Exhibit 99.2 Business Plan Overview November 6, 2018 1 Seaport Global Securities LLC. Member FINRA/SIPC.Exhibit 99.2 Business Plan Overview November 6, 2018 1 Seaport Global Securities LLC. Member FINRA/SIPC.

Disclaimer This presentation may contain confidential information of PetroQuest Energy, Inc. and its subsidiaries (collectively, “we,” “our,” “us,” and the Company”) that is being provided pursuant to that certain confidentiality agreement between you and the Company. By accepting and reviewing this presentation, you expressly acknowledge and agree that any confidential information herein will be treated in accordance with such confidentiality agreement. This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included or incorporated by reference in this presentation are forward-looking statements. Forward-looking statements may be found in this presentation regarding our financial position, business strategy, production and reserve growth, possible or assumed future results of operations, and other plans and objectives for our future operations. All forward-looking statements are made as of the date of the document containing the applicable statement, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this presentation. Forward-looking statements are subject to risks and uncertainties. Although we believe that in making such statements our expectations are based on reasonable assumptions, such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will,” “would,” “should,” “plans,” “likely,” “expects,” “anticipates,” “intends,” “believes,” “estimates,” “thinks,” “may,” “seek,” “achievable,” “projects” and similar expressions, are forward-looking statements. All written and oral forward-looking statements attributable to us are expressly qualified in their entirety by such factors. For a more detailed discussion of risk factors, please see, Item 1A, “Risk Factors” of the Company’s most recent Annual Report on Form 10-K, or most recent Quarterly Report on Form 10-Q filed with the U.S. Securities and Exchange Commission. Any financial projections or forecasts included in this presentation were not prepared with a view toward public disclosure or compliance with the published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants regarding projections or forecasts. The projections do not purport to present the Company's financial condition in accordance with accounting principles generally accepted in the United States. The Company's independent accountants have not examined, compiled or otherwise applied procedures to the projections and, accordingly, do not express an opinion or any other form of assurance with respect to the projections. The inclusion of the projections should not be regarded as an indication that the Company or its affiliates or representatives consider the projections to be a reliable prediction of future events, and the projections should not be relied upon as such. Neither the Company nor any of its affiliates or representatives has made or makes any representation or warranty, express or implied or at law or at equity, in connection with any of the information made available herein or subsequent to this presentation, including, but not limited to, the anticipated cash flows, income, costs, expenses, liabilities, and profits, if any, of the Company, and none of them undertakes any obligation to publicly update the projections to reflect circumstances existing after the date when the projections were made or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying the projections are shown to be in error. The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. The Company does not plan to include probable and possible reserve estimates in its filings with the SEC. The Company has provided internally generated estimates that have not been audited by its third party reserve engineer in this presentation. The Company estimate of proved, probable and possible reserves is provided in this presentation because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. In addition, we use the terms “inventory,” “EUR,” “wellhead EUR, “sales EUR,” “2P reserves,” “3P reserves” or other descriptions of volumes of hydrocarbons to describe volumes of resources potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines prohibit us from including in filings with the SEC. Estimates of inventory, EUR, wellhead EUR, sales EUR, 2P reserves and 3P reserves do not reflect volumes that are demonstrated as being commercially or technically recoverable. Even if commercially or technically recoverable, a significant recovery factor would be applied to these volumes to determine estimates of volumes of proved reserves. Accordingly, these estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. The methodology for estimating inventory, EUR, wellhead EUR, sales EUR, 2P reserves and 3P reserves may also be different than the methodology and guidelines used by the Society of Petroleum Engineers and is different from the SEC’s guidelines for estimating probable and possible reserves. 