Whipkey Drilling Pad, Marshall County, West Virginia DUG EAST JUNE 5, 2014 1
Disclaimer This presentation contains forward-looking statements within the meaning of section 21E of the United States Securities Exchange Act of 1934, as amended (the Exchange Act ) which represent our expectations or beliefs about future events. These statements can be identified generally by forward-looking words such as expect, believe, anticipate, plan, intend, estimate, may, will or similar words. Forward-looking statements are statements about the future and are inherently uncertain, and our actual achievements or other future events or conditions may differ materially from those reflected in the forward-looking statements due to a variety of risks, uncertainties and other factors, including, without limitation, those described in Item 1A of the company s annual report on form 10-K for the year ended December 31, 2013 under the heading, Risk Factors, and elsewhere in the annual report and our filings with the Securities and Exchange Commission. These risks and uncertainties include, but are not limited to: 1. The risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas; 2. market demand; 3. risks and uncertainties involving geology of oil and gas deposits; 4. the uncertainty of reserves estimates and reserves life; 5. the uncertainty of estimates and projections relating to production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; 6. fluctuations in oil and gas prices, foreign currency exchange rates and interest rates; 7. health, safety and environmental risks; 8. uncertainties as to the availability and cost of financing; 9. the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; 10. other sections of this presentation may include additional factors that could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. Our forward-looking statements contained in this presentation are made as of the respective dates set forth in this presentation. Such forward-looking statements are based on the beliefs, expectations and opinions of management as of the date the statements are made. We do not intend to update these forward-looking statements. For the reasons set forth above, investors should not place undue reliance on forward-looking statements. Readers are encouraged to read our December 31, 2013 Annual Report on Form 10-K and any and all of our other documents filed with the SEC regarding information about Trans Energy, Inc. for meaningful cautionary language in respect of the forward-looking statements herein. Interested persons are able to obtain copies of filings containing information about Trans Energy, Inc., without charge, at the SEC s internet site (http://www.sec.gov). 2
About Trans Energy Company Overview Area of Operation Trans Energy: (OTCQB: TENG) Pure Play Marcellus Shale PD Reserves: 48.0 Bcfe (12/31/2014 Wright & Co. Estimates - Marcellus only) Recent Daily Production: 16,700 Mcfe 52-Week Range: $2.50 - $4.25 3-Month Avg. Daily Volume 4,548 Shares Shares Outstanding: 13.6 Million Market Capitalization: $56.1 million Experienced Management Team Selected Financial Information 12/31/2013 (est.) LTM Revenue $18.4 million Net Debt (as of 5/30/14) $102.3 million Recent Stock Price (TENG) $4.12 Shares Outstanding (5/23/2014) 13.6 million Market Capitalization $56.1 million Enterprise Value $158.4 million 3
