivative contract, these contracts are in cross-default with the Company’s default on its notes with Morgan Stanley as further discussed in Note 7. Under the terms of the Forbearance Agreement discussed in Note 7, because the affiliate counterparty of the derivative contracts has also agreed to forbear on exercising its rights it is entitled to under default, we believe the classifications disclosed in the condensed consolidated balance sheets is appropriate.

F-17

NOTE 9 — 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 Treasurer and are approved by the President. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, the inputs used in the fair value calculations are updated and management reviews the changes from period to period for reasonableness. The Company has consistently applied the valuation techniques discussed below in all periods presented.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 by level within the fair value hierarchy


	Level 1	Level 2		Level 3	Total
September 30, 2016
ASSETS:
Commodity contracts		$	2,196,635		$	2,196,635
LIABILITIES:
Commodity contracts		$	372,480		$	372,480
December 31, 2015
ASSETS:
Commodity contracts		$	5,841,395		$	5,841,395
LIABILITIES:
Commodity contracts		$	1,727,720		$	1,727,720

We use Level 2 inputs to measure the fair value of gas commodity derivatives. Level 2 assets and liabilities consist of commodity derivative assets and liabilities (See Note 8 - Derivative and Hedging Financial Instruments). The fair value of the commodity derivative assets and liabilities are estimated by the Company using income valuation techniques and a discounted cash flow 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-18

Assets Measured and Recorded at Fair Value on a Non-Recurring Basis

The Company also uses the income valuation technique to estimate the valuation of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money. During the nine months ended September 30, 2016 and 2015, the Company recorded asset retirement obligations of $28,777 and $34,116, respectively. See Note 1 for additional information.

Other financial instruments not measured at fair value on a recurring basis include cash, accounts receivable-trade, accounts receivable due from drilling operator, accounts receivable-related party, advance royalties, prepaid expenses, accounts payable-trade, accounts payable due to operator, accounts payable-related party, accrued expenses, revenue payable, deferred revenue, and the amounts outstanding under the notes payable. With the exception of the notes payable, the financial statement carrying items approximate their fair values due to their short-term nature.

NOTE 10 — STOCKHOLDERS’ DEFICIT

In September 2016, Trans Energy issued 6,957 shares of common stock to Scott Jackson Consulting, LLC, for fees related to services rendered at a value of $1.20 per share.

In September 2016, Trans Energy issued 400,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $1.05 per share.

In August 2016, Trans Energy issued 3,604 shares of common stock to Scott Jackson Consulting, LLC, for fees related to services rendered at a value of $1.11 per share.

In August 2016, Trans Energy issued 50,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $1.11 per share.

In July 2016, Trans Energy issued 5,333 shares of common stock to Scott Jackson Consulting, LLC, for fees related to services rendered at a value of $1.11 per share.

In July 2016, Trans Energy issued 50,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $1.10 per share.

In June 2016, Trans Energy granted 64,300 shares of stock to seven employees and five outside board members under the long-term incentive bonus program. The 64,300 shares are not performance based and vest semi-annually over a three year period. The 64,300 shares were valued at $1.10 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 June 2016, Trans Energy issued 50,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $0.75 per share.

In June 2016, Trans Energy issued 5,334 shares of common stock to Scott Jackson Consulting, LLC, for fees related to services rendered at a value of $0.75 per share.

In May 2016, Trans Energy issued 50,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $1.00 per share.

In May 2016, Trans Energy issued 7,143 shares of common stock to Scott Jackson Consulting, LLC, for fees related to services rendered at a value of $1.12 per share.

In April 2016, Trans Energy issued 50,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $1.00 per share.

In March 2016, Trans Energy issued 50,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $1.00 per share.

In February 2016, Trans Energy issued 50,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $0.41 per share.

In January 2016, Trans Energy issued 25,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $0.45 per share.

F-19

In December 2015, Trans Energy issued 25,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $0.60 per share.

In November 2015, Trans Energy issued 25,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $0.70 per share.

In October 2015, Trans Energy issued 25,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $0.80 per share.

In April 2015, Trans Energy issued 150,000 shares of common stock to Gordian Group, LLC, for fees related to services rendered at a value of $1.80 per share.

In February 2015, Trans Energy issued 100,000 shares of common stock to John G. Corp, President, for the 2014 Performance Payment at a price of $2.10 per share.

In February 2015, Trans Energy issued 100,000 shares of common stock to Stephen P. Lucado, Chairman of the Board, for the 2014 Performance Payment at a price of $2.10 per share.

In January 2015, Trans Energy issued 109,005 shares of common stock to William F. Woodburn, a related party, for the exercise of options at a price of $1.50 per share.