2 Seaport Global Securities LLC. Member FINRA/SIPC.Disclaimer This presentation may contain confidential information of PetroQuest Energy, Inc. and its subsidiaries (collectively, “we,” “our,” “us,” and the Company”) that is being provided pursuant to that certain confidentiality agreement between you and the Company. By accepting and reviewing this presentation, you expressly acknowledge and agree that any confidential information herein will be treated in accordance with such confidentiality agreement. This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included or incorporated by reference in this presentation are forward-looking statements. Forward-looking statements may be found in this presentation regarding our financial position, business strategy, production and reserve growth, possible or assumed future results of operations, and other plans and objectives for our future operations. All forward-looking statements are made as of the date of the document containing the applicable statement, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this presentation. Forward-looking statements are subject to risks and uncertainties. Although we believe that in making such statements our expectations are based on reasonable assumptions, such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will,” “would,” “should,” “plans,” “likely,” “expects,” “anticipates,” “intends,” “believes,” “estimates,” “thinks,” “may,” “seek,” “achievable,” “projects” and similar expressions, are forward-looking statements. All written and oral forward-looking statements attributable to us are expressly qualified in their entirety by such factors. For a more detailed discussion of risk factors, please see, Item 1A, “Risk Factors” of the Company’s most recent Annual Report on Form 10-K, or most recent Quarterly Report on Form 10-Q filed with the U.S. Securities and Exchange Commission. Any financial projections or forecasts included in this presentation were not prepared with a view toward public disclosure or compliance with the published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants regarding projections or forecasts. The projections do not purport to present the Company's financial condition in accordance with accounting principles generally accepted in the United States. The Company's independent accountants have not examined, compiled or otherwise applied procedures to the projections and, accordingly, do not express an opinion or any other form of assurance with respect to the projections. The inclusion of the projections should not be regarded as an indication that the Company or its affiliates or representatives consider the projections to be a reliable prediction of future events, and the projections should not be relied upon as such. Neither the Company nor any of its affiliates or representatives has made or makes any representation or warranty, express or implied or at law or at equity, in connection with any of the information made available herein or subsequent to this presentation, including, but not limited to, the anticipated cash flows, income, costs, expenses, liabilities, and profits, if any, of the Company, and none of them undertakes any obligation to publicly update the projections to reflect circumstances existing after the date when the projections were made or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying the projections are shown to be in error. The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. The Company does not plan to include probable and possible reserve estimates in its filings with the SEC. The Company has provided internally generated estimates that have not been audited by its third party reserve engineer in this presentation. The Company estimate of proved, probable and possible reserves is provided in this presentation because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. In addition, we use the terms “inventory,” “EUR,” “wellhead EUR, “sales EUR,” “2P reserves,” “3P reserves” or other descriptions of volumes of hydrocarbons to describe volumes of resources potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines prohibit us from including in filings with the SEC. Estimates of inventory, EUR, wellhead EUR, sales EUR, 2P reserves and 3P reserves do not reflect volumes that are demonstrated as being commercially or technically recoverable. Even if commercially or technically recoverable, a significant recovery factor would be applied to these volumes to determine estimates of volumes of proved reserves. Accordingly, these estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. The methodology for estimating inventory, EUR, wellhead EUR, sales EUR, 2P reserves and 3P reserves may also be different than the methodology and guidelines used by the Society of Petroleum Engineers and is different from the SEC’s guidelines for estimating probable and possible reserves. 2 Seaport Global Securities LLC. Member FINRA/SIPC.

Business Plan Overview 3 Seaport Global Securities LLC. Member FINRA/SIPC.Business Plan Overview 3 Seaport Global Securities LLC. Member FINRA/SIPC.

