Johnson Rice & Company 2015 Energy Conference

Transcription

1 Johnson Rice & Company 2015 Energy Conference September 2015 E XPANDING O UR H ORIZONS 1

2 Forward-Looking Statements CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 This presentation of Gastar Exploration Inc. contains forward-looking statements relating to Gastar s operations that are based on management s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as anticipates, expects, intends, plans, targets, projects, believes, seeks, schedules, estimates, budgets and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond the company s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forwardlooking statements, whether as a result of new information, future events or otherwise. Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices; changing refining, marketing and chemical margins; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternative-energy sources or product substitutes; technological developments; the results of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, sever weather or crude oil production quotas that might be imposed; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; governmentmandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principals promulgated by rule-setting bodies; and the factors set forth under the heading Risk Factors on pages 29 through 42 of the company s 2014 Annual Report on Form 10-K. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed in this presentation could also have material adverse effects on forward-looking statements. The company undertakes no obligation to publicly update or revise any forward-looking statements except as required by law. 2

3 Statement on Hydrocarbon Quantities We use terms, such as resources, resource potential, and EUR, or estimated ultimate recovery, and similar terms, in this presentation to describe potentially recoverable oil and gas hydrocarbon quantities that are not permitted to be used in filings with the U.S. Securities and Exchange Commission. We include these internally-prepared estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial capital spending over significant number of years to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. In addition, we have made no commitment to drill, and likely will not drill, all of the drilling locations which have been attributed to these quantities EURs and type curve data included herein remain subject to change as more well data is analyzed and, except as otherwise noted, are not reflective of SEC proved undeveloped estimates. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. The following is a description of the referenced terms we have used to refer to hydrocarbon quantities: 1P reserves: estimates of proved reserves which in this presentation are estimated by Wright & Company as of December 31, 2014 using SEC pricing and definitions. EURs: estimated ultimate recoveries per well based on estimated future production type curves using NYMEX futures curve pricing as of August 31, 2015, as follows: for operated and non-operated Hunton, based on June 30, 2015 Wright & Company proved reserve type curve assuming 4,200 lateral; for operated Upper Hunton and Lower Hunton in the West Edmond Hunton Lime Unit (WEHLU), based on June 30, 2015 Wright & Company proved reserve type curve and assuming 6,000 lateral; for Marcellus, based on June 30, 2015 Wright & Company proved type curve assuming 5,000 lateral and benefit of ethane processing; and for Utica, based on June 30, 2015 Wright & Company proved reserve type curve and assuming 6,600 lateral 3

4 Company Profile Asset Overview (06/30/2015) Q2 15 Net Prod. by Region Utica Dry Gas (1) ~8,600 net acres leased ~1,900 net acres pending Marcellus Shale Play ~46,700 net acres Appalachia 7.7 MBoe/d 55% Mid-Continent 6.2 MBoe/d 45% Hunton Limestone Oil Play ~103,900 net acres STACK - Meramec ~43,700 net acres STACK - Woodford ~68,100 net acres Field Offices Oklahoma City, OK Clarksburg, WV Appalachia 53.3 MMBoe 58% 13.9 MBoe/d Proved Reserves by Region (2) Mid-Continent 38.1 MMBoe 42% Total ~150,600 net acres Stock Information (9/23/15) Listed on the NYSE MKT: GST $105.7 million market capitalization $671 million enterprise value (3) 80.1 million shares outstanding ~47% institutional ownership (4) Houston, TX Headquarters 1. 10,500 net acres of Utica Dry Gas included in Marcellus Shale Play. 1,900 net acres pending includes acreage with lease negotiations in progress 2. Based on 6/30/15 Wright & Company, Inc. report utilizing SEC pricing 3. Includes issued and outstanding preferred shares of $154.6 million face value, $420 million of debt and $9.4 million of cash 4. Source: Bloomberg as of 09/23/15 Appalachia $75.9MM 14% 91.4 MMBoe (548.4 Bcfe) SEC PV-10 (2) $538 Million Mid-Continent $462.1MM 86% 4

5 Key Investment Criteria High-Quality Resource Base Strong drilling results in the Hunton Limestone oil play Offset STACK Play wells (Meramec and Woodford) successful NE stack play of prolific high rate dry gas Utica under liquids-rich Marcellus Shale Organic Growth Strategy Through the Drill Bit and Strategic Acquisitions ~81% of 2015 budgeted capex allocated to drilling ~91% of 2015 budgeted drilling capex operated ~1,053 net undrilled locations Track Record of Adding Proved Reserves and Creating Value Proved reserves of 91.4 MMBoe (1) Oil reserves of 29.5 MMboe (1) (up 10%) Four and a half year 70% CAGR (1) Diverse Mix of Crude Oil and Natural Gas Opportunities Liquids 54% of proved reserves Liquids 53% of Q production Gas optionality with dry gas Utica Strong Financial Profile Strong liquidity position No near term debt maturities Active hedging program 2016 PDP hedge position 62% of oil PDP production and 54% of gas PDP production (2) 1. Based on 06/30/15 Wright & Company, Inc. report utilizing SEC pricing 2. Hedges as of 09/1/2015. Oil hedges include WTI for NGL proxy hedges and 25% of NGL PDP 5

6 Proven Track Record of Growth Significant reserves and production growth through acquisitions and the drill bit Gas Liquids 96.0 Proved Reserves by Product (1) 91.4 MMBoe % 53% 54% MBoe/d % 99.3% Gas Condensate & Oil NGLs 2% 3% 95% 23% 28% 77% 12% 8% 80% 72% 22% 15% 31% 48% 16% 26% 69% 52% Q2' Guidance Mid-Point 55% 47% 46% Q2'15 5% 20% Total Daily Production (1) % 29% 47% 52% %-56% Liquids 1. Gas converted to oil equivalent on basis of 6 Mcf:1 Boe 6