In January 2015, Trans Energy issued 109,005 shares of common stock to Loren E. Bagley, a related party, for the exercise of options at a price of $1.50 per share.

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 and nine months ending September 30, 2016, was determined using the following assumptions:


Expected volatility		90	%
Risk free interest rate		1.75	%
Expected term (years)		3.0
Dividend yield		0	%
Estimated grant date fair value	$	0.35

F-20

As a result of the above stock and option transactions, we recorded total stock-based compensation of $91,124 and $125,027 for the three months ended September 30, 2016 and 2015, respectively and $289,113 and $817,030 for the nine months ended September 30, 2016 and 2015, respectively. This unrecognized cost is expected to be recognized over the next 2.0 years.

Stock option activity is as follows:


	Number of Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Fair Value
Outstanding December 31, 2015		2,137,000		$	2.53		.75 Years	$	5,406,610
Granted		200,000		$	0.60
Exercised		—			—
Forfeited		(169,000	)	$	2.77
Expired		(330,000	)	$	2.68

Outstanding September 30, 2016		1,838,000		$	2.27		1.48 Years	$	4,172,260
Exercisable at September 30, 2016		1,589,500		$	2.46			$	3,814,800
Unvested at September 30, 2016		248,500

NOTE 11 — 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, 2016 and 2015, all potential shares were anti-dilutive and were thus not included in the net loss per share calculation. Potentially dilutive shares consisted of 1,838,000 and 2,360,000 as of September 30, 2016 and September 30, 2015, respectively, and 304,667 and 34,000 shares of unvested restricted common stock as of September 30, 2016 and September 30, 2015, respectively, and 300,000 and 0 in-the-money outstanding options as of September 30, 2016 and September 30, 2015, respectively.

F-21

NOTE 12 — 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		2016	$	2,226,936		$	24,168	$	—		$	2,251,104
		2015	$	2,662,511		$	45,845	$	2,765		$	2,711,121
Income (Loss) from operations		2016		(977,140	)		26,769		(1,678,877	)		(2,629,248	)
		2015		(675,929	)		22,719		(752,871	)		(1,406,081	)
Interest expense		2016		7,449,447			—		43			7,449,490
		2015		6,114,306			—		2,708			6,117,014
Depreciation, depletion, amortization and accretion		2016		1,754,307			167		8,257			1,762,731
		2015		961,880			250		17,436			979,566
Property and equipment acquisitions, including oil and gas properties		2016		512,575			—		13,303			525,878
		2015		(79,082	)		—		—			(79,082	)

	For the Nine Months Ended September 30		Exploration and Production			Pipeline Transmission		Corporate			Total
Revenue		2016	$	7,575,156		$	68,194	$	133		$	7,643,483
		2015	$	10,668,175		$	129,734	$	8,679		$	10,806,588
Income (Loss) from operations		2016		(11,197,480	)		43,674		(3,634,008	)		(14,787,814	)
		2015		(4,207,934	)		74,856		(3,772,411	)		(7,905,489	)
Interest expense		2016		21,469,571			—		2,091			21,471,662
		2015		12,276,046			—		4,448			12,280,494
Depreciation, depletion, amortization and accretion		2016		12,261,293			667		26,875			12,288,835
		2015		5,313,113			750		57,160			5,371,023
Property and equipment acquisitions, including oil and gas properties		2016		(223,820	)		—		13,303			(210,517	)
		2015		114,515			—		5,168			119,683
Total assets, net of intercompany accounts:
September 30, 2016				77,866,823			70,893		—			77,937,716
December 31, 2015				93,265,585			47,322		—			93,312,907

Property and equipment acquisitions include accrued amounts and reclassifications.

F-22

NOTE 13 — RELATED PARTY TRANSACTIONS

During 2015, the Company conducted business with two companies owned by Clarence E. Smith, current shareholder and former officer and director. Work was awarded the companies after bids were sought and reviewed. The amount of payments total $29,450 for 2015.

During 2016 and 2015, the Company conducted business with a company owned by William F. Woodburn, a current shareholder and director. Work related to consulting services performed by Mr. Woodburn for the Company’s joint development with Republic that were billed to the Company. The amount of payments total $46,263 and $84,254 for 2016 and 2015, respectively.

In May 2015, the Company engaged Opportune LLP, a consulting firm specializing in assisting clients across the energy industry, to perform reporting functions for which the Company did not have the staff to complete in the prescribed timeframes. Josh L. Sherman, a member of our board of directors and chairman of our Audit Committee, is a partner in Opportune LLP. The amount of payments total $607,270 for 2015.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

We operate exclusively in the United States, entirely in West Virginia, in the business of oil and gas acquisition, exploration, development, 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.