Business Plan and Global Assumptions Global Operational Assumptions: Strip pricing for oil and natural gas as of 11/5/2018 Pricing Cotton Valley average oil differentials of +$0.17 / BBL off WTI, average gas differentials of -$0.01 / MCF Austin Chalk average oil differentials of +$2.61 / BBL off WTI, average gas and NGLs are 100% flared Cotton Valley: $0.90 - $1.10 per MCFE LOE Austin Chalk: $1.75 per BBL, $0.59 per MCF, $50K net per month per well Cotton Valley: 4.6% for oil; 4.5% for NGL and Gas; $0.00067 per MCF Production Taxes Austin Chalk: 12.5% for oil (24 month severance tax exemption on each well drilled); $0.015 per BBL; $0.114 per MCF; 1.0% Ad Valorem on all revenue G&A $16.1MM for 2019 (includes $5.1MM of capitalized G&A), increases 5% annually thereafter Cotton Valley: Drilling: $3.2MM Avg. Gross; Completion: $2.4MM Avg. Gross; Flowback: $550K Gross; Casing: $175K Gross (1 year after first spud) CapEx Austin Chalk: Drilling: $2.9MM Gross per well; Completion: $2.9MM Gross per well; Flowback: $2.9MM Gross per well; Casing: $175K Gross per well (1 year after first spud); Facilities: $1.2MM (75% on first well, 25% on second well); SWD: $800K Capitalized G&A: $6.3MM per year Cotton Valley: Avg Lateral length: 6,400’; EUR: ~7,300 Mmcfe; Avg 30-Day IP Rate: 11.1 Mmcfe/d; Production Mix: 7% Oil / Type Curve (Unrisked) 93% gas & NGLs Austin Chalk: Avg EUR: ~730 Mboe; Avg 30-Day IP Rate: 2.6 Mboe/d; Production Mix: 83% Oil / 17% gas & NGLs Cotton Valley: 95% Production Risking Austin Chalk: 60% Cotton Valley: 76% (includes existing JV, before additional JV / sell-down) Avg Working Interest Austin Chalk: 79% (includes existing JV, before additional JV / sell-down) D&C Timing 10-13 wells per rig per year Capital Assumptions: Interest Rates 6.25% (assuming LIBOR grid based pricing) Austin Chalk sell down (avg WI declines from 79% to 54% on all future wells) Joint Venture Cotton Valley sell down (avg WI declines from 76% to 51% on all future wells; JV partners pay 30% D&C costs) 4 Seaport Global Securities LLC. Member FINRA/SIPC.Business Plan and Global Assumptions Global Operational Assumptions: Strip pricing for oil and natural gas as of 11/5/2018 Pricing Cotton Valley average oil differentials of +$0.17 / BBL off WTI, average gas differentials of -$0.01 / MCF Austin Chalk average oil differentials of +$2.61 / BBL off WTI, average gas and NGLs are 100% flared Cotton Valley: $0.90 - $1.10 per MCFE LOE Austin Chalk: $1.75 per BBL, $0.59 per MCF, $50K net per month per well Cotton Valley: 4.6% for oil; 4.5% for NGL and Gas; $0.00067 per MCF Production Taxes Austin Chalk: 12.5% for oil (24 month severance tax exemption on each well drilled); $0.015 per BBL; $0.114 per MCF; 1.0% Ad Valorem on all revenue G&A $16.1MM for 2019 (includes $5.1MM of capitalized G&A), increases 5% annually thereafter Cotton Valley: Drilling: $3.2MM Avg. Gross; Completion: $2.4MM Avg. Gross; Flowback: $550K Gross; Casing: $175K Gross (1 year after first spud) CapEx Austin Chalk: Drilling: $2.9MM Gross per well; Completion: $2.9MM Gross per well; Flowback: $2.9MM Gross per well; Casing: $175K Gross per well (1 year after first spud); Facilities: $1.2MM (75% on first well, 25% on second well); SWD: $800K Capitalized G&A: $6.3MM per year Cotton Valley: Avg Lateral length: 6,400’; EUR: ~7,300 Mmcfe; Avg 30-Day IP Rate: 11.1 Mmcfe/d; Production Mix: 7% Oil / Type Curve (Unrisked) 93% gas & NGLs Austin Chalk: Avg EUR: ~730 Mboe; Avg 30-Day IP Rate: 2.6 Mboe/d; Production Mix: 83% Oil / 17% gas & NGLs Cotton Valley: 95% Production Risking Austin Chalk: 60% Cotton Valley: 76% (includes existing JV, before additional JV / sell-down) Avg Working Interest Austin Chalk: 79% (includes existing JV, before additional JV / sell-down) D&C Timing 10-13 wells per rig per year Capital Assumptions: Interest Rates 6.25% (assuming LIBOR grid based pricing) Austin Chalk sell down (avg WI declines from 79% to 54% on all future wells) Joint Venture Cotton Valley sell down (avg WI declines from 76% to 51% on all future wells; JV partners pay 30% D&C costs) 4 Seaport Global Securities LLC. Member FINRA/SIPC.