7 Production Growth YTD Average Production has grown ~29% over 2014 average Total Daily Production (1) MBoe/d % 1.4 Liquids % Liquids % Liquids Year To Date Gas Condensate & Oil NGLs 1. Gas converted to oil equivalent on basis of 6 Mcf:1 Boe 7

8 Summary Target Economics ~704 net locations for Hunton, Marcellus and Utica, additional ~349 net locations in STACK Play Operated and Non- Operated Hunton Operated WEHLU Upper Hunton Operated WEHLU Lower Hunton Marcellus Utica Number of net drilling locations ~293 ~144 ~156 ~57 ~54 EURs Processed 419 Mboe 346 Mboe 425 Mboe 6.9 Bcfe 18.5 Bcfe Wet Gas 380 Mboe 314 Mboe 395 Mboe NA N/A Daily Peak Rate 746 Boe/d 467 Boe/d 426 Boe/d 2.6 MMcf/d & 260 Bbl/d 28.9 MMcf/d % Gas (processed) 21% 16% 11% 50% 100% % Liquids (processed) 79% 84% 89% 50% N/A % Oil (wet gas) 61% 75% 82% 27% N/A IRR 11% 42% 23% 5% 9% Costs ($MM) $5.50 $3.30 $5.25 $6.50 $13.00 PV-10 ($MM) $0.1 $2.3 $2.1 ($1.2) ($1.1) F&D Costs (processed) $16.83/Boe $11.61/Boe $15.09/Boe $1.16/Mcfe $0.86/Mcfe Est. Average Proc. Cum. Daily Rate (1) : 1st 30 Days 124 Boe/d 430 Boe/d 406 Boe/d 847 Boe/d 24.2 MMcf/d 1st 60 Days 383 Boe/d 384 Boe/d 374 Boe/d 803 Boe/d 21.1 MMcf/d 1st 90 Days 410 Boe/d 350 Boe/d 349 Boe/d 765 Boe/d 19 MMcf/d Note: EURs and related type curves developed by the Company based on assumptions and methodology described on page 3 of this presentation 1. Cumulative daily rates calculated using processed gas stream 8

9 2015 Capital Budget 91% of drilling budget operated, provides financial flexibility Current 2015 Budget Area Capital ($MM) % of Total Mid-Continent Operated $65 54% Mid-Continent Non-Operated 9 8% Marcellus 18 15% Utica 5 4% Capitalized Costs (2) 6 5% Land (1) 17 14% Total $ % No. of Wells Spud Gross Net Mid-Continent Operated Mid-Continent Non-Operated Marcellus Utica No. of Wells Completed Gross Net Mid-Continent Operated Mid-Continent Non-Operated Marcellus Drilling and Infrastructure $97 81% Mid-Continent $87 72% Land $17 14% Capitalized Costs $6 5% Capitalized Costs $6 5% Utica Mid-Continent $12.5MM; Appalachia $4.5MM 2. Includes capitalized interest and other capitalized costs Appalachia $27 23% 9

10 HUNTON & STACK PLAYS 10

11 Hunton: First Mover Advantage Large, contiguous acreage position with multiple horizontal targets 103,900 net acres Asset Overview Low all-in acreage cost due to non-core lease sales WEHLU acquisition increased oil production and added to upside potential in the play Hunton Asset Map Net Hunton exploitation locations 256 Operated Lower Hunton (1) 235 Operated Upper Hunton (2) 102 Non-Operated Lower Hunton (1) 593 STACK Play potential locations 213 net Woodford 136 net Meramec net drilling locations STACK Play Hunton Cross Section 1. Includes 22 PUDS booked as of 06/30/15 on WEHLU acreage per Wright & Company, Inc. 2. Includes 45 PUDS booked as of 06/30/15 on WEHLU acreage per Wright & Company, Inc. 11

12 Oklahoma Hunton Play Overview Successful drilling results, leading to development Hunton Activity Map De-risking by industry activity and historic vertical production in the area Oklahoma Hunton Statistics 1P Reserves: 38.1 MMBoe (1) Q2 15 net production: 6.20 MBoe/d; 74% liquids (54% oil) Total Net Potential Drilling Locations: 593 Producing Wells: Gross 227 / Net Based on 06/30/15 Wright & Company, Inc. report utilizing SEC pricing 12

13 Operated Hunton Development 2015 Development Plan Operated Activity Map Focus is on WEHLU Recently finished drilling last well for this year Lower Hunton Development 11 horizontal operated wells drilled over large geographic area to date Still de-risking additional operated acreage Upper Hunton Development 7 horizontal operated wells drilled Southern WEHLU Extension No PUD or Probable locations booked on Southern WEHLU Warsaw pad tested three zones in southern WEHLU Jetson pad testing Upper and Lower Hunton 13