The Company had gas delivery commitments to Dominion Field Services for Gateway firm nomination up to 800 Dth per day with the receipt/delivery point being Meter #4395501 (ED120). Effective May 1, 2016, Tyler Construction Company, Inc., a subsidiary of the Company (“Assignor”) entered into an assignment and bill of sale of its Gas Pipeline (hereinafter, “Assignment”) with Diversified Gas & Oil Corp. (“Assignee”) whereby the Assignor assigned the pipeline, customers, sales meters and equipment to the Assignee, and the Assignee assumed the Assignor’s obligation to Dominion Field Services, Inc. At closing, the Assignee paid the Assignor the sum of $32,530.

NOTE 15 — SUBSEQUENT EVENTS

The Company has evaluated all subsequent events through the date of issuance.

On October 24, 2016, Trans Energy entered into an Agreement and Plan of Merger (the “Merger Agreement”) with EQT Corporation, a Pennsylvania corporation (“Parent”), and WV Merger Sub, Inc., a Nevada corporation and a wholly owned subsidiary of Parent (“Purchaser”).

Under the terms of the Merger Agreement, Purchaser will commence a tender offer (the “Offer”) to purchase all of the Company’s outstanding shares of common stock, par value $0.001 per share (“Common Stock”), at a purchase price of $3.58 per share, net to seller in cash without interest thereon (the “Offer Price”) and less any required withholding tax. The Offer will expire on the twentieth business day following the commencement of the Offer, unless extended in accordance with the terms of the Offer, the Merger Agreement and the applicable rules and regulations of the Securities and Exchange Commission, provided that the Purchaser shall not be required to extend the expiration date of the Offer beyond December 31, 2016.

The Offer is conditioned upon, among other things, there being validly tendered and not withdrawn prior to the expiration of the Offer the number of shares of Common Stock that, together with shares of Common Stock owned by Parent, Purchaser or any of their respective affiliates, would represent at least a majority of the issued and outstanding Common Stock on a fully diluted basis (the “Minimum Tender Condition”). The Offer is also subject to certain other conditions, including (i) that certain representations and warranties of the Company set forth in the Merger Agreement are true and correct as of the expiration of the Offer; (ii) the consummation of the acquisition by Parent or an affiliate of Parent of certain properties from Republic Energy Ventures, LLC, Republic Partners VI, LP, Republic Partners VII, LLC, Republic Partners VIII, LLC and Republic Energy Operating, LLC (collectively “Republic”) pursuant to that certain Purchase and Sale Agreement dated as of October 24, 2016 (the “Republic Transaction”); (iii) the delivery by Purchaser to Parent of payoff letters from all financial institutions and other persons to which indebtedness under Purchaser’s credit agreement is owed; (iv) the Company shall have complied with in all material respects its obligations under the Merger Agreement; (v) the absence of certain legal impediments; (vi) that no change, circumstance or event has occurred or would reasonably be expected to occur that would have a material adverse effect on the Company; and (vii) other customary closing conditions.

F-23

The Merger Agreement provides, among other things, that following the consummation of the Offer and subject to the terms and conditions set forth in the Merger Agreement, Purchaser will merge with and into the Company (the “Merger”). As a result of the Merger, each issued and outstanding share of Common Stock (other than shares of Common Stock held by Parent, Purchaser or any other subsidiary of Parent, held in the Company’s treasury or by a subsidiary of Company, or held by stockholders who are entitled to assert, and who properly assert, dissenters’ rights) that is not tendered pursuant to the Offer will be converted into the right to receive an amount in cash equal to the Offer Price, less any required withholding tax. Following the effective time of the Merger, the separate corporate existence of Purchaser shall cease, and the Company shall continue as the surviving corporation in the Merger. The closing of the Merger is subject to approval of the Merger by the holders of a majority of the Common Stock if required by the applicable laws of the state of Nevada (“Nevada Law”). The parties have agreed that if, after the purchase of the Common Stock pursuant to the Offer and after giving effect to any shares purchased pursuant to the Top-Up Option (as defined below), Parent, Purchaser or their respective affiliates own at least 90% of the outstanding Common Stock, then, following the satisfaction or waiver of the other conditions to the closing of the Merger, Parent shall execute a “short-form” Merger pursuant to applicable Nevada Law, which will not require the consent of the Company’s stockholders. The Merger is also conditioned upon the absence of certain legal restraints and the acceptance of payment by Purchaser of all the shares of Common Stock validly tendered pursuant to the Offer.