Why Invest in Trans Energy? Marcellus Shale pure play Predictable and repeatable inventory Prominent land position with strong upside potential Marshall Wetzel Monongalia Trades at a significant discount to NAV Tyler Marion Experienced Management Team Pleasants Doddridge Harrison Taylor Ritchie WET GAS DRY GAS Marcellus Shale Pure Play Over 45,000 gross acres in core of the Marcellus Shale Utica Shale potential Upper Devonian upside potential High-BTU, liquid-rich focus <$1.50 per MMBtu breakeven gas price on recent wells Extensive Organic Drilling Inventory 400/500 + potential drilling locations (204/307 drillable today) (1) 3+ Tcfe gross upside potential (including JV & royalty partners) Significant portion of acreage HBP (approx. 55%) Off-take agreements totaling more than 45,000 MMBtu per day Production Growing Current daily production up 20% vs. same time prior year Current daily production does not include two Beatty wells Experienced Management w/ Technical Expertise More than 200 years combined management experience Well-funded joint development partner has geologic / engineering team (1) At 750 ft / 500 ft spacing 4
Marcellus Overview Majority of Company acreage located in wet gas window NGL yields in the 1.1 1.9 gallons per mcf range Ft. Beeler processing plants provide 320 MMcf/day throughput capacity Williams is adding another 640 MMcf/day of processing to this system Condensate and NGLs provide $1.00 - $2.00 pricing uplift vs. dry gas Breakeven natural gas price on new wells <$1.50 per MMBtu (with NGLs @ 45% WTI price) Wet Gas Dry Gas Trans Energy Area of Operation Low-cost, highly predictable and repeatable play In Trans Energy s area of operation, the Marcellus shale is approximately 50 100 feet thick 5
Gas Off-Take (Williams & Momentum 3) 20-year gas gathering agreement with Williams for up to 45,000 MMBTU / day 90,000 MMBTU / day including Republic capacity Williams committed to provide offtake for all wells to be drilled (1) Access to the TETCO, Columbia and Dominion lines Marshall and Wetzel County wells feed into TETCO Ft. Beeler cryogenic processing facility started up in 2Q 2011 NGL yields up to 1.1 1.9 gal/mcf Second facility started Moundsville fractionation plant online since November 2012 Momentum 3 will gather and provide transportation in Marion County for all of our volumes (1) Based on acreage dedication; Excludes Marion County 6
Corporate Strategy - Prove Acreage / Add Drillable Locations Consolidate acreage surrounding legacy positions in the core of the Marcellus Marshall, Wetzel and Marion counties Building upon local presence a West Virginia company Drill to turn highly prospective acreage into 3P reserves Secure and maintain land position via leasehold rights Grow production and reserves / monetize assets 7
Competitive Market Position 8
Acreage Wellbores There is no forced pooling in West Virginia Acreage has value, drillable pad sites have (much) more value. Four criteria four a drillable wellbore: Defensible title on 100% of the underlying acreage Topography supports a pad site Hillside drilling Wetlands, etc. Mining Minimum wellbore length Minimum number of wellbores We can drill over 300 wellbores today at 500 spacing 9
Current Marcellus Acreage Significant Marcellus acreage that is held by shallow well production Acreage Breakdown 18,733 Net acres Approximately 300 horizontal well locations from HBP acreage alone 942 ac. Primary term leased acreage can generally be held by production from shallow vertical or Marcellus horizontal wells 8,312 ac. Leased-Termed Held By Production Current drilling program supplemented with selective shallow drilling will HBP all strategic acreage with near term lease expirations over the next two years 9,478 ac. Mineral Rights Purchased Significant amount of acreage is also prospective for the Utica shale and Upper Devonian formations 10