14 Operated Hunton Potential - WEHLU Hunton offers a substantial source of high return projects Upper Hunton Overview 45 PUDs on northern WEHLU acreage No proved value assigned to southern WEHLU horizontal potential Lower Hunton Overview Previous operator drilled no horizontal producing wells on WEHLU acreage 22 PUDS on northern WEHLU acreage Four well average results: Peak rate of 646 Boe/d (88% oil) Five well average results: Peak rate of 546 Boe/d (87% oil) Summary Economics (2) EUR % Oil Well Cost IRR PV MBoe 75% $3.3MM 42% $2.3MM Average Type Curve Daily Rate (3) Peak 1 st 30 Days 1 st 60 Days 1 st 90 Days Boe/d Summary Economics (2) EUR % Oil Well Cost IRR PV MBoe 82% $5.25MM 23% $2.1MM Average Type Curve Daily Rate (3) Peak 1 st 30 Days 1 st 60 Days 1 st 90 Days Boe/d Through production date of 7/19/2015. Oil % representative of inception to date 2. Based on EURs and related type curves developed by the Company using assumptions and methodologies described on page 3 of this presentation 3. Cumulative daily rates calculated using unprocessed gas stream 14

15 Non-Operated AMI Activity Overview AMI established in 2012 to focus on Lower Hunton development Have drilled 37 wells in the Lower Hunton and 2 wells in the Upper Hunton Currently re-drilling one well 55 gross PUDs booked on AMI acreage Non-Operated Activity Map AMI Summary Economics (1) EUR % Oil Well Cost IRR PV MBoe 61% $5.5MM 11% $0.1MM Average Type Curve Daily Rate (2) Peak 1 st 30 Days 1 st 60 Days 1 st 90 Days Boe/d Based on EURs and related type curves developed by the Company using assumptions and methodologies described on page 3 of this presentation 2. Cumulative daily rates calculated using unprocessed gas stream 15

16 Non-Operated AMI Average Well Performance Production averages in line with current type curve % (Boe and % Oil) % % 72% 74% 70% 70% 67% 68% 66% 67% 65% 66% 0 Peak Rate 76% Peak Rate 30-Day 30-Day 60-Day 60-Day 90-Day 90-Day Day Day 360- Day Day Day 360-Day Cumulative Production Averages Current Type Curve (1) AMI Results (2) No. of Wells Based on EURs and related type curves developed by the Company using assumptions and methodologies described on page 3 of this presentation. Cumulative daily rates calculated using unprocessed gas stream 2. Includes only AMI Lower Hunton target wells, excludes upper Hunton well Huntsberger 1-3H. See appendix for individual well performance included in each average. Represents average on production cumulative average daily Boe 16

17 STACK - Meramec Overview Offset operator IPs range up to ~1,600 Boe/d (98% oil) Meramec / Miss Lime Activity Map (1) Meramec play naturally fractured carbonate similar to Hunton Other operator activity de-risking the play Meramec/ Miss. Lime Statistics Net potential acres: ~43,700 Est. locations: 136 net MBoe, reserve target (87% oil) Currently drilling $6.5 MM gross CWC 1. Other operator production rates obtained from third-party company data, investor presentations, public filings and other sources that have not been independently verified by Gastar Exploration Inc. 17

18 STACK - Woodford Overview Offset operator IPs up to ~1,000 Boe/d (84%+ oil) Woodford Activity Map (1) Gastar acreage unexplored Other operator activity de-risking the play Non-operated participation Woodford Statistics Net potential acres: ~68,100 Est. locations: 213 net 1. Other operator production rates obtained from third-party company data, investor presentations, public filings and other sources that have not been independently verified by Gastar Exploration Inc. 18

19 Oklahoma Summary Meramec ~136 net locations Woodford 2015 Capital Budget Activity Hunton Wells spud gross (13.2 net) wells 12.0 gross (11.8 net) operated Hunton wells 3.0 gross (1.4 net) non-operated AMI Hunton wells Hunton Wells completed gross (17.5 net) wells 14.0 gross (13.8 net) operated Hunton wells 9.0 gross (3.7 net) non-operated AMI Hunton wells Meramec -1.0 gross (>65% net) Net Hunton Drilling Locations ~593 net risked locations on existing acreage Additional Upside STACK Play ~213 net locations 38.1 MMBoe 1P reserves with SEC PV-10 of $462.1MM (1) 1. Based on 06/30/15 Wright & Company, Inc. report utilizing SEC pricing 19

20 MARCELLUS AND UTICA 20

21 Core Position in the Marcellus and Utica Acreage position lies near other leading players in the basin Appalachia Overview Core acreage proven in both the Marcellus wet gas and the Utica dry gas plays Marcellus and Utica Map Utica Dry Gas Core Gastar West Acreage ~11,000 net acres in Marcellus and 8,600 leased (additional 1,900 pending (1) ) net acres in dry Utica 50% WI, 41.0% NRI Marshall & Wetzel Counties Marcellus Fairway ~35,700 net acres in eastern area 100% WI, 80% NRI Utica potential being studied ~46,700 total net acres (2) Utica Fairway Gastar East Acreage 1. 1,900 net acres pending includes acreage with lease negotiations in progress 2. As of 06/30/2015. Includes ~1,300 acres in Pennsylvania expiring 2015 and forward 21

22 Infrastructure Overview Operational Improved run-time No flow restrictions expected Processing Total system capacity to 720 MMcf/d Central receipt point capacity 155 MMcf/d Adequate takeaway capacity Firm transport Water System 50 MMBtu/d Additional firm available 14-mile system in Marshall County Reduced water costs from $2.50/Bbl to $0.20/Bbl Supports both Marcellus and Utica development 22

23 NE Basis Gas and NGL basis differentials widened in 2015 Gas infrastructure buildout to alleviate REX reversal to west August 1, Bcf Source: Tudor Pickering Holt & Co January 2015 Midstream Bulletin ~15 Bcf/d of incremental takeaway capacity announced since YE