Model Assumption and Output Summary Take-Back Debt Strip Pricing Notes 1 Cotton Valley Rig Running 2018 2019 2020 2021 Average Realized Pricing • High level assumptions: Oil ($ / Bbl) 67.71 65.83 64.11 61.66 - 1 rig program starting 11/8/2018 with JV in Gas ($ / Mcf) 3.06 2.88 2.66 2.59 place beginning on third well NGL ($ / Bbl) 27.89 25.84 25.75 25.51 - Austin Chalk development begins 7/1/2019 Total Gross Wells 3.0 10.0 13.0 13.0 drilling 2 wells per year from 2020 on Cumulative Gross Wells 3.0 13.0 26.0 39.0 Production Total Production (Mcfe) 20,742.4 18,774.1 21,495.2 22,312.2 Daily Production (Mmcfe/d) 56.8 51.4 58.7 61.1 EBITDA 44,293.3 39,967.6 47,698.6 48,061.7 Capex (17,527.8) (37,999.1) (37,474.0) (40,608.0) Capitalized G&A (5,875.5) (5,135.8) (5,205.8) (5,205.8) Proceeds from Acreage Selldow ns -- 35,500.0 -- -- Change in WC (20,500.4) (3,547.3) 3,615.0 181.7 Other Income (Expenses) 9,577.5 3,500.0 -- -- Unlevered FCF 9,967.1 32,285.4 8,633.8 2,429.7 Less: Legal & Restructuring Costs (11,781.1) -- -- -- Less: Interest Expense (5,741.3) (2,007.3) (472.6) (225.0) Levered FCF (7,555.3) 30,278.1 8,161.2 2,204.7 Liquidity Borrow ing Base / Commitments 50,000.0 50,000.0 55,000.0 60,000.0 Amount Debt Outstanding (50,000.0) (11,841.7) (3,680.5) (1,475.8) Availibility -- 38,158.3 51,319.5 58,524.2 Plus: Cash 12,880.3 5,000.0 5,000.0 5,000.0 Liquidity 12,880.3 43,158.3 56,319.5 63,524.2 Unit Analysis Sales 4.07 3.85 3.77 3.70 Taxes (0.16) (0.20) (0.16) (0.15) LOE (1.01) (0.93) (0.85) (0.85) G&A (0.76) (0.59) (0.54) (0.54) EBITDA 2.14 2.13 2.22 2.15 5 Seaport Global Securities LLC. Member FINRA/SIPC.Model Assumption and Output Summary Take-Back Debt Strip Pricing Notes 1 Cotton Valley Rig Running 2018 2019 2020 2021 Average Realized Pricing • High level assumptions: Oil ($ / Bbl) 67.71 65.83 64.11 61.66 - 1 rig program starting 11/8/2018 with JV in Gas ($ / Mcf) 3.06 2.88 2.66 2.59 place beginning on third well NGL ($ / Bbl) 27.89 25.84 25.75 25.51 - Austin Chalk development begins 7/1/2019 Total Gross Wells 3.0 10.0 13.0 13.0 drilling 2 wells per year from 2020 on Cumulative Gross Wells 3.0 13.0 26.0 39.0 Production Total Production (Mcfe) 20,742.4 18,774.1 21,495.2 22,312.2 Daily Production (Mmcfe/d) 56.8 51.4 58.7 61.1 EBITDA 44,293.3 39,967.6 47,698.6 48,061.7 Capex (17,527.8) (37,999.1) (37,474.0) (40,608.0) Capitalized G&A (5,875.5) (5,135.8) (5,205.8) (5,205.8) Proceeds from Acreage Selldow ns -- 35,500.0 -- -- Change in WC (20,500.4) (3,547.3) 3,615.0 181.7 Other Income (Expenses) 9,577.5 3,500.0 -- -- Unlevered FCF 9,967.1 32,285.4 8,633.8 2,429.7 Less: Legal & Restructuring Costs (11,781.1) -- -- -- Less: Interest Expense (5,741.3) (2,007.3) (472.6) (225.0) Levered FCF (7,555.3) 30,278.1 8,161.2 2,204.7 Liquidity Borrow ing Base / Commitments 50,000.0 50,000.0 55,000.0 60,000.0 Amount Debt Outstanding (50,000.0) (11,841.7) (3,680.5) (1,475.8) Availibility -- 38,158.3 51,319.5 58,524.2 Plus: Cash 12,880.3 5,000.0 5,000.0 5,000.0 Liquidity 12,880.3 43,158.3 56,319.5 63,524.2 Unit Analysis Sales 4.07 3.85 3.77 3.70 Taxes (0.16) (0.20) (0.16) (0.15) LOE (1.01) (0.93) (0.85) (0.85) G&A (0.76) (0.59) (0.54) (0.54) EBITDA 2.14 2.13 2.22 2.15 5 Seaport Global Securities LLC. Member FINRA/SIPC.

