GASTAR EXPLORATION INC. Investor Presentation. August Click to edit Master subtitle style

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1 GASTAR Click to edit Master subtitle style EXPLORATION INC Investor Presentation August 2018

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 forward-looking 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, severe 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; government-mandated 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; risks associated with the engagement in the exploration of strategic alternatives; and the factors set forth under the heading Risk Factors in the company s 2017 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. 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 The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves, however, we currently do not disclose probable or possible reserves in our SEC filings. We may use the terms resource potential and EUR in this presentation to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These are based on the Company s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities do not constitute reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or SEC rules. EUR, or Estimated Ultimate Recovery, refers to our management s internal estimates based on per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. For areas where the Company has no or very limited operating history, EURs are based on publicly available information relating to operations of producers operating in such areas. For areas where the company has sufficient operating data to make its own estimates, EURs are based on internal estimates by the Company s management and reserve engineers. Early well results are not always indicative of future well performance. Well costs are based on internally generated company estimates and actual results may vary. Drilling locations represent the number of locations that we currently estimate could potentially be drilled in a particular area estimated by well spacing and geological characteristic assumptions applicable to that area. The actual number of locations drilled and quantities that may be ultimately recovered from the Company s interests may differ substantially. There is no commitment by the Company to drill all of the drilling locations which have been attributed these quantities. Net prospective acreage and net surface acreage is calculated using geologic characteristic assumptions and anticipated drilling unit sizes. Factors affecting ultimate recovery include: (1) the scope of any drilling program we may pursue, which will be directly affected by factors that include the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and (2) actual drilling results, including geological and mechanical factors affecting recovery rates. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of any future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. 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 June 30, 2018 using SEC pricing and definitions. EURs: estimated ultimate recoveries per well based on estimated 35 year future production type curves using flat pricing of $60.00/Bbl for WTI-oil and $3.00/Mmbtu for HH-gas: Meramec and Osage based on June 30, 2018 Wright & Company proved reserve type curve assuming 4,700 lateral 3

4 Corporate Overview

5 Corporate Overview ~ 69,400 Core STACK Surface Acres (1) ~ 73% Held By Production ~ 1,574 Undeveloped Net Drilling Locations (1) Field Office: Oklahoma City STACK Sooner-Trend-Anadarko-Canadian-Kingfisher Garfield Formation STACK Optionality (1) Net prospective Acres Net Undeveloped Well Loc. Oswego 16, Manning 39, Meramec 26, Osage 64, Woodford 17, Hunton 40, Mid-Con Proved Reserves (2) Headquarters: Houston NGLs NGLs 25% Gas Prod. 19% Gas 35% 35% 10.5 MMBoe Oil 40% Kingfisher Q2 18 Net 5.7 MBoe/d Oil 46% (1) Acreage and well counts developed by the Company based on assumptions and methodology described on page 3 of this presentation as of 6/30/18. (2) Based on 6/30/18 Wright & Company Inc. report utilizing SEC pricing. PUD reserves not included due to financing uncertainty. 5

6 2018 Capital Budget January 2018 Budget Capital Area ($MM) % of Total STACK Operated Drilling $ % STACK Non-Operated Drilling % Land % Capitalized Interest + G&G % Total $ % No. of Wells Spud Gross Net STACK Operated STACK Non-Operated Total No. of Wells Completed Gross Net STACK Operated STACK Non-Operated Total Area August 2018 Revised Budget Capital ($MM) % of Total STACK Operated Drilling $ % STACK Non-Operated Drilling % Land % Capitalized Interest + G&G % Total $ % No. of Wells Spud New Gross Net STACK Operated STACK Non-Operated Total No. of Wells Completed New Gross Net STACK Operated STACK Non-Operated Total Currently drilling last operated well for

7 STACK Type Log Seven prospective formations across acreage position Multiple formations may be stacked depending on specific area Multiple benches within prospective formations Gamma Resistivity Porosity Cleveland Oswego Manning Offers large quantity of drilling projects and optionality to select highest returns and strategic benefits Meramec Osage Multiple formations can be pad drilled from the same site Possible stacked horizontal wellbores or saw tooth horizontal placement Proved Additional Upside Woodford Hunton Sylvan 7