Pursuant to the Merger Agreement, if the Minimum Tender Condition is satisfied but the 90% threshold referred to in the preceding paragraph is not, the Company shall issue to Purchaser, and Purchaser shall purchase (the “Top-Up Option”), at a price per share equal to the Offer Price, up to a number of newly issued, fully paid and nonassessable shares of Common Stock (the “Top-Up Shares”) that, when added to the number of shares of Common Stock owned by Parent, Purchaser or their respective affiliates at the time of the closing of the purchase of Top-Up Shares (after giving effect to the closing of the Offer), shall constitute one share more than 90% (determined on a fully diluted basis) of the shares of the Common Stock outstanding immediately after the issuance of the Top-Up Shares; provided, however, that the Top-Up Option shall not be exercisable (i) if any law or judgment then in effect shall prohibit the exercise of the Top-Up Option or the delivery of the Top-Up Shares and (ii) unless Parent or Purchaser has accepted for payment all shares of the Common Stock validly tendered in the Offer and not withdrawn.

The Company has made customary representations and warranties and covenants in the Merger Agreement, including, among other things, covenants not to solicit alternative transactions or to provide information or enter into discussions in connection with alternative transactions, except with respect to discussions or negotiations with persons related to bona fide, unsolicited written acquisition proposals, and subject to certain limited exceptions to permit the Company’s board of directors to comply with its fiduciary duties.

If, after acceptance for payment by Purchaser of shares of Common Stock pursuant to the Offer, the adoption of the Merger Agreement by the Company’s stockholders is required by law, Parent shall be entitled to designate such number of directors, rounded up to the next whole number, to serve on the Company’s board of directors (the “Company Board”) as will give Purchaser representation on the Company Board equal to the product of (i) the total number of directors on the Company Board (giving effect to such election of any additional directors) and (ii) the percentage that the number of Shares beneficially owned by Parent and/or Purchaser bears to the number of Shares outstanding (the date on which the majority of the Company’s directors are designees of Parent that have been effectively appointed to the Company Board in accordance herewith, the “Board Appointment Date”). The Company is also obligated to cause individuals designated by Parent to constitute the same percentage as is on the entire Company Board to be on (i) each committee of the Company Board of the Company and (ii) each board of directors and each committee thereof of each Company subsidiary. From and after the Board Appointment Date and prior to the Effective Time, any amendment or termination of the Merger Agreement by the Company requiring action by the Company Board, any extension by the Company of the time for the performance of any of the obligations or other acts of Parent or Purchaser under the Merger, or waiver of any of the Company’s rights under the Merger Agreement, in each case, will require the separate concurrence of a majority of the directors on the Company Board that were not appointed by Parent.

The Merger Agreement contains certain termination rights for the Company and Parent, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, the Company will be obliged to pay Parent a termination fee of $4 million.

In connection with the Merger Agreement, Parent and the Company have entered into a Joint Defense and Common Interest Agreement (the “Joint Defense Agreement”) with respect to the following litigation: (i) James K. Abcouwer vs. Trans Energy, Inc. pending in the Circuit Court of Kanawha County, West Virginia (Civil Action No. 12-C-416) before the Honorable Charles E. King, Jr. and (ii) James K. Abcouwer vs. Trans Energy, Inc., a foreign corporation, William F. Woodburn and Loren E. Bagley pending in the Circuit Court of Kanawha County, West Virginia (Civil Action No. 13-C-56) before the Honorable Carrie L. Webster (the “Litigation”). The purpose of the Joint Defense Agreement is to allow the parties to share defense materials with respect to the Litigation prior to the consummation of the Merger.

F-24

Also in connection with the Merger, (i) the Company, American Shale Development, Inc. (“American Shale”), Prima Oil Company, Inc. (“Prima” and, collectively with the Company and American Shale, the “TE Group”); (ii) Republic Energy Ventures, LLC (“REV”), Republic Partners VI, LP (“RP6”), Republic Partners VII, LLC (“RP7”), Republic Partners VIII, LLC (“RP8”), and Republic Energy Operating, LLC (“REO” and, collectively with REV, RP6, RP7 and RP8, the “Republic Group”); and (iii) Parent, EQT Production Company (“Production”), and Purchaser (collectively with Purchaser and Production, the “EQT Group”), entered into a Tri-Party Agreement (the “Tri-Party Agreement”). Members of the TE Group and the Republic Group have had numerous transactions among them over the last several years, including a Farm-Out and Area of Joint Development Agreement (as amended and restated to date, the “AJDA”) and a Joint Operating Agreement (as amended to date, the “JOA”). Pursuant to both the AJDA and the JOA, members of the TE Group had certain rights of first refusal (“ROFR”) and tag-along rights (“Tag”) that would be triggered by the Republic Transaction. In addition, under the AJDA, (a) REV agreed to fund all costs associated with certain leasehold acquisitions made pursuant to the AJDA subsequent to April 1, 2014 (such leasehold acquisitions, the “Subject Properties”), and (b) in the event that REV sold its interest in any such Subject Properties, American Shale has the right to buy a 25% interest in any Subject Property at REV’s cost, plus interest accrued thereon at the rate of 12% per annum (the “Purchase Option”), simultaneously with the consummation of such sale by REV.