Cotton Valley Overview 6 Seaport Global Securities LLC. Member FINRA/SIPC.Cotton Valley Overview 6 Seaport Global Securities LLC. Member FINRA/SIPC.

PQ Land and Well Position South East Carthage Chronology Acreage • 2003: PQ acquired ~50% interest in 45,354 acres operated by Chevron in the Southeast Carthage Field, limited from the top of the Travis Peak, through the Cotton Valley and to the bottom of the Bossier Shale • 2005 - Present: PQ acquired an additional 8,891 gross operated acres, for a total of 54,245 acres Wells • 2003: Acquired interest in 89 Chevron operated vertical wells drilled by UPRC and Addington • 2004 - 2008: PQ drilled 49 vertical wells targeting the Cotton Valley and Travis Peak • 2009 - 2010: PQ participated in the drilling of 7 non-operated horizontal CV wells and 1 non-operated Bossier Shale well • 2011 - Present: PQ drilled 30 very successful hzl CV wells averaging 7.2 Bcfe EUR. • Current Wells: - Count – 210 (41 horizontals and 169 verticals) - Status – 101 producing, 69 shut-in, 11 transferred, 29 plugged - Avg. Prod. Ownership – 63.0 W.I., 50.2% NRI (79.3% net to 100% W.I.) Current PetroQuest JV I and II Acreage rd 3 Party Leasehold PQ / CVX Acreage* Existing Vertical Wells Existing Horizontal Wells *PQ Operates Drilling and Completion of all joint wells. 7 Seaport Global Securities LLC. Member FINRA/SIPC.PQ Land and Well Position South East Carthage Chronology Acreage • 2003: PQ acquired ~50% interest in 45,354 acres operated by Chevron in the Southeast Carthage Field, limited from the top of the Travis Peak, through the Cotton Valley and to the bottom of the Bossier Shale • 2005 - Present: PQ acquired an additional 8,891 gross operated acres, for a total of 54,245 acres Wells • 2003: Acquired interest in 89 Chevron operated vertical wells drilled by UPRC and Addington • 2004 - 2008: PQ drilled 49 vertical wells targeting the Cotton Valley and Travis Peak • 2009 - 2010: PQ participated in the drilling of 7 non-operated horizontal CV wells and 1 non-operated Bossier Shale well • 2011 - Present: PQ drilled 30 very successful hzl CV wells averaging 7.2 Bcfe EUR. • Current Wells: - Count – 210 (41 horizontals and 169 verticals) - Status – 101 producing, 69 shut-in, 11 transferred, 29 plugged - Avg. Prod. Ownership – 63.0 W.I., 50.2% NRI (79.3% net to 100% W.I.) Current PetroQuest JV I and II Acreage rd 3 Party Leasehold PQ / CVX Acreage* Existing Vertical Wells Existing Horizontal Wells *PQ Operates Drilling and Completion of all joint wells. 7 Seaport Global Securities LLC. Member FINRA/SIPC.

465 CV Horizontal Wells Drilled Surrounding PQ Acreage (30 wells drilled) (7 wells) / (106 wells) (148 wells) / (69 wells) PQ Oper. Acreage / CVX Co-owned (115 wells) rd 3 -Party Leasehold 8 Seaport Global Securities LLC. Member FINRA/SIPC.465 CV Horizontal Wells Drilled Surrounding PQ Acreage (30 wells drilled) (7 wells) / (106 wells) (148 wells) / (69 wells) PQ Oper. Acreage / CVX Co-owned (115 wells) rd 3 -Party Leasehold 8 Seaport Global Securities LLC. Member FINRA/SIPC.