Overview of Recent Debt Refinancing On May 21, 2014, ASD closed on a new $200 mm financing Morgan Stanley advanced $102.5 mm at closing Initial advance repaid all debt to previous lender Additional contingent commitment of $47.5 mm available based on PDP PV9 / Net Debt Additional $50 mm available at Morgan Stanley s discretion Interest on grid initially at 10%, with stepdowns to 7.0% NPI of 6.5% of equity value granted at closing; Maximum NPI of 9.0% upon full drawdown of contingent commitment Contingent commitment intended to fund 2 rig drilling program Republic Energy (JV partner) funding $15 mm of CAPEX plus all acreage purchases in exchange for undeveloped leasehold and ORRI ($6,700/ac) ASD can repay the $15 mm within 6 months and reverse the acreage and most ORRI Upon demonstration of funding for acreage, ASD will fund 50% of acreage purchases on a go-forward basis Backend interest in 25% of all acreage purchased prior to termination by ASD See the Form 8-K filing dated May 23, 2014 for more details regarding the refinancing 11
Reserves and Resources (Internal 12/31/13) Trans Energy has exposure to more than 3 Tcfe of Marcellus resource potential More than 400/500 potential drilling locations (204/307 ready to drill today) (3) EUR per well of 1.4 2.9 Bcfe /1000 of lateral (Est. Reserves as of 12/31/13) 12/31/13 Internal Reserve Summary (1) Oil Gas NGL Total % of (MMBbl) (Bcf) (MMBbl) (Bcfe) Total Total PV10% PDP/PDNP 0.019 42.672 0.896 48.161 100.00% $160.1 $69.2 Total Proved 0.019 42.672 0.896 48.161 $160.1 $69.2 (2) PROBABLE 0.191 514.980 11.563 585.503 $1,434.5 $307.1 POSSIBLE 0.000 17.387 0.204 18.611 $48.5 $12.2 Reserve Mix (1) Reserve Category Mix (1) Oil Gas NGL Prob/Poss PDP/PDNP (1) Based on reserve estimates for ASD from the 12/31/2013 reserve report prepared by independent reserve engineer Wright & Company, Inc. (12/31/2013 NYMEX pricing) (2) Approximately 45% of the Probable Reserves shown above have been designated as such due to the SEC 5-year rule. (3) At 750 ft / 500 ft spacing 12
Wet Gas Provides Positive Economics $4.50 NYMEX Equals $5.21/MCF Wellhead Price $4.50 / MMBTU NYMEX Henry Hub $95 NYMEX WTI One mcf Natural Gas via Wellhead Production Natural Gas Natural Gas Liquids Condensate Production Breakdown.88 MCF 1.2 Gallons/MCF.00212 BBLS/MCF Gross Realized Price by Product Total Realized Price per 1 MCF Gathering, Transportation and Processing Net Realized Price per 1 MCF $3.94 net (1)(2) $1.10 net (3)(4)(5) $0.17 net (6) $5.21/MCF ($0.75/MCF) $4.46/MCF 1. $0.50 discount to NYMEX Henry Hub 2. 1.119 MMBTU/mcf residue BTU factor 3. 45% NYMEX WTI per NGLs 4. 42 gal/bbl conversion factor 5. 90% NGLs 6. WTI less $15.00 for Appalachian Light Sweet 13
Experienced Management Team Steve Lucado Chairman of the Board John Corp President & Director John Tumis Chief Financial Officer Director since 2011 More than 19 years professional financial experience, including E&P CFO experience Bachelor of Arts Degree Harvard University, MBA, University of Chicago Director since 2005 and President since June 2010 More than 25 years drilling, production and operations experience Received a Bachelor of Science Degree in Petroleum Engineering from Marietta College Chief Financial Officer of Trans Energy since April 2011 More than 25 years experience in financial and strategic business planning in the oil and natural gas industry Received a Bachelor of Science Degree from Ohio Northern University and is a certified public accountant Leslie Gearhart Vice President of Operations & General Secretary Vice President of Operations and General Secretary Has more than 25 years of experience in the oil and gas industry in the Appalachian Basin Graduated with a Bachelor of Science Degree in Petroleum Engineering from Marietta College 14