24 Marcellus Shale Activity concentrated in liquids-rich portion of the play Marshall & Wetzel Counties, W. Va. Atinum 50% JV Partner High Btu gas and condensate yields Bbls/MMcf condensate Bbls/MMcf NGLs (pre-ethane recovery) Marcellus Core Statistics 1P Reserves: 42.6 MMBoe (1) Q2 15 net production: 6.5 MBoe/d; 42% liquids (11% oil) Remaining locations: gross 113, net gross PUDS Summary Economics (2) EUR Well Cost IRR PV Bcfe $6.5MM 5% ($1.2MM) Gross Appalachia Production 1. Based on 06/30/15 Wright & Company, Inc. report utilizing SEC pricing 2. Based on EURs and related type curves developed by the Company using assumptions and methodologies described on page 3 of this presentation 24

25 Marcellus Shale Development Development Plan Gastar has drilled and completed 74 gross (35.4 net) horizontal wells and one vertical well to date Recent completions: Armstrong (7 wells) - 12/19/2014 Hansen ( 3 wells) - 12/26/2014 Goudy (3 wells) - 03/3/2015 Hoyt (2 wells) - 4/5/2015 Blake (2 wells) - 4/18/2015 OHIO Marcellus Drilling Locations Marshall Co. - Marcellus Wells Producing - 74 PUDS 51 West Virginia No further drilling in 2015 No near term lease expirations 42% HBP 71% 2015/16 expirations include automatic payment extensions OHIO Wetzel Co. - Marcellus Wells Producing - 1 Future Locations - 62 West Virginia 25

26 Utica Shale Acreage position lies in core of the Dry Gas Window Overview Underlies core 11,000 acre Marcellus position 8,600 currently leased with an additional 1,900 pending (1) Majority of Utica acreage is held by Marcellus drilling Utica Statistics 1P Reserves: 10.7 MMBoe (3) Q production: 6.8 MMcf/d (No liquids) Pending locations: ~54 net 6 gross PUDS Summary Economics (4) EUR Well Cost IRR PV Bcf $13.0MM 9% ($1.1MM) Rice IP: 42 MMcfe/d (Bigfoot #9H) OHIO GPOR IP: 21 MMcfe/d Avg. 14 MMcfe/d in Q3 13 (Stutzman #1-14H) Rex 3 wells IP: MMcfe/d Antero 2 wells IP: MMcfe/d Antero 5 wells IP: MMcfe/d (peak) Utica Fairway Utica Activity Map (2) GPOR 2 wells IP: MMcfe/d MHR 32 MMcf/d (Stadler #3UH) GPOR 30 MMcf/d (Irons #4H) Eclipse 21.3 MMcf/d avg (Shroyer 2H&4H) Eclipse 23 MMcf/d (Tippens #6H) Hess 1 well IP: 25 MMcfe/d Chevron 25 MMcf/d (Howard Conner #6H) MHR WEST 46.5 MMcf/d VIRGINIA (Stewart Winland #1300U) Gastar Blake U-7H IP 36.8 MMcf/d Gastar Simms U-5H IP 29.4 MMcf/d Southwestern IP 25.0 MMcf/d (Messenger 3H) Stone Energy IP 30.0 MMcf/d (Pribble 6HU) Range Resources 59 MMcf/d 1 well EQT 72.9 MMcf/d Scotts Run Pad Utica Dry Gas Core 1. 1,900 net acres pending includes acreage with lease negotiations in progress 2. Other operator production rates obtained from third-party company data, investor presentations, public filings and other sources that have not been independently verified by Gastar Exploration Inc. 3. Based on 06/30/15 Wright & Company, Inc. report utilizing SEC pricing 4. Based on EURs and related type curves developed by the Company using assumptions and methodologies described on page 3 of this presentation 26

27 Utica Shale Development Development Plan Blake well completed, 6,600 lateral with 34 stage frac ~$15.3MM D&C costs Only 6 of 108 gross locations in PUD category Timing of additional Utica development based on market conditions Blake U-7H 6600 Lateral Length OHIO Utica Drilling Locations Marshall Co. - Utica Wells Producing - 2 Future Locations - 77 West Virginia Simms U-5H 4447 Lateral Length Wetzel Co. - Utica Wells Future Locations - 31 OHIO West Virginia 27

28 Utica Shale Development Blake U-7H and Simms U-5H demonstrate the repeatability of dry gas Utica across Gastar s Marshall County position Initial production date Initial 48 hours sales rate (MMcf/d) Flowing casing pressure psi Lateral length (feet) Frac stages 30 day initial production (MMcf/d) ITD daily production average (MMcf/d) (1) ITD cumulative production (Bcf) (1) Blake U-7H 05/18/ ~6,235 6, Simms U-5H 08/29/ ~6,700 4, Production as of 07/31/

29 Point Pleasant Paleography and SSTVD Structure East and West Appalachian Acreage on same shelf with similar features Point Pleasant Paleogeography Point Pleasant SSTVD Structure GST SIMMS IP: 29.4 MMCF/D BLAKE IP: 36.8 MMCF/D Scotts Run Pad-EQT 3,221 treated interval 24 hr. IP: 72.9 MMcf 22.6 MMcf / ,641 psi flowing casing pressure 0.95 pore pressure gradient Stewart-Winland Pad- MHR IP: 46.5 MMcf GST LACKAWANNA PAD Higher porosities in Pleasant Point are associated with the depositional environment of the Lexington Shelf Region Structure is very benign in Point Pleasant over west acreage East Marcellus acreage appears prospective in the Point Pleasant Point Pleasant Paleogeography Source: After Wickstrom and others, 1992 and Cornell, Image from 29