8 Regional Cross Section Northeastern up-dip extension of the STACK play Over 1,000 of combined prospective formations Primary source rock (Woodford) underlies all of Gastar s acreage Target formations are very continuous Enhanced porosity from fractures and multiple unconformities throughout the STACK column 8

9 Summary Target Economics Based on third party proved reserve type curve projections (1) Meramec Economic Overview Meramec IRR Sensitivities (2) Meramec 2-Stream EUR (2) 463 MBoe % Oil 58% 3-Stream EUR (2) 511 Mboe % Liquids 72% IRR (2) 46% PV-10 ($MM) (2) $2.3 Gross Loc. per 640 acre section 6 Net Undeveloped Drilling Locations 228 Drilling & Completion Cost ($MM) (3) $4.5 Osage Economic Overview Osage 2-Stream EUR (2) 444 MBoe % Oil 58% 3-Stream EUR (2) 489 Mboe % Liquids 73% IRR (2) 45% PV-10 ($MM) (2) $2.2 Gross Loc. per 640 acre section 7 Net Undeveloped Drilling Locations 674 Drilling & Completion Cost ($MM) (3) $4.0 (1) EURs, related type curves and drilling locations are developed by the Company based on assumptions and methodologies described on page 3 of this presentation. (2) Assumes $3.00 gas with 100% WI and 78% NRI. (3) Assumes pad drilling cost. 100% 80% 60% 40% 20% 0% 100% 80% 60% 40% 20% 0% $5 MM $4.75 MM $4.5 MM $4.25 MM $4 MM $50 $60 $70 NYMEX STRIP Osage IRR Sensitivities (2) $4.75 MM $4.5 MM $4.25 MM $4 MM $3.75 MM $50 $60 $70 NYMEX STRIP

10 Regional STACK Overview

11 STACK Overview Mid-Continent Asset Overview Mid-Continent Asset Map ~ 69,400 Core STACK Surface Acres (1) ~ 1,574 Undeveloped Net Drilling Locations (1) Undeveloped STACK Drilling Potential (1) Operated Wells Non-Operated Wells Total Zone Gross Net Gross Net Gross Net Oswego Manning Meramec Osage , Woodford Hunton Total STACK 2,174 1,353 1, ,400 1,574 Large, contiguous acreage position with multiple stacked targets Kingfisher Garfield (1) Acreage and well counts developed by the Company based on assumptions and methodology described on page 3 of this presentation as of 6/30/18. Spacing assumptions: Oswego (4), Manning (4), Meramec (6), Osage (7), Woodford (6) and Hunton (3). 11

12 Mid-Continent STACK Operator Map Note: Rig data obtained from Drillinginfo as of 7/12/18. 12

13 STACK: Significant Multi-Zone Development Up to 30 wells per section Description Operators 13

14 STACK: Meramec

15 Meramec Overview ~ 26,900 Net Prospective Acres(1) 89% Operated (2) and 87% HBP Activity Gross Isopach and Activity Map Operated 26 Operated Wells Drilled 24 Non-Op 18 Participated 16 STACK Activity 800+ wells completed or permitted in the STACK area (3) Undeveloped Potential (1) 448 Gross Wells 228 Net Wells (1) Acreage and drilling locations developed by the Company based on assumptions and methodology described on page 3 of this presentation. Meramec assumes six wells per section. (2) Calculated using prospective net acres as of 6/30/18 and based on assumptions generated by the Company. (3) Based on data obtained from IHS as of 6/30/18. 15