Pursuant to the Tri-Party Agreement, the parties agreed that at the closing of the Republic Transaction, in consideration of the payment of approximately $15 million to be made to TE as such closing, the Republic Group would assign to Production all the Subject Properties, including the Option Properties, and the TE Group will waive any and all rights in respect of the Purchase Option. The TE Group also agreed to waive any and all rights to operatorship of the properties subject to the AJDA or the JOA. In addition, the TE Group agreed to waive any and all rights to exercise the ROFR, the Tag or any other rights contained in the AJDA or the JOA in connection with the Republic Transaction. In addition, each of the members of the TE Group and the Republic Group agreed to release each other from any and all past actions and omissions arising under the AJDA, the JOA or any other agreements among the parties that occurred prior to the closings contemplated by the Merger Agreement and the Republic Transaction.

F-25

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 2015 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.

Based on current prices and expected future prices for oil and natural gas for the remainder of 2016 and our capital resources, we have reduced our drilling activity to conserve capital.

Liquidity and Bank Debt

As of March 31, 2016, June 30, 2016, and September 30, 2016, we were not in compliance with our debt covenants with our debt facility with Morgan Stanley.

On May 20, 2016, we notified the Agent that we determined we were in default under numerous provisions under the Credit Agreement. The following defaults currently exist under the Credit Agreement:

1. American Shale has failed to maintain the Asset Coverage Ratio as set forth in Section 6.21 of the Credit Agreement since September 30, 2015;

3. American Shale has failed to timely effect the Wetzel County disposition in accordance with Section 5.19;

4. American Shale has failed to timely engage a financial advisor reasonably acceptable to Administrative Agent and to commence the related refinancing activities in accordance with Section 5.20;

6. American Shale has failed to timely provide the Reserve Report pursuant to Section 5.06 (d) for the year ended December 31, 2015 and the quarters ended March 31, 2016 and June 30, 2016;

On August 17, 2016, (“Effective Date”) Trans Energy and American Shale executed an agreement with the Agent for the Lenders under the Credit Agreement, as amended. Under the terms of the agreement (the “Forbearance”), the Agent and the Lenders agreed to forbear from taking any enforcement actions with respect to various defaults under the Credit Agreement, provided that (a) no further defaults occur other than those (i) specified in the Forbearance as having already occurred or (ii) anticipated to occur in the future and (b) the Borrower achieves certain milestones with respect to a process to sell certain assets of the Borrower, with such milestones to be agreed upon among the Borrower and the Agent.

In addition, the Forbearance provides for a sharing of the proceeds that might result from any such sale process, according to the following formula:

(i)

first, 100% to the Lenders, until the Lenders have received $80,000,000 plus interest from and after the Effective Date, at a rate of 12.00% per annum;

(ii)

(iii)

15.00% to the Lenders and 85.00% to the Borrower.

The Lenders have further agreed to re-convey the NPI to the Borrower with respect to any assets that are sold in accordance with the terms of the Forbearance.

The Forbearance further provides that the Borrower has the option to retire all obligations due to the Lenders, including the NPI, for $142,384,848, provided that the Borrower enters into definitive documentation with a third party by November 15, 2016 to finance the repurchase, and that such repurchase occurs by December 31, 2016 (the “Call Option”). Both dates can be extended by thirty days to accommodate regulatory requirements, if necessary. Such amount will increase to the extent that the Lenders incur professional fees after the Effective Date that are payable by the Borrower under the terms of the Credit Agreement. On November 8, 2016, the Borrower sent notice to the Lenders that it intends to exercise the Call Option in connection with the consummation of the Merger Agreement, as discussed more fully in Note 15.

Subsequent Merger Agreement

See Note 15 to the condensed consolidated financial statements for a full discussion.

Results of Operations

Three months ended September 30, 2016 compared to September 30, 2015

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, 2016 and 2015.