30 Appalachia Summary 2015 Capital Activity Complete 7.0 gross (3.5 net) Marcellus wells Complete 1.0 gross (0.5 net) Utica wells Net Drilling Locations ~ 57 net Marcellus locations on existing acreage ~ 54 net Utica locations on existing acreage Appalachia Statistics 1P Reserves: 53.3 MMBoe (1) 1P PV 10: $75.9MM (1) 53.3 MMBoe 1P reserves with SEC PV-10 of $75.9MM (1) 1. Based on 06/30/15 Wright & Company, Inc. report utilizing SEC pricing 30

31 FINANCIAL OVERVIEW 31

32 Financial Strategy Goal: Grow NAV and reserves per share through exploitation of existing assets Leverage Ratios and Liquidity Maintain acceptable leverage and coverage ratios given commodity price environment Financial flexibility through revolver capacity Review opportunities to reduce leverage and enhance liquidity Hedging Program Protects cash flow and targeted leverage and coverage ratios Supports fixed cost coverage and capital program As of 9/1/2015, hedged 83% of 2015 PDP oil and NGLs production with $63.50 average floor As of 9/1/2015, hedged 71% of 2015 PDP gas production with $3.53 average floor Operating Margins and Efficiency Balanced production profile allows focus on highest operating margin product Low cash operating costs per Boe Working to reduce drilling times and improve completion design in Hunton Operational Budget Control Operate ~91% of 2015 drilling capital budget Growing multi-year drilling inventory Capital expenditure flexibility 32

33 Capitalization and Liquidity Capitalization ($ in millions) 06/30/2015 Cash $9.4 Long Term Debt Senior Secured Notes due 2018, net (maturity value) $325 Revolving Credit Facility 95.0 Total Debt $420.0 Total Stockholders Equity Total Capitalization $650.6 Liquidity Revolver Borrowing Base $200.0 Less: Revolver Balance 95.0 Plus: Cash 9.4 Liquidity $114.4 Pro forma property sale closed July 6 th Pro forma liquidity $

34 PDP Hedging Program 5,000 Oil and NGLs Hedging Strategy (Bbl/d) 4,000 3,000 2,000 $63.50 $77.71 $74.73 $ ,000 0 Downside Hedged % 30,000 (3) (1) (2) Volume Average Hedge Floor Price ($/Bbl) 83% 62% 60% 14% Gas Hedging Strategy (MMBtu/d) 24,000 18,000 12,000 $3.53 $3.37 $3.00 $3.00 6,000 0 Downside Hedged % (4) (5) Volume Average Hedge Floor Price ($/MMbtu) 71% 54% 20% 23% Note: Hedges as of 9/1/2015. Average Floor prices represent average floor of swap and long put volumes 1. Volume includes 750 Bbl/d propane swap at $ Price represents WTI average floor 2. Volume includes 500 Bbl/d propane swap at $ Price represents WTI average floor 3. Includes WTI for NGL proxy hedges and 25% of NGL PDP 4. Does not include 7,500 MMBtu/d IF DOM South Basis Swap at ($1.123) 5. Does not include 7,500 MMBtu/d Tetco-M2 Basis Swap at ($1.04) 6. Does not include 5,000 MMBtu/d NYMEX Henry Hub Basis Swap at ($1.01) excludes 10,000 Mmbtu/d short call. (6) (6) 34

35 Realized Prices - Historical Realized Oil Prices Realized Gas Prices $ % 91% 90% 100% $ % $78.00 $ % 75% 80% $ % 80% 81% 79% 80% $66.00 $54.00 $65.45 $70.91 $ % 40% $3.60 $2.40 $3.21 $3.02 $ % 60% 40% $42.00 $ % $1.20 $2.21 $ % $ YTD'15 0% $ YTD'15 0% % of WTI - Other Realized Price % of HH Realized Price Realized NGL Price Commodity Prices $ % $8.00 $91.53 $90.69 $94.49 $89.49 $100 $ % 60% $6.40 $80 $36.00 $ % 33% 31% 45% $4.80 $3.99 $3.72 $4.33 $49.81 $60 $24.00 $12.00 $28.22 $31.59 $ % 30% 15% $3.20 $1.60 $21.89 $2.75 $19.26 $28.58 $43.84 $2.80 $19.97 $40 $20 $0.00 $ YTD'15 0% $ YTD'15 $0 % of WTI - Other Realized Price $/Boe HH WTI - Other Note: Excludes impact of hedge gains and losses and 2014 arbitration settlement 35

36 Realized Prices by Area YTD 15 Realized Oil Prices Realized Gas Prices $60.00 $ % 90% 120% 96% $6.00 $ % 120% 96% $40.00 $30.00 $20.00 $ % $ % $50.40 $44.76 Marcellus Utica Mid-Continent Total Company % of WTI - Other Realized Price 72% 48% 24% 0% $3.60 $2.40 $1.20 $ % $ % $0.99 $ % $1.55 Marcellus Utica Mid-Continent Total Company % of HH Realized Price 72% 48% 24% 0% Realized NGL Price Realized Boe Price $ % $ % 80% $12.00 $9.00 $6.00 $3.00 $0.00 8% $3.93 0% $0.00 $ % $ % Marcellus Utica Mid-Continent Total Company % of WTI - Other Realized Price 48% 36% 24% 12% 0% $48.00 $36.00 $24.00 $12.00 $ % $ % $5.93 $ % $19.97 Marcellus Utica Mid-Continent Total Company % of WTI - Other Realized Price 64% 48% 32% 16% 0% Note: Excludes impact of hedge gains and losses 36