16 Meramec Activity Map Ma Stucki 30-1H Max 30: 227 Boe/d (75% Oil) 4,756 Eff. Lat. Length Geis 31-1H Max 30: 654 Boe/d (70% Oil) 4,706 Eff. Lat. Length Franchise 20-1MH WOC 4,353 Eff. Lat. Length Kramer 29-1H Max 30: 614 Boe/d (81% Oil) 4,194 Eff. Lat. Length Johnny 32-1H Max 30: 396 Boe/d (74% Oil) 2,515 Eff. Lat. Length Sweetness 21-1MH WOC 4,270 Eff. Lat. Length Lilly 28-1H Max 30: 560 Boe/d (85% Oil) 4,254 Eff. Lat. Length Snowden 27-1H Max 30: 517 Boe/d (86% Oil) 4,760 Eff. Lat. Length Eldon 34-1H Max 30: 679 Boe/d (81% Oil) 4,163 Eff. Lat. Length Barney 35-1MH Max 30: 470 Boe/d (66% Oil) 4,904 Eff. Lat. Length High Valley 1UMH-36 Max 30: 652 Boe/d* (52% Oil) 4,588 Lat. Length 31 Stampede 13-1H WOC 4,902 Lat Length Cora MH Max 30: 549 Boe/d (59% Oil) 4,934 Lat Length Preacher Creek 1-14MH Max 30: 184 Boe/d (69% Oil) 4,534 Lat. Length 28 The Cowboy H Max 30: 331 Boe/d (71% Oil) 4,514 Lat. Length 27 Holiday Road 2-1H Max 30: 503 Boe/d (76% Oil) 4,395 Eff. Lat. Length Weber MH Max 30: 597 Boe/d (70% Oil) 4,803 Eff. Lat. Length Ohm 28-1H Max 30: 469 Boe/d (77% Oil) 2,580 Eff. Lat. Length Katy 21-1H Max 30: 373 Boe/d (55% Oil) 4,470 Eff. Lat. Length Ingle 29-1H Max 30: 880 Boe/d (78% Oil) 4,713 Eff. Lat. Length Mott 20-2H Max 30: 686 Boe/d (74% Oil) 4,884 Eff. Lat. Length Deep River 30-1MH Max 30: 970 Boe/d (71% Oil) 4,929 Eff. Lat. Length Mott 19-1H Max 30: 610 Boe/d (68% Oil) 4,382 Eff. Lat. Length Victoria 25-1H Max 30: 447 Boe/d (68% Oil) 3,966 Eff. Lat. Length Bagwell 24-1H Max 30: 679 Boe/d (73% Oil) 4,542 Eff. Lat. Length 11 Homier 36-1MH Max 30: 689 Boe/d (69% Oil) 4,284 Eff. Lat. Length 12 Winfield 31-1MH Max 30: 586 Boe/d (71% Oil) 3,563 Eff. Lat. Length Best 20-1H Max 30: 270 Boe/d (74% Oil) 4,897 Eff. Lat. Length Stitt 32-1H Max 30: 509 Boe/d (79% Oil) 4,916 Eff. Lat. Length Bradbury 28-1H Max 30: 236 Boe/d (77% Oil) 7,243 Eff. Lat. Length Pickle 33-1H Max 30: 408 Boe/d (57% Oil) 4,760 Eff. Lat. Length Note: 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. * Represents three phase. 16

17 Operated Meramec Results Cumulative Oil Production (1) Map of Wells Cum. Oil Production (bbls) 80,000 64,000 48,000 32,000 16, Days Type Curve <30 Stages 30+ Stages Well Count Well Count Cum. Gas Production (Mcf) 210, , ,000 84,000 42,000 0 Cumulative Gas Production (1) Days Type Curve <30 Stages 30+ Stages Well Count (1) Represents production adjusted for downtime and normalized to a lateral length of 4,700. Excludes data from nine wells completed with an inefficient design designated as Gen. 1.0 completions Well Count 17

18 Meramec Economics Type Curve Assumptions/Economics Production Profile Peak Rate (bbl/d) (1 month) Decline Rate 80.5% Terminal Decline 6.0% B-Factor 1.1 Peak Rate (Mcf/d) 400-1,100 (2 months) Decline Rate 60.0% Terminal Decline 5.0% B-Factor 1.1 WOR 2.5 Processing Shrink (% Dry Gas Remaining) 73.0% Yield (bbl/mmcf) 84.3 Residue BTU 1 Operating Costs $ / Well / Month (1 st 12 Months) $11,894 $ / Well / Month (Thereafter) $10,413 Water ($ / Bbl) $1.81 Sales Gas Fee ($/Mcf) (1) $0.96 Differentials Oil ($/Bbl) ($2.00) Gas (% of HH) 75.0% NGL (% of WTI) 42.0% Taxes Severance Tax (1st 3 years) 5.0% Severance Tax (thereafter) 7.0% EUR - Two Phase (MBoe) 463 % Oil 57.6% % Gas 42.4% EUR - Three Phase (MBoe) 511 % Oil 52.1% % Gas 27.6% % NGL 20.3% % Liquids 72.4% Economics (2) Well Costs ($MM) $4.5 IRR 46.2% PV-10 ($MM) $2.3 Daily Rate (Bbl/d Mcf/d) 1, % 80% 60% 40% 20% 0% Meramec Type Curve Month Oil Gas Meramec IRR Sensitivities (2) $5 MM $4.75 MM $4.5 MM $4.25 MM $4 MM $50 $60 $70 NYMEX STRIP (1) Per most recent revenue recognition standards, fee will be applied as a revenue deduct and split between NGLs. Approximately 40% is allocated to NGL and 60% to gas. (2) Assumes $3.00 gas with 100% WI and 78% NRI.. 18