Current Offset Activity Commentary • 18 Haynesville and 6 Cotton Valley operators currently drilling 9 Seaport Global Securities LLC. Member FINRA/SIPC.Current Offset Activity Commentary • 18 Haynesville and 6 Cotton Valley operators currently drilling 9 Seaport Global Securities LLC. Member FINRA/SIPC.

Cotton Valley Formation Overview Cotton Valley Formation Numerous Lessons Learned About the Cotton Valley • The Cotton Valley is a low risk horizontal target with repeatable high • Sonic Log Data - Dipole sonic log provided rock strength understanding returns which helped correlate our micro-seismic data and optimize the drill bits for more efficient drilling • PQ has continually improved EURs, while lowering drilling and completion costs • Micro-Seismic Data - Revealing gaps of unfractured space between stages which prompted us to minimize the spacing between stages. It • The current environment offers commodity price upside and more also confirmed the minimal spacing to avoid the interference from opportunities for cost cutting adjacent horizontal wells. • The majority of the PQ acreage is held by production. Significant • Gas Tracer Data - Gas tracer technology showed us the producing takeaway capacity is currently available through existing pipelines and contribution of each frac stage in a horizontal well. We saw all stages facilities contributed and the entire well bore effectively produced. • Optimized Reserves - Identified reserve recovery increased directly with longer laterals, so maximize lateral lengths through multi-unit wells and reverse drilling. Saw improved performance from keeping the horizontal well path in the zone of highest porosity. • Optimized Hydraulic Fractures - We tested larger fracks in PQ 25, compared to PQ 23 and concluded the slightly higher rates do not provide sufficient economic benefit to offset the additional cost Last Two Wells Completed in 2018 • PQ #29 (Wiener Owen #3H) initial 24 hour producing 10,794 Mcfe/d • PQ #30 (Wiener #1H) initial 24 hour producing 15,371 Mcfe/d 10 Seaport Global Securities LLC. Member FINRA/SIPC.Cotton Valley Formation Overview Cotton Valley Formation Numerous Lessons Learned About the Cotton Valley • The Cotton Valley is a low risk horizontal target with repeatable high • Sonic Log Data - Dipole sonic log provided rock strength understanding returns which helped correlate our micro-seismic data and optimize the drill bits for more efficient drilling • PQ has continually improved EURs, while lowering drilling and completion costs • Micro-Seismic Data - Revealing gaps of unfractured space between stages which prompted us to minimize the spacing between stages. It • The current environment offers commodity price upside and more also confirmed the minimal spacing to avoid the interference from opportunities for cost cutting adjacent horizontal wells. • The majority of the PQ acreage is held by production. Significant • Gas Tracer Data - Gas tracer technology showed us the producing takeaway capacity is currently available through existing pipelines and contribution of each frac stage in a horizontal well. We saw all stages facilities contributed and the entire well bore effectively produced. • Optimized Reserves - Identified reserve recovery increased directly with longer laterals, so maximize lateral lengths through multi-unit wells and reverse drilling. Saw improved performance from keeping the horizontal well path in the zone of highest porosity. • Optimized Hydraulic Fractures - We tested larger fracks in PQ 25, compared to PQ 23 and concluded the slightly higher rates do not provide sufficient economic benefit to offset the additional cost Last Two Wells Completed in 2018 • PQ #29 (Wiener Owen #3H) initial 24 hour producing 10,794 Mcfe/d • PQ #30 (Wiener #1H) initial 24 hour producing 15,371 Mcfe/d 10 Seaport Global Securities LLC. Member FINRA/SIPC.