37 Production Costs Historical ($/Boe) Lease Operating Expense Transportation $9.00 $4.00 $3.51 $7.20 $6.74 $3.20 $5.40 $5.26 $5.53 (1) $2.40 $2.25 $3.60 $2.80 $2.92 $1.60 $1.24 $1.80 $0.80 $0.56 $0.43 $ YTD'15 $ YTD'15 Prod. Tax Total Direct Costs vs. Daily Production $1.80 $1.44 $1.08 $0.72 $0.48 $1.03 $1.44 $1.66 $0.69 $14.00 $11.20 $8.40 $5.60 $10.73 $6.08 3,509 6,032 8,866 $ ,159 $ ,243 $6.66 (1) 15,000 12,000 9,000 6,000 $0.36 $2.80 3,000 $ YTD'15 1. Includes $1.15/Boe of workover expense Note: Excludes impact of 2014 arbitration settlement $ YTD'15 Total Direct Costs Daily Production 0 37

38 Key Investment Criteria High-Quality Resource Base Strong drilling results in the Hunton Limestone oil play Offset STACK Play wells (Meramec and Woodford) successful NE stack play of prolific high rate dry gas Utica under liquids-rich Marcellus Shale Organic Growth Strategy Through the Drill Bit and Strategic Acquisitions ~81% of 2015 budgeted capex allocated to drilling ~91% of 2015 budgeted drilling capex operated ~1,053 net undrilled locations Track Record of Adding Proved Reserves and Creating Value Proved reserves of 91.4 MMBoe (1) Oil reserves of 29.5 MMboe (1) (up 10%) Four and a half year 70% CAGR (1) Diverse Mix of Crude Oil and Natural Gas Opportunities Liquids 54% of proved reserves Liquids 53% of Q production Gas optionality with dry gas Utica Strong Financial Profile Strong liquidity position No near term debt maturities Active hedging program 2016 PDP hedge position 62% of oil PDP production and 54% of gas PDP production (2) 1. Based on 06/30/15 Wright & Company, Inc. report utilizing SEC pricing 2. Hedges as of 09/1/2015. Oil hedges include WTI for NGL proxy hedges and 25% of NGL PDP 38

39 APPENDIX 39

40 Lower Hunton Non-Operated Drilling Overview Well Results Cumulative Production Averages (2) Approx. NRI % Date Flowback Commenced Peak Rate (1) 30 Day 60 Day 90 Day 180 Day 270 Day 360 Day Current 5 Day Average (3) % Oil (4) (Boe/d) Non-Operated Hunton AMI Thrasher -1H 39.0% 02/15/13 1, , % Bledsoe 1-28H 44.2% 04/03/ % Gritz 1-7H 39.0% 04/30/ % Henley 1-11H 42.6% 08/23/ % State School Land 1-36H 39.0% 10/04/13 1, , % Stevens 1-36H 36.6% 11/15/ % Jet 1-12H 36.8% 02/01/ % Jones 1-21H 37.7% 03/02/ % Liebhart 1-31H 38.7% 03/18/ NA 57 69% Coronado 1-3H 33.6% 03/19/ % Gamebird 1-7H 37.8% 04/02/ % Sieber 1-31H 26.3% 04/13/14 1, % Kodiak 1-29H 35.3% 05/04/14 1,666 1,259 1, % Anna Lee 1-30H 39.0% 05/20/ NA 87 68% Vaverka 01-20H 35.1% 07/10/ NA 83 65% Sasquatch 01-23H 34.5% 07/27/ NA % Jam 1-4H 25.8% 08/08/ NA 91 57% Yeti 1-29H 33.0% 08/26/14 1, NA 87 61% Danny Ray 1-30H 24.0% 08/29/ NA 83 54% Cline 1-13H 39.0% 09/06/ NA 49 81% Michael J 1-18H 26.0% 09/29/ NA % Shimanek 1-2H 38.0% 10/09/14 1,829 1,400 1,268 1, NA % Hobbs Ranch 1-19H 27.0% 10/13/ NA % Snowman 28.0% 10/19/ NA NA % Breckenridge 1-2H 21.0% 11/07/ NA NA 54 74% Bear Claw % 11/13/ NA NA % Joyce % 12/05/ NA NA % Barry 1-6H 38.0% 12/13/ NA NA % LB % 01/23/ NA NA NA % Boss Hog 1-14H 33.0% 02/21/ NA NA NA 45 68% Hubbard 1-23H 39.0% 02/19/15 NA NA NA NA 27 95% Bo % 02/28/ NA NA NA % The River 1-22H 28.4% 03/14/15 1,250 1,090 1,071 1,008 NA NA NA % Bigfoot % 03/17/ NA NA NA 80 58% Falcon 1-5H 35.1% 04/01/15 1, NA NA NA % Dorothy % 04/10/15 NA NA NA NA NA 20 78% Polar Bear 1-20H 35.0% 05/05/ NA NA NA NA % Average % Type Curve Well (5) % 1. Wells that have not reached peak rate reflected as NA 2. Represents the actual on production cumulative average daily Boe production 3. Reflects the most recent five-day production average as of 7/19/ Inception to date percentage oil production 5. Based on EURs and related type curves developed by the Company using assumptions and methodologies described on page 3 of this presentation. Reflects unprocessed gas stream. 40