19 STACK: Osage

20 Osage Overview ~ 64,000 Net Prospective Acres(1) 90% Operated (2) and 68% HBP Activity Gross Isopach and Activity Map Operated 27 Operated Wells Drilled 25 Non-Op 33 Participated 28 STACK Activity 500+ wells completed or permitted in the STACK area (3) Undeveloped Locations (1) 1,357 Gross Wells 674 Net Wells (1) Acreage and drilling locations developed by the Company based on assumptions and methodology described on page 3 of this presentation. Osage assumes seven wells per section. (2) Calculated using prospective net acres as of 6/30/18 and based on assumptions generated by the Company. (3) Based on data obtained from IHS as of 6/30/18. 20

21 Osage Activity Map Gary Hajek 18-1LOH Max 30: 246 Boe/d (60% Oil) 4,628 Eff. Lat. Length Dizzy 17-1LOH Max 30: 447 Boe/d (56% Oil) 4,258 Eff. Lat. Length 1 2 Maral H Max 30: 507 Boe/d (79% Oil) 4,722 Lat Length Jesse H Max 30: 1,191 Boe/d (73% Oil) 5,336 Lat. Length Flying Monkey MH Producing 4,945 Lat. Length Lankard MH Max 30: 1,585 Boe/d (69% Oil) 4,855 Lat. Length Ash MH Max 30: 852 Boe/d 4,810 Lat. Length Schilde MH Max 30: 831 Boe/d (80% Oil) 4,966 Lat. Length 24 Borelli MH Max 30: 1,200 Boe/d (72% Oil) 4,845 Lat. Length Biggio LOH Max 30: 1,020 Boe/d (31% Oil) 4,919 Eff. Lat. Length 3 Hoskins MH Max 30: 637 Boe/d 4,693 Lat. Length 23 Dr J UOH Max 30: 716 Boe/d (67% Oil) 4,433 Eff. Lat. Length 4 Fazio MH Max 30: 909 Boe/d (73% Oil) 4,436 Lat. Length 22 Yogi 8-1UOH Max 30: 384 Boe/d (67% Oil) 4,620 Eff. Lat. Length 5 Oltmanns MH Max 30: 787 Boe/d 4,930 Lat. Length 21 Willie LOH Initial Flowback 4,811 Eff. Lat. Length 6 Vadder MH Max 30: 616 Boe/d 4,504 Lat. Length 20 Pribil 21-1H Max 30: 669 Boe/d (75% Oil) 4,064 Eff. Lat. Length 7 McNulty MH Max 30: 778 Boe/d 4,858 Lat. Length 19 Mack LOH Max 30: 286 Boe/d (79% Oil) 4,247 Eff. Lat. Length Milacek 27-1H (1) Max 30: 376 Boe/d (81% Oil) 3,140 Eff. Lat. Length Broadhead 34-1H Max 30: 317 Boe/d (90% Oil) 4,412 Eff. Lat. Length Pollard Farm 7-1LOH Max 30: 389 Boe/d (67% Oil) 4,685 Eff. Lat. Length Barr 35-1LOH Max 30: 782 Boe/d (69% Oil) 3,890 Eff. Lat. Length Farrar MH-6 Max 30: 613 Boe/d (76% Oil) 4,854 Lat. Length Towne MH Max 30: 834 Boe/d (91% Oil) 4,793 Lat. Length Low Valley 1LMH Farber MH-6 (2) Fuksa 2007 #1LMH-14 (2) Bugabago 1-31MH Max 30: 1,174 Boe/d (73% Oil) 4,925 Lat. Length Max 30: 509 Boe/d (85% Liq) 4,129 Lat Length Max 30: 710 Boe/d (83% Liq) 4,087 Lat Length Max 30: 678 Boe/d (71% Oil) 5,054 Lat. Length Note: 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. (1) Mechanically Impaired. (2) Represents three phase. 21