Prospective Benches within the Cotton Valley Cotton Valley – Type Log of 7 Benches Commentary • All Benches are productive in vertical wells on PetroQuest acreage • PetroQuest Producing Benches - E4 Sand (completed in 6 PQ horizontal 8600 wells & 46 offset* horizontals) 8700 - E-Berry/Roseberry (completed in 23 PQ horizontal wells & 53 offset 8800 horizontals) ˜ C/D - E Sand (completed in 35 offset 8900 horizontals) 9000 • Offset Producing Benches ˜ Vaughn - D Sand (completed in 2 offset 9100 horizontals) ˜ Davis - Vaughn (completed in 36 offset 9200 E4 horizontals) ˜ - Davis (completed in 22 offset 9300 horizontals) Completed E˜ - Taylor/Sexton (completed in 7 offset benches 9400 thus far horizontals) 9500 • “Offset” includes horizontal wells within 5 E-Berry/ ˜ miles 9600 Roseberry 9700 9800 9900 10000 ˜ Taylor 10100 11 Seaport Global Securities LLC. Member FINRA/SIPC. 1,400 Feet Overall Thickness (8,700 ft. to 10,100 ft.)Prospective Benches within the Cotton Valley Cotton Valley – Type Log of 7 Benches Commentary • All Benches are productive in vertical wells on PetroQuest acreage • PetroQuest Producing Benches - E4 Sand (completed in 6 PQ horizontal 8600 wells & 46 offset* horizontals) 8700 - E-Berry/Roseberry (completed in 23 PQ horizontal wells & 53 offset 8800 horizontals) ˜ C/D - E Sand (completed in 35 offset 8900 horizontals) 9000 • Offset Producing Benches ˜ Vaughn - D Sand (completed in 2 offset 9100 horizontals) ˜ Davis - Vaughn (completed in 36 offset 9200 E4 horizontals) ˜ - Davis (completed in 22 offset 9300 horizontals) Completed E˜ - Taylor/Sexton (completed in 7 offset benches 9400 thus far horizontals) 9500 • “Offset” includes horizontal wells within 5 E-Berry/ ˜ miles 9600 Roseberry 9700 9800 9900 10000 ˜ Taylor 10100 11 Seaport Global Securities LLC. Member FINRA/SIPC. 1,400 Feet Overall Thickness (8,700 ft. to 10,100 ft.)

Horizontal Cotton Valley Type Curve Assumptions (1) Single Well Gross Production Curve Oil Gas Wellhead EUR 73 MBbl 5,581 MMcf 10,000.0 IP-30 114 Bbl/d 8,706 Mcf/d Gas Shrink N/A 4.6% Production Mix 7% 93% 1,000.0 100.0 0 10 20 30 40 50 60 70 80 90 100 110 120 Months (1) Single Well Economics 160% Assumptions @ $3.00 MMbtu / $60.00 Bbl Oil (MBbl) 73 141% 140% Natural Gas (Mcf) 5,581 Wellhead EUR (MMcfe) 6,018 120% 100% 99% Oil (MBbl) 73 Natural Gas (Mcf) 5,339 80% NGL (MBbl) 14 66% Sales EUR (MMcfe) 5,859 60% D&C Cost ($M) $5,103 41% 40% IRR 66% 22% 20% PV-10 ($M) $3,781 Payback (Months) 17 0% $2.00 $2.50 $3.00 $3.50 $4.00 Gas Prices ($/MMBtu) 1) Well data normalized and averaged based on previous 18 E-Berry wells drilled. 12 Seaport Global Securities LLC. Member FINRA/SIPC. Gross Production (Mcfe/d) IRRsHorizontal Cotton Valley Type Curve Assumptions (1) Single Well Gross Production Curve Oil Gas Wellhead EUR 73 MBbl 5,581 MMcf 10,000.0 IP-30 114 Bbl/d 8,706 Mcf/d Gas Shrink N/A 4.6% Production Mix 7% 93% 1,000.0 100.0 0 10 20 30 40 50 60 70 80 90 100 110 120 Months (1) Single Well Economics 160% Assumptions @ $3.00 MMbtu / $60.00 Bbl Oil (MBbl) 73 141% 140% Natural Gas (Mcf) 5,581 Wellhead EUR (MMcfe) 6,018 120% 100% 99% Oil (MBbl) 73 Natural Gas (Mcf) 5,339 80% NGL (MBbl) 14 66% Sales EUR (MMcfe) 5,859 60% D&C Cost ($M) $5,103 41% 40% IRR 66% 22% 20% PV-10 ($M) $3,781 Payback (Months) 17 0% $2.00 $2.50 $3.00 $3.50 $4.00 Gas Prices ($/MMBtu) 1) Well data normalized and averaged based on previous 18 E-Berry wells drilled. 12 Seaport Global Securities LLC. Member FINRA/SIPC. Gross Production (Mcfe/d) IRRs