41 AMI Drilling Results Lower Hunton Wells are in line with current type curve 300, , , ,000 60, Based on EURs and related type curves developed by the Company using assumptions and methodologies described on page 3 of this presentation 2. Includes only AMI Lower Hunton target wells, excludes upper Hunton well Huntsberger 1-3H Thrasher 1H Bledsoe 1 28H Gritz 1 7H Henley 1 11H State School Land 1 36H Stevens 1 36H Jet 1 12H Jones 1 21H Liebhart 1 31H Coronado 1 3H Gamebird 1 7H Sieber 1 31H Kodiak 1 29H Anna Lee 1 30H Vaverka 01 20H Sasquatch 01 23H Jam 1 4H Yeti 1 29H Danny Ray 1 30H Cline 1 13H Michael J 1 18H Shimanek 1 2H Hobbs Ranch 1 19H Snowman Breckenridge 1 2H Bear Claw 1 28 Joyce 1 10 Barry 1 6H LB 1 1 Hubbard 1 23H Boss Hog 1 14H Bo 1 23 The River 1 22H Bigfoot 1 9 Falcon 1 5H Polar Bear 1 20H Dorothy 1 12 (1) Type Curve (2) Average Well Count 41

42 Lower/Upper Hunton Drilling Overview Well Results Approx. NRI % Date Flowback Commenced Peak Rate (1) 30 Day 60 Day 90 Day 180 Day 270 Day 360 Day Current 5 Day Average (3) % Oil (4) Operated Hunton WEHLU Lower Easton 22-1H 80.5% 07/30/ NA 85 90% Deer Draw 21-4CH 80.5% 11/07/ NA NA % Deer Draw 21-5H 80.5% 11/09/ NA NA % Warsaw 33-3H 80.5% 02/14/ NA NA NA % Easton 22-3H 80.5% 05/24/15 NA 285 NA NA NA NA NA % Average NA % Type Curve Well (5) % WEHLU Upper Easton 22-2H 80.5% 08/05/ NA % Warsaw 33-2H 80.5% 02/13/ NA NA NA % Blair Farms 31-1H 80.5% 05/07/ NA NA NA NA % Easton 22-4H 80.5% 05/20/ NA NA NA NA NA % Average NA % Type Curve Well (5) % Non-WEHLU Burton 16-1H 65.8% 12/07/ % Townsend 6-1H 80.0% 01/13/ % Taborek 1-22H 67.0% 03/06/ % Horseshoe 3-1H 78.0% 09/16/ NA % Average % Type Curve Well (5) % 1. Wells that have not reached peak rate reflected as NA 2. Represents the actual on production cumulative average daily Boe production 3. Reflects the most recent five-day production average as of 7/19/ Inception to date percentage oil production 5. Based on EURs and related type curves developed by the Company using assumptions and methodologies described on page 3 of this presentation 42

43 Utica Acreage is the dry gas Core of the Core Point Pleasant Point Pleasant Shale Porosity Cross-Section A A GASTAR SIMMS U-5H 4-6% Porosity Up to 17% Porosity VERY HIGH PRESSRURE, HIGH RATE GAS WINDOW Landing point Lexington Shelf High Porosity High TOC High Carbonate Content 43

44 Utica Shale Development Utica Dry Gas Comparative Statistics (1) 1. Other operator data obtained from third-party company data, investor presentations, public filings and other sources that have not been independently verified by Gastar Exploration Inc. 44

45 Point Pleasant Gross Isopach Thickness Low thickness variations in the Point Pleasant across Gastar s acreage Eclipse Shroyer #2H & 4H Combined IP: 42.5 MMcf/d GPOR Irons #4H IP: 30.3 MMcf/d CVX Conner #6H IP: 25 MMcf/d EQT Scotts Run Pad IP: 72.9 MMcf/d Eclipse Tippens #6H IP: 23.2 MMcf/d MHR Stalder #3UH IP: 32.5 MMcf/d GST SIMMS U-5H IP: 29.4 MMcf/d BLAKE U-7H IP: 36.8 MMcf/d MHR Stewart Winland #1300U IP: 46.5 MMcf/d 45

46 Utica Activity around Marshall & Wetzel Counties (1) 1. Other operator data obtained from third-party company data, investor presentations, public filings and other sources that have not been independently verified by Gastar Exploration Inc. 46

47 Simms/Dangel Cross-Section Statoil USA Onshore Prop Inc Dangel 1-H Gastar Simms U-5H 5 Miles to west of Gastar s acreage Porosity: 6 12% Net pay of +/- 74 Target Depth: 11,350 TVD Porosity: Avg. 11% (up to 17%) Net pay of 92 47

48 Production Costs by Area YTD 15 ($/Boe) Lease Operating Expense Transportation $12.00 $1.00 $9.60 Workover expense $9.80 $2.53 $0.80 $0.79 $0.78 $7.20 $4.80 $5.53 $1.15 $0.60 $0.40 $0.43 $7.27 $2.40 $4.38 $0.20 $0.00 $2.21 $0.19 Marcellus Utica Mid-Continent Total Company $0.00 $0.01 Marcellus Utica Mid-Continent Total Company Prod. Tax Total Direct Costs vs. Daily Production $1.00 $0.80 $0.60 $0.63 $0.65 $0.77 $0.69 $14.00 $11.20 $8.40 Workover expense $10.57 $ ,243 14,000 11,200 8,400 $0.40 $5.60 6,334 6,030 $6.66 $1.15 5,600 $0.20 $0.00 Marcellus Utica Mid-Continent Total Company $2.80 $0.00 $8.04 $ $3.63 $1.62 Marcellus Utica Mid-Continent Total Company 2,800 0 Note: Excludes impact of hedge gains and losses Total Direct Costs Daily Production 48