22 Operated Osage Results Cumulative Oil Production (1) Map of Wells Cum. Oil Production (bbls) 60,000 48,000 36,000 24, , Days Type Curve Gen 3.0, 35 stage spacing Gen 3.0, <35 stage spacing Well Count Cumulative Gas Production (1) Well Count 200, Cum. Gas Production (Mcf) 160, ,000 80, , Days Type Curve Gen 3.0, 35 Stage spacing Gen 3.0, <35 Stage spacing Well Count (1) Represents production adjusted for downtime and normalized to a lateral length of 4,700. Excludes data from seven wells completed with an inefficient design. 12 Well Count 22

23 Osage Economics Type Curve Assumptions/Economics Osage Type Curve Production Profile Peak Rate (bbl/d) (2 months) Decline Rate 79.0% Terminal Decline 6.0% B-Factor 1.2 Peak Rate (Mcf/d) (3 months) Decline Rate 60.0% Terminal Decline 5.0% B-Factor 1.2 WOR (Year 1-3) 2.5 WOR (Thereafter) 2.0 Processing Shrink (% Dry Gas Remaining) 73.0% Yield (bbl/mmcf) 84.3 Residue BTU 1 Operating Costs $ / Well / Month $11,894 $ / Well / Month $10,413 Water ($ / Bbl) $1.81 Sales Gas Fee ($/Mcf) (1) $0.96 Differentials Oil ($/Bbl) ($2.00) Gas (% of HH) 75.0% NGL (% of WTI) 42.0% Taxes Severance Tax (1st 3 years) 5.0% Severance Tax (thereafter) 7.0% EUR - Two Phase (MBoe) 444 % Oil 58.0% % Gas 42.0% EUR - Three Phase (MBoe) 489 % Oil 53.0% % Gas 27.1% % NGL 19.8% % Liquids 72.9% Economics (2) Well Costs ($MM) $4.0 IRR 44.8% PV-10 ($MM) $2.2 (1) Per most recent revenue recognition standards, fee will be applied as a revenue deduct and split between NGLs. Approximately 40% is allocated to NGL and 60% to gas. (2) Assumes $3.00 gas with 100% WI and 78% NRI. Daily Rate (Bbl/d Mcf/d) 1, % 80% 60% 40% 20% 0% Month Oil Gas Osage IRR Sensitivities (2) $4.75 MM $4.5 MM $4.25 MM $4 MM $3.75 MM $50 $60 $70 NYMEX STRIP

24 Additional Upside

25 Oswego Overview ~ 16,300 Net Prospective Acres(1) 73% Operated (2) and 69% HBP Activity Net Isopach and Activity Map Operated 1 Operated Well Drilled 1 Non-Op 11 Participated 10 STACK Activity 130+ wells completed or permitted in the STACK area (3) Undeveloped Potential (1) 262 Gross Wells 99 Net Wells (1) Acreage and drilling locations developed by the Company based on assumptions and methodology described on page 3 of this presentation. Oswego assumes four wells per section. (2) Calculated using prospective net acres as of 6/30/18 and based on assumptions generated by the Company. (3) Based on data obtained from IHS as of 6/30/18. 25

26 Woodford Overview ~ 17,700 Net Prospective Acres(1) 84% Operated (2) and 52% HBP Activity Gross Isopach and Activity Map Non-Op 5 Participated 5 STACK Activity 250+ wells completed or permitted in the STACK area (3) Chisholm Trail W IP 30day Avg: 1,600 Boe/d Undeveloped Potential (1) 381 Gross Wells 166 Net Wells Laura 1H-17X* IP 30day Avg: 1,326 Boe/d (66% Oil) * IP Denotes three stream rate (oil / gas / NGLs) (1) Acreage and drilling locations developed by the Company based on assumptions and methodology described on page 3 of this presentation. Woodford assumes six wells per section. (2) Calculated using prospective net acres as of 6/30/18 and based on assumptions generated by the Company. (3) Based on data obtained from IHS as of 6/30/18. 26