Joint Development Partner: Republic Energy Republic is a privately held Dallas-based E&P company Technical team has 200+ years combined industry experience Former VP Geology and Head of Completion Operations for North Texas from Mitchell Energy Corporation Mitchell was the cutting edge Barnett player wrote the book on shale fracing Republic focused on assets in the JV with Trans Energy 100% of Trans Energy s Marcellus assets in the JV JV agreement requires mutual consent to drill >6 wells/year Equity financing from Energy Trust Partners (an affiliate of Energy Spectrum) and Wells Fargo 15
IRR Type Curve IRR Sensitivities By County IRR vs. Price of Gas Marshall Wetzel Marion 80% 70% 60% 50% Projected Horizontal Well Reserves Per Well: 9.75 Bcfe, 11.0 Bcfe, 11.5 Bcfe CAPEX per 5,000 : $7.27 mm, $7.43 mm, $7.72 mm Percent Liquids: 20%, 20%, 0% WTI Price/bbl: $95 NGL price/bbl: 45% WTI Lateral Length: 5,000 ft 40% 30% 20% 10% 0% $2.50 $3.50 $4.50 NG Price ($/mmbtu) 16
Marshall County JV has 11,265 gross acres of leased and owned minerals (5,059 net to ASD) 15 wells online Average 30-day IP of 4.4 MMcfe/d (1) / 6.0 MMcfe/d (2) 20% Liquids (excl. ethane) Average lateral length 4,100 (1) / 3,420 (2) Average EUR / 1000 lateral of 1.90 Bcfe (1) / 2.22 Bcfe (2) 4.5 Frac Stages/1000' lateral Drill time of 35 days spud to rig release Total Potential Wells: > 175 Wells Drillable Today: 54 / 85 (3) 3 wells recently turned into sales 4 wells planned for drilling in 2014 (1) Excludes Whipkey 1H, Doman 1H, Doman 2H, Goshorn 3H, Goshorn 4H and Martinez 1H (2) Includes Doman 1H and Doman 2H (3) At 750 ft / 500 ft spacing 17
Wetzel County JV has 15,339 gross acres of leased and owned minerals (6,162 net to ASD) 5 wells online Average 30-day IP of 8.1 MMcfe/d (1) 20% liquids (excl. ethane) 5,000 Average lateral length (1) v Average EUR / 1000 lateral (1) of 2.27 Bcfe 4.5 Frac Stages/1000' lateral Drill time of 35 days spud to rig release Total Potential Wells: > 200 Wells Drillable Today: 88 / 128 (2) 6 wells planned for drilling in 2014 (1) Excludes Hart 28H (2) At 750 ft / 500 ft spacing 18
Marion County JV has 19,673 gross acres of leased and owned minerals (7,512 net to ASD) Marion County Marcellus gains thickness relative to Wetzel BTU between 1050 and 1100 Marshall Total Potential Wells: ~200 Wetzel Monongalia Total Wells Drillable Today: 62 / 94 (1) 4 wells recently turned into sales Tyler Marion 9 wells planned for drilling in 2014 Doddridge Harrison (1) At 750 ft / 500 ft spacing 19
Drilling Program Recap 24 Hz wells online 2013 drilling program included 8 wells 2014 drilling program includes drilling 19 wells, of which 15 are expected to be completed by year end Completed (Online): Anderson 5H, 7H Beatty 1H, 2H Dewhurst 110H, 111H Doman 1H, 2H Freeland 1H, 2H Goshorn 1H, 2H, 3H, 4H Groves 1H Hart 28H Keaton 1H Lucey 1H, 2H Martinez 1H Stout 2H Whipkey 1H, 2H, 3H Marshall Completed (Resting): Woodruff 1H, 2H Blackshere 200H, 201H Drilled, waiting on Frac: Jones 2H, 3H Wetzel Monongalia Scheduled to Drill: Anderson 8H, 9H Sivert 1H, 2H Dewhurst 300H, 301H, 400H, 401H Shaver 1H, 2H Michaels 1H, 2H Wright 1H, 2H Tyler Marion Pleasants Harrison Ritchie Doddridge 20
Average Production, MCF IP Rates - Recent Marcellus Completions Incremental 30 Day Average Production/ 1000' Lateral 30 60 90 120 2,500 2,000 1,500 1,000 500 0 Hart 28H Whipkey 1H Whipkey 2H Stout 2H Keaton 1H Groves 1H Lucey 1H Whipkey 3H Lucey 2H Goshorn 1H Goshorn 2H Anderson 5H Anderson 7H Dewhurst 110H Dewhurst 111H Doman 1H Doman 2H Martinez 1H Freeland 2H Freeland 1H Goshorn 3H Goshorn 4H Note: The Martinez 1H and the Freeland 1H, 2H were under significant flow restrictions due to pipeline constraints. The Goshorn 3H reflects actual results; Over half of the wellbore is believed to be shut off due to completion issues. 21