49 Hedge Detail Natural Gas Period Contract Type Volume Hedged Price Sep - Dec 15 NYMEX Swap 400 MMBtu/d $4.00 Sep - Dec 15 NYMEX Swap 2,500 MMBtu/d $4.06 Sep - Dec 15 Prot. Spread 2,600 MMBtu/d $4.00 / $3.25 Sep - Dec 15 Basis Swap - Dom. SP 2,500 MMBtu/d ($1.12) Sep - Dec 15 Basis Swap - Dom. SP 2,500 MMBtu/d ($1.11) Sep - Dec 15 Basis Swap - Dom.SP 2,500 MMBtu/d ($1.14) Sep - Dec 15 NYMEX Swap 5,000 MMBtu/d $3.49 Sep - Dec 15 NYMEX Swap 2,000 MMBtu/d $3.53 Sep - Dec 15 3-Way 2,500 MMBtu/d $3.70 / $3.00 / $4.09 Sep - Dec 15 3-Way 5,000 MMBtu/d $3.77 / $3.00 / $4.11 Sep - Oct 15 3-Way 2,000 MMBtu/d $3.00 / $2.25 / $3.34 Sep - Oct 15 NYMEX Swap 10,000 MMBtu/d $2.94 Nov - Dec 15 3-Way 2,500 MMBtu/d $3.00 / $2.25 / $3.65 Jan - Oct 16 3-Way 2,500 MMBtu/d $3.00 / $2.25 / $3.65 Jan - Dec 16 Prot. Spread 2,000 MMBtu/d $4.11 / $3.25 Jan - Dec 16 3-Way 2,000 MMBtu/d $4.00 / $3.25 / $4.58 Jan - Dec 16 3-Way 5,000 MMBtu/d $3.40 / $2.65 / $4.10 Jan - Dec 16 Basis Swap - Tetco M2 2,500 MMBtu/d ($1.10) Jan - Dec 16 Basis Swap - Tetco M2 2,500 MMBtu/d ($1.02) Jan - Dec 16 Basis Swap - Tetco M2 2,500 MMBtu/d ($1.00) Jan - Mar 16 3-Way 7,500 MMBtu/d $3.00 / $2.50 / $4.00 Apr - Dec 16 3-Way 5,000 MMBtu/d $3.00 / $2.35 / $4.00 Jan - Dec 17 Basis Swap - Tetco M2 2,500 MMBtu/d ($1.02) Jan - Dec 17 Basis Swap - Tetco M2 2,500 MMBtu/d ($1.00) Jan - Dec 17 Short Call 10,000 MMBtu/d $4.75 Jan - Dec 17 3-Way 5,000 MMBtu/d $3.00 / $2.35 / $4.00 Jan - Dec 18 Basis Swap - Tetco M2 2,500 MMBtu/d ($1.02) Jan - Dec 18 Basis Swap - Tetco M2 2,500 MMBtu/d ($1.00) Jan - Dec 18 3-Way 5,000 MMBtu/d $3.00 / $2.35 / $4.00 Oil Period Contract Type Volume Hedged Price Sep - Dec 15 3-Way 400 Bbl/d $85.00 / $70.00 / $96.50 Sep - Dec 15 3-Way 325 Bbl/d $85.00 / $65.00 / $97.80 Sep - Dec 15 3-Way 50 Bbl/d $85.00 / $65.00 / $96.25 Sep - Dec 15 Collar 750 Bbl/d $52.50 / $62.05 Sep - Dec 15 Collar 300 Bbl/d $52.50 / $68.10 Sep - Dec 15 NYMEX Swap 600 Bbl/d $72.54 Sep - Dec 15 NYMEX Swap 250 Bbl/d $74.20 Sep - Dec 15 Collar 700 Bbl/d $45.00 / $55.25 Jan - Dec 16 3-Way 275 Bbl/d $85.00 / $65.00 / $95.10 Jan - Dec 16 3-Way 330 Bbl/d $80.00 / $65.00 / $97.35 Jan - Dec 16 3-Way 450 Bbl/d $57.50 / $42.50 / $80.00 Jan - Dec 16 Put Spread 550 Bbl/d $85.00 / $65.00 Jan - Dec 16 Put Spread 300 Bbl/d $85.50 / $65.50 Jan - Dec 17 3-Way 280 Bbl/d $80.00 / $65.00 / $97.25 Jan - Dec 17 3-Way 242 Bbl/d $80.00 / $60.00 / $98.70 Jan - Dec 17 3-Way 200 Bbl/d $60.00 / $42.50 / $85.00 Jan - Dec 17 Put Spread 500 Bbl/d $82.00 / $62.00 Jan - Dec 17 3-Way 200 Bbl/d $57.50 / $42.50 / $76.13 Jan - Aug 18 Put Spread 425 Bbl/d $80.00 / $60.00 NGL Period Contract Type Volume Hedged Price Sep - Dec 15 Propane Swap 250 Bbl/d $45.61 Sep - Dec 15 Propane Swap 500 Bbl/d $20.79 Jan - Dec 16 Propane Swap 500 Bbl/d $20.79 Deferred Put Premiums Year Amount ($MM) 2015 $ $ $ $0.97 Note: Hedges as of 09/1/

50 References Cornell, S. R Sequence Stratigraphy and Event Correlations of upper Black River and lower Trenton Group Carbonates of northern New York State and southern Ontario, Canada, unpublished M.S. Thesis, University of Cincinnati, Cincinnati, Ohio Wickstrom, L.H., J.D. Gray, and R.D. Stieglitz, 1992, Stratigraphy, structure, and production history of the Trenton Limestone (Ordovician) and adjacent strata in northwestern Ohio; Ohio Division of Geological Survey, Report of Investigations No. 143, 78 p., 1 pl. 50