	Three months ended September 30,
	2016			2015
Total operating revenues	$	2,251,104		$	2,711,121
Total operating costs and expenses		(4,880,352	)		(4,117,202	)

Loss from operations		(2,629,248	)		(1,406,081	)
Other expenses, net		(5,348,504	)		(3,194,395	)
Income tax		—			—

Net loss	$	(7,977,752	)	$	(4,600,476	)

The following table is a summary of revenues, volumes, and pricing for the three months ended September 30, 2016 and 2015.

Three Months Ended September 30, 2016 compared to the Three Months Ended September 30, 2015


	Three Months Ended
	September 30,				Increase/
	2016		2015		(Decrease)
Natural gas sales	$	1,706,260	$	2,224,421	$	(518,161	)	-23.3	%
Oil sales	$	4,925	$	4,082	$	843		2.1	%
Natural gas liquid sales	$	503,720	$	434,008	$	69,712		16.1	%

Total oil & gas sales	$	2,214,905	$	2,662,511	$	(447,606	)	-16.8	%
Transportation and other revenue	$	36,199	$	48,610	$	(12,412	)	-25.5	%

Total revenue	$	2,251,104	$	2,711,121	$	(460,017	)	-17.0	%
Net Production
Natural gas sales (MCF)		1,024,883		1,777,188		(752,305	)	-42.3	%
Oil sales (Bbls)		166		214		(48	)	-22.4	%
Natural gas liquids (gallons)		2,450,463		3,215,419		(764,956	)	-23.8	%
Natural Gas Equivalent ( MCFe)		1,375,946		2,237,818		(861,875	)	-38.5	%
Average Sales Price per Unit
Natural Gas (MCF)	$	1.66	$	1.25	$	0.41		32.8	%
Oil (Bbl)	$	29.67	$	19.07	$	10.6		55.6	%
Natural gas liquids (gallons)	$	0.21	$	0.13	$	0.08		61.5	%
Natural Gas Equivalent (MCFe)	$	1.61	$	1.19	$	0.42		35.3	%

Expenses

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


	Three Months Ended September 30,
	2016		2015
Costs and expenses of production:
Production expenses	$	1,314,593	$	2,120,475
Production taxes		127,233		261,524
G&A expenses (excluding share-based compensation)		1,587,754		630,610
Non-cash share-based compensation		91,124		125,027
Depletion of oil and natural gas properties		1,719,830		1,898,095
Depreciation and amortization		40,187		(920,932	)
Accretion of discount on asset retirement obligation		2,714		2,403
Costs and expenses per MCFE of production:
Production expenses		0.96		0.95
Production taxes		0.09		0.12
G&A expenses (excluding share-based compensation)		1.15		0.28
Non-cash share-based compensation		0.07		0.06
Depletion of oil and natural gas properties		1.25		0.85
Depreciation and amortization		0.03		(0.41	)
Accretion of discount on asset retirement obligation		—		—

Total revenues decreased for the three months ended September 30, 2016 as compared to the same period for 2015 primarily due to a decrease in natural gas, oil and NGL volumes which was offset in part by an increase in natural gas, oil, and (NGL) prices.

Production costs decreased $940,173 or 39% for the three months ended September 30, 2016 as compared to the same period for 2015, primarily due to a decrease in volumes as well as a credit being issued by Williams Ohio Valley Midstream LLC which reduces our processing and gathering fees related to our NGL production. The credit became effective in May 2016 to offset the decline in market prices. In addition, in July 2016, the state of West Virginia eliminated the additional severance tax paid on production under the Workers’ Compensation Debt Reduction Act of 2005.

Depreciation, depletion, amortization and accretion expense increased by $783,165 or 80% for the three months ended September 30, 2016 compared to the same period for 2015, primarily because no depletion was recorded on assets held for sale in 2015. These assets were moved to proved properties during 2016 which resulted in additional depletion expense.

General and administrative expense increased $923,241 or 122% for the three months ended September 30, 2016 as compared to the same period for 2015, primarily due to an increase in legal and professional fees incurred in connection with the Forbearance and the Merger Agreement.

Interest expense increased $1,332,476 or 22% for the three months ended September 30, 2016 as compared to the same period for 2015 due to a higher balance on the Morgan Stanley loan. Stated interest rate was 13% if paid in cash and 15% if paid in kind on the Morgan Stanley loan after July 31, 2015 compared to 10% paid in cash prior to that date. Effective October 1, 2015, the Company is paying a default interest rate of 17%. For the three months ended September 30, 2016 the average loan balance was $138,488,049 compared to $114,905,089 for the same period in 2015.

Gain on commodity derivative for the three months ended September 30, 2016 was $2,100,443 as compared to a gain of $2,922,063 for the same period last year.