Mcfe/d Bcfe West Virginia Peer Well Performance TENG is drilling some of the best wells in the wet gas window of the Marcellus 30-Day IP Rates per 1,000 Lateral (1) EUR per 1,000 Lateral (1) 2,500 2.50 2,000 2.00 1,500 1.50 1,000 1.00 500 0.50 - (2) (3) (4) - (4) 1. Peer data compiled and estimated from public investor materials by EnerCom, Inc.. Peer Group includes: Antero Resources, EQT, Gastar and Magnum Hunter. 2. Based on the Freeland #2H 3. Based on the Doman 1H, 2H and Martinez #1H (Note: well was choked back due to constraints imposed at the pipeline interconnect) 4. Excludes Hart 28H 22
Mcfe/d Comparative Well Performance 90-Day IP Rates per 1,000 Lateral (1) 2,500 2,000 TENG Wells Rice Energy Avg. 6/12 - IPO TENG Wells Turned In to Sales from 6/12-12/13 Using New Completion Techniques 1,500 1,000 500-1. Rice Energy data from IPO Prospectus. 2. Martinez 1H and Freeland 2H were restricted due to pipeline constraints. Data represents first 90 days for Freeland 2H; It was further restricted after first 60 days. 23
Trading At a Significant Discount to Net Asset Value (NAV) NAV based on PDP PV10, PV40 of drillable locations plus other acreage $20.00 $18.00 $16.00 $4.10 $2.90 $14.00 $12.00 $10.00 $11.32 $(5.67) $(0.80) $11.84 $8.00 $6.00 $4.00 $4.12 Unrealized Value $2.00 $0.00 Share Price (5/30/14) Wells Drillable Today (PV40) PDP PV10 Value Other Acreage less Net Debt (5/30/14) less NPI Value per TENG Share See Appendix for the assumptions behind the per share calculations shown above 24
Why Invest in Trans Energy? Marcellus Shale Pure Play Over 45,000 gross acres in core of the Marcellus Shale Utica Shale potential Upper Devonian upside potential High-BTU, liquid-rich focus <$1.50 per MMBtu breakeven natural gas price on recent wells Extensive Organic Drilling Inventory w/ Large Acreage Position 400/500 + potential drilling locations (1) 3+ Tcfe upside potential (including JV and royalty partners) Significant portion of acreage HBP (approx. 55%) Off-take agreements totaling over 45,000 MMBtu per day Production Growing Current daily production up 20% vs. same time prior year Current daily production does not include two Beatty wells Experienced Management w/ Technical Expertise More than 200 years combined management experience Well-funded joint development partner has geologic / engineering team (1) At 750 ft / 500 ft spacing 25
A P P E N D I X Doman Drilling Pad, Marshall County, West Virginia 26
Detailed NAV Assumptions Using 750 and 500 Spacing NAV based on PDP PV10, PV40 of drillable locations plus other acreage EUR Assumption Spacing (ft) 750 Avg. 2.15 Bcfe/1000 feet of lateral, $4.50 Pricing 500 Number of Wellbores 204 307 PV20/Wellbore ($mm) $5.5 $5.5 PV20 (Total) ($mm) $1,115.8 $1,679.2 PV40/Wellbore ($mm) $2.0 $2.0 PV40 (Total) ($mm) $417.2 $627.8 % net to ASD 46% 46% Total Value to ASD of Wells Drillable Today (PV40) ($mm) $192.4 $289.6 PDP PV10 Value (Strip, $mm) $69.2 $69.2 Total Reserve Value ($mm) $261.6 $358.8 % of Acreage Represented by Wells Drilled + Drillable Today 49% 47% Total Net Acreage 18,733 18,733 Acreage NOT Represented by Wells Drilled + Drillable Today 9,621 9,926 $/Acre Assumption for Acreage NOT Represented by Wells Drilled + Drillable Today $6,700 $6,700 Valuation of Acreage NOT Represented by Wells Drilled + Drillable Today ($mm) $64.5 $66.5 Total ASD Enterprise Value $326.1 $425.3 less Net Debt as of 5/30/14 ($102.3) ($102.3) less Potential Repayment to Republic ($15.0) ($15.0) Total ASD Equity Value $208.8 $308.0 less NPI of 6.5% (13.6) (20.0) Total Equity Value to TENG Shareholders 195.2 288.0 Approx. # Shares Outstanding, in Millions (Assumes Vesting and Exercise of All Shares/Options) 17.0 17.0 Value to TENG Shareholders (Incl. Option Proceeds) $201.2 $294.0 Value per TENG Share $11.84 $17.29 Note: Assumes $4.50 flat natural gas price, average cost of $7.45 mm/well, 5,000' avg. lateral length, 81.3% 8/8ths NRI (Marshall Cty Avg.); Actual NRI in Wetzel is closer to 87.5%. 27