27 Hunton Overview ~ Operated 40,200 Net Prospective Acres(1) 86% Operated (2) and 77% HBP Activity 41 Operated Wells Drilled 41 Gross Isopach and Activity Map The River 01-22H Max 30: 1,182 Boe/d (43% oil) 3,897 Lat. Length Thrasher 01-01H Max 30: 1,274 Boe/d (75% oil) 4,832 Lat. Length Non-Op 1 Participated 1 Kodiak 01-29H Max 30: 1,322 Boe/d (83% oil) 4,570 Lat. Length STACK Activity 69+ wells completed in the STACK area (3) Undeveloped Potential (1) Shimanek 01-02H Max 30: 1,527 Boe/d (75% oil) 4,411 Lat. Length School Land 01-36H Max 30: 1,353 Boe/d (62% oil) 4,261 Lat. Length 357 Gross Wells 163 Net Wells (1) Acreage and drilling locations developed by the Company based on assumptions and methodology described on page 3 of this presentation. Hunton assumes three wells per section. (2) Calculated using prospective net acres as of 6/30/18 and based on assumptions generated by the Company. (3) Based on data obtained from IHS as of 6/30/18. 27

28 Manning Overview ~ 39,100 Net Prospective Acres(1) 78% Operated (2) and 69% HBP Activity Historical vertical well production from the Manning shows to be a prolific formation Nearby operator commenced horizontal drilling in 2017 ~400 shallower than Meramec Quartz-rich carbonate with high porosity stringers Majority of acreage position has greater than 100 of gross Manning thickness Log data indicates reservoir is fractured similar to Meramec and Osage Undeveloped Potential (1) Manning Gross Isopach 595 Gross Wells 244 Net Wells (1) Acreage and drilling locations developed by the Company based on assumptions and methodology described on page 3 of this presentation. Manning assumes four wells per section. (2) Calculated using prospective net acres as of 6/30/18 and based on assumptions generated by the Company. 28

29 Oswego Fracture Overview The Oswego formation blankets 100% of Gastar s acreage Gross Isopach Map Gross Oswego thickness ranges from 150 to 275 feet thick across the position Well data indicates the Oswego is fractured and is self-sourced from TOC-rich shale stringers Upside potential utilizing larger completion techniques as 2017 Gastar Exploration Inc. in Meramec and Osage plays 29

30 Appendix

31 Type Curve Assumptions Formation Meramec Osage Production Profile Peak Rate (Bbl/d) (1 month) (2 months) Decline Rate 80.5% 79.0% Terminal Decline 6.0% 6.0% B-Factor Peak Rate (Mcf/d) 400-1,100 (2 months) (3 months) Decline Rate 60.0% 60.0% Terminal Decline 5.0% 5.0% B-Factor WOR (Year 1-3) WOR (Thereafter) Processing Shrink (% Dry Gas Remaining) 73.0% 73.0% Yield (bbl/mmcf) Residue BTU 1 1 Operating Costs $ / Well / Month (1 st 12 Months) $11,894 $11,894 $ / Well / Month (Thereafter) $10,413 $10,413 Water ($ / Bbl) $1.81 $1.81 Sales Gas Fee ($/Mcf) (1) $0.96 $0.96 Differentials Oil ($/Bbl) ($2.00) ($2.00) Gas (% of HH) 75.0% 75.0% NGL (% of WTI) 42.0% 42.0% Taxes Severance Tax (1st 3 years) 5.0% 5.0% Severance Tax (thereafter) 7.0% 7.0% EUR - Three Phase (MBoe) % Oil 52.1% 53.0% % Gas 27.6% 27.1% % NGL 20.3% 19.8% % Liquids 72.4% 72.9% Well Cost Drilling & Completion Costs ($MM) $4.5 $4.0 (1) Per most recent revenue recognition standards, fee will be applied as a revenue deduct and split between NGLs (40%) and gas (60%). 31