Net loss for the three months ended September 30, 2016 was $7,977,752 compared to a net loss of $4,600,476 for the same period of 2015. The increase in net loss is due primarily to a decrease in revenue, an increase in depletion expense, an increase in interest expense, and an increase in general and administrative expenses.

Nine months ended September 30, 2016 compared to September 30, 2015

The following table sets forth the relationship of total revenues of principal items contained in our Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30, 2016 and 2015.


	Nine months ended September 30,
	2016			2015
Total operating revenues	$	7,643,483		$	10,806,588
Total operating costs and expenses		(22,431,297	)		(18,712,077	)

Loss from operations		(14,787,814	)		(7,905,489	)
Other expenses, net		(20,766,641	)		(2,508,533	)
Income tax		—			—

Net loss	$	(35,554,455	)	$	(10,414,022	)

The following table is a summary of revenues, volumes, and pricing for the nine months ended September 30, 2016 and 2015.

Nine Months Ended September 30, 2016 compared to the Nine Months Ended September 30, 2015


	Nine Months Ended
	September 30,				Increase/
	2016		2015		(Decrease)
Natural gas sales	$	6,043,170	$	9,073,049	$	(3,029,879	)	-33.4	%
Oil sales	$	26,586	$	31,343	$	(4,757	)	-15.2	%
Natural gas liquid sales	$	1,493,368	$	1,563,783	$	(70,415	)	-4.5	%

Total oil & gas sales	$	7,563,124	$	10,668,175	$	(3,105,051	)	-29.1	%
Transportation and other revenue	$	80,359	$	138,413	$	(58,054	)	-41.9	%

Total revenue	$	7,643,483	$	10,806,588	$	(3,163,105	)	-29,3	%
Net Production
Natural gas sales (MCF)		4,111,756		5,614,926		(1,503,170	)	-26.8	%
Oil sales (Bbls)		1,164		816		348		42.7	%
Natural gas liquids (gallons)		8,666,191		6,406,777		2,259,414		35.3	%
Natural Gas Equivalent (MCFe)		5,356,768		6,535,079		(1,178,311	)	-18.0	%
Average Sales Price per Unit
Natural Gas (MCF)	$	1.47	$	1.62	$	(0.15	)	-0.9	%
Oil (Bbl)	$	22.84	$	38.39	$	(15.55	)	-40.5	%
Natural gas liquids (gallons)	$	0.17	$	0.24	$	(0.07	)	-29.2	%
Natural Gas Equivalent (MCFe)	$	1.41	$	1.63	$	(0.22	)	-13.5	%

Expenses

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


	Nine Months Ended September 30,
	2016		2015
Costs and expenses of production:
Production expenses	$	6,123,862	$	8,587,441
Production taxes		632,542		972,522
G&A expenses (excluding share-based compensation)		3,230,028		2,964,060
Non-cash share-based compensation		289,113		817,031
Depletion of oil and natural gas properties		12,157,663		6,162,284
Depreciation and amortization		122,833		(796,759	)
Accretion of discount on asset retirement obligation		8,339		5,498
Costs and expenses per MCFE of production:
Production expenses		1.14		1.31
Production taxes		0.12		0.15
G&A expenses (excluding share-based compensation)		0.60		0.52
Non-cash share-based compensation		0.05		0.06
Depletion of oil and natural gas properties		2.27		0.94
Depreciation and amortization		0.02		(0.12	)
Accretion of discount on asset retirement obligation		—		—

Total revenues decreased primarily due to a decrease in natural gas, oil, and natural gas liquid (NGL) prices for the nine months ended September 30, 2016 as compared to the same period in 2015 compounded further by a decline in natural gas production.

Production costs decreased $2,803,559 or 29% for the nine months ended September 30, 2016 as compared to the same period for 2015, primarily due to a decrease in volumes as well as a credit being issued by Williams Ohio Valley Midstream LLC which reduces our process and gathering fees related to our NGL production. The credit became effective in May 2016 to offset the decline in market prices. In addition, in July 2016, the state of West Virginia eliminated the additional severance tax paid on production under the Workers’ Compensation Debt Reduction Act of 2005.

Depreciation, depletion, amortization and accretion expense increased by $6,917,812 or 129% for the nine months ended September 30, 2016 compared to the same period for 2015, primarily because no depletion was recorded on assets held for sale in 2015. These assets were moved to proved properties during the first quarter of 2016 which resulted in additional depletion expense in the first quarter of $4,372,965.

General and administrative expense decreased $261,950 or 7% for the nine months ended September 30, 2016 as compared to the same period for 2015, primarily due to an increase in legal and professional fees that was offset by a decrease in administrative salaries and a reduction in non-cash share based compensation.

Interest expense increased $9,191,168 or 75% for the nine months ended September 30, 2016 as compared to the same period for 2015 primarily due to $16,889,343 of interest expense from the American Shale note. The Morgan Stanley stated interest rate remained at 10% until July 31, 2015, after which the stated interest rate was 13% if paid in cash and 15% if paid in kind. Effective October 1, 2015, the Company is paying a default interest rate of 17%. For the nine months ended September 30, 2016 the average loan balance was $132,504,370 compared to $113,697,530 for the same period in 2015.

Gain on commodity derivative for the nine months ended September 30, 2016 was $703,371, compared to a gain of $9,770,324 in 2015. This represents the decrease in the fair value of our gas hedges.

Net loss for the nine months ended September 30, 2016 was $35,554,455 compared to a net loss of $10,414,022 for the same period of 2015. This decrease in net loss is due primarily to a decrease in revenue, an increase in interest expense and decrease in the gain on commodity derivatives.

Liquidity and Capital Resources

Historically, we have satisfied our working capital needs with borrowed funds and the proceeds of acreage sales. At September 30, 2016, we had negative working capital of $138,306,055 compared to negative working capital of $116,988,273 at December 31, 2015. The decrease in working capital is primarily due to the fact that interest has been added to the principal balance of our notes payable in 2016.

During the first nine months of 2016, net cash used by operating activities was $444,595 compared to $2,175,834 of net cash used for the same period of 2015. This increase in cash flow from operations was primarily due to the net loss in 2016, increase in accounts receivable, and decrease in accrued expenses offset by increase in depreciation, depletion and amortization and interest and legal expense added to principal.

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 2016, net cash provided by investing activities was $360,517 compared to net cash used of $119,683 in the same period in 2015. The change was primarily due to a change in ownership percentage due to unitization of various leases, as well as a reduction in capital spending in 2016 compared to 2015.

During the first nine months of 2016, there was no cash activity from financing activities compared to net cash provided of $1,144,485 for the same period in 2015. This change was primarily due to an increase in debt to M3 Appalachia Gathering LLC and the issuance of stock in connection with the exercise of options in 2015.

As of November 10, 2016, the cash balance of the Company amounted to approximately $15.4 million and the Company continues to face significant liquidity constraints in the short term. Under the terms of the Forbearance, the Company is limited on normal business decisions as all transactions must be approved by the debtholder. There is a substantial doubt about the ability of the Company to continue as a going concern. On October 24, 2016, the Company entered into a Merger Agreement with EQT Corporation and WV Merger Sub, Inc., as discussed in Note 15 to the Company’s financial statements. If the transactions contemplated therein are consummated in accordance with their terms, the Company will become a wholly owned subsidiary of EQT Corporation and will cease filing reports with the SEC.

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, 2015.

Forward-looking and Cautionary Statements

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

•

the sufficiency of existing capital resources and our ability to raise additional capital to fund cash requirements for future operations;

•

uncertainties involved in the rate of growth of our business and acceptance of any products or services;

•

success of our drilling activities;

•

volatility of the stock market, particularly within the energy sector;

•

the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2015; and

•

general economic conditions.

Although we believe the expectations reflected in these forward-looking statements are reasonable, such expectations cannot guarantee future results, levels of activity, performance or achievements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Not Applicable.

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 principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the assessment, our management has concluded that our internal control over financial reporting was ineffective as of September 30, 2016 due to insufficient financial reporting resources. The results of management’s assessment were reviewed with our Board of Directors. To remediate these issues, our management has retained the services of additional third party consulting personnel and will modify existing internal controls in a manner designed to ensure compliance.

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. vs. 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. On November 26, 2012, the Court granted our motion for summary judgment and on February 25, 2014, the United States Court of Appeals for the Fourth Circuit in Richmond Virginia affirmed the summary judgment. The defendant’s time to appeal this judgment has passed, so this judgment in our favor is final.

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

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

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. This case went to trial beginning May 9, 2016, and the jury began deliberations on May 13, 2016. On May 16, 2016, the jury ended deliberations without reaching a unanimous verdict. Accordingly, the judge declared a mistrial. While Abcouwer originally sought punitive damages in his complaint, the claims for punitive damages were not submitted to the jury for consideration. At this point it is unclear whether Abcouwer will seek a new trial in this case.

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. In addition, the Company alleges that Abcouwer made misrepresentations to Trans Energy concerning the extension of a maturity date of a credit facility with CIT Capital USA Inc. (“CIT”) which caused the Company damages. Trial is currently set to begin in December 2016.

Item 1A. Risk Factors

None

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