32 Earthquake Seismicity Map As of 4/1/18, Gastar has implemented a 24/7 surveillance of seismicity events during company operated completions in Kingfisher Co(OCC area of Interest) Gastar has also implemented a protocol addressing the appropriate response to any seismic events detected above 2.0 magnitude during completion activities The industry has been recompleting into the Wilcox to mitigate seismic concerns of disposing in the Arbuckle Gastar uses third parties for a majority of water disposal Contracts for transportation and disposal at fixed $/bbl Number of Earthquakes per Year OK Earthquake Magnitude > 3.0 ~1.6/ yr Low seismicity around Gastar leasehold USGS EARTHQUAKE DATA FROM 1/1/ /26/2018 MAGNITUDE OF 2.0 OR GREATER Nemaha Ridge Year Source: USGS-NEIC ComCat & Oklahoma Geological Survey; Preliminary as of July 4,

33 PDP Hedging Program Oil and NGLs Hedging Strategy Crude Oil (1) Q (2) Q FY 2018 Q Q Q Q FY 2019 Upside Hedges (Bbl/d) 2,813 2,800 2,806 2,700 2,700 2,700 2,439 2,635 Downside Hedges (Bbl/d) 2,813 2,800 2,806 2,700 2,700 2,700 2,439 2,635 Average Ceiling $57.94 $57.10 $57.52 $57.29 $57.29 $57.29 $57.66 $57.38 Average Floor $52.01 $50.81 $51.41 $48.25 $48.25 $48.25 $48.14 $48.22 % Hedged 89% 100%+ 99% 100%+ 100%+ 100%+ 100%+ 100%+ Gas Hedging Strategy Gas Q (2) Q FY 2018 Upside Hedges (Mcf/d) 6,550 6,550 6,550 Downside Hedges (Mcf/d) 6,550 6,550 6,550 Average Ceiling $3.77 $3.77 $3.77 Average Floor $3.00 $3.00 $3.00 % Hedged 60.1% 67.1% 64.1% Note: hedges as of 7/22/18. Average floor price represents average floor of swap and long put. (1) Hedgeable oil includes heavy NGL barrel uplift, calculated as 35% of total NGL barrel. Q3 18 excludes July. (2) Does not include the month of July. 33

34 Realized Prices: STACK $80.00 $64.00 $48.00 $32.00 $16.00 Realized Oil Prices 97% 98% $63.90 $ % 88% 66% 44% 22% $5.00 $4.00 $3.00 $2.00 $1.00 Realized Gas Prices (1) 91% 78% $2.70 $2.27 $2.20 $ % 80% 60% 40% 20% $0.00 $45.00 $36.00 $27.00 $ YTD 2018 % of NYMEX (post-treat/gath) Realized Price (Post-treat/gath) Realized NGL Price (1) 47% 0% 50% 39% 40% $23.96 $ % $20.89 $ % $0.00 $60.00 $48.00 $36.00 $ YTD 2018 % of HH (pre-treat/gath) Realized Price (pre-treat/gath) Realized Price (post-treat/gath) Realized Boe Price 66% $33.84 $ % $40.81 $ % 80% 64% 48% 32% $ % $ % $ YTD 2018 % of NYMEX (pre-treat/gath) Realized Price (pre-treat/gath) Realized Price (post-treat/gath) 0% $ YTD 2018 % of NYMEX (pre-treat/gath) Realized Price (pre-treat/gath) Realized Price (post-treat/gath) 0% (1) 2017 realized prices reduced for transport fees allocated between gas (60%) and NGLs (40%). Represents $0.50/Mcf for gas and $3.07/Bbl for NGLs. 34

35 Production Costs ($/Boe): STACK $12.00 $9.60 Lease Operating Expense $9.86 $9.97 $0.33 $0.44 $1.20 Production Tax $1.10 $1.12 $7.20 $4.80 $9.53 $9.53 $1.05 $2.40 $ YTD 2018 LOE Workover $ YTD 2018 (1) Total Direct Costs vs. Daily Production $ ,000 $5.00 Revenue Deducts (1) ($/Boe) $12.00 $9.00 $6.00 $10.96 $11.09 $0.33 $0.44 5,597 ($0.01) 3,161 8,000 6,000 4,000 (Boe/d) $4.00 $3.00 $2.00 $3.07 $4.17 $3.00 $0.00 $10.63 $ YTD ,000 0 Total Direct Costs Workover Daily Production $1.00 $0.00 $0.50 $ YTD 2018 Gas Revenue Deduct ($/mcf) NGL Revenue Deduct ($/bbl) (1) 2018 represents values that reduce reported revenue per new revenue recognition standard reported as expense, shown for comparison only. 35