2017 Operational Improvements 2017 Gross Gas Production 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 Downtime due to Startup issues 10,000 PQ 21 PQ 22 PQ 23 PQ 24 PQ 25 PQ 26 PQ 27 PQ 28 PQ 29 PQ 30 with WM plant 0 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Reduction in Lease Operating Expenses $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 13 Seaport Global Securities LLC. Member FINRA/SIPC. LOE ($ / Mcfe) Gas Production (Mcf/d)2017 Operational Improvements 2017 Gross Gas Production 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 Downtime due to Startup issues 10,000 PQ 21 PQ 22 PQ 23 PQ 24 PQ 25 PQ 26 PQ 27 PQ 28 PQ 29 PQ 30 with WM plant 0 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Reduction in Lease Operating Expenses $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 13 Seaport Global Securities LLC. Member FINRA/SIPC. LOE ($ / Mcfe) Gas Production (Mcf/d)

2017 Operational Improvements (Cont’d) Water Infrastructure Sale EUR Improvements • Solved our biggest salt water disposal problems • Superior understanding of the Cotton Valley through log and core data - Locked in our operating cost for salt water disposal, which is our combined with extensive mapping of all targets highest LOE cost • Fine tuned completions for best frac results - Provided option for additional SWD capacity to accommodate - Decreased the number of perforations to ensure limited entry and future drilling optimum frac placement • $8.75 million - Reducing the spacing between stages and increased number of - Included 2 SWD wells and 2 pipelines connecting additional two stages based on microseismic observations 3rd party SWD wells • Improved directional efforts to stay in zone to connect with highest - Raised capital to deploy in attractive oily Austin Chalk permeability for best flow conduit • Volume commitment of 14 million BBLs which should be covered by • Increased completed lateral length existing wells - Drilling from off unit locations so horizontal at first legal take point • Option to increase daily disposal capacity up to 35 million BBLS for a - Permitting multiple unit Production Sharing Agreement (PSA) wells higher volume commitment • Future EUR improvement in the Davis and Vaughn Sands Cost Per Lateral Foot (2011 – 2017) $3,000 $2,500 $2,000 In 2017, we achieved our goal of < $1000/Lat Foot, even with rising completion costs $1,500 $1,000 $500 2011 2012 2013 2014 2015 2016 2017 $0 PQ 1 PQ 2 PQ 3 PQ 4 PQ 5 PQ 6 PQ 7 PQ 9 PQ 10 PQ 11 PQ 12 PQ 13 PQ 14 PQ 15 PQ 16 PQ 17 PQ 18 PQ 19 PQ 20 PQ 21 PQ 22 PQ 23 PQ 24 PQ 25 PQ 26 PQ 27 PQ 28 PQ 29 PQ 30 Drilling $ / Lateral Foot Completion $ / Lateral Foot Total $ / Lateral Foot 14 Seaport Global Securities LLC. Member FINRA/SIPC. $ / Lateral Foot2017 Operational Improvements (Cont’d) Water Infrastructure Sale EUR Improvements • Solved our biggest salt water disposal problems • Superior understanding of the Cotton Valley through log and core data - Locked in our operating cost for salt water disposal, which is our combined with extensive mapping of all targets highest LOE cost • Fine tuned completions for best frac results - Provided option for additional SWD capacity to accommodate - Decreased the number of perforations to ensure limited entry and future drilling optimum frac placement • $8.75 million - Reducing the spacing between stages and increased number of - Included 2 SWD wells and 2 pipelines connecting additional two stages based on microseismic observations 3rd party SWD wells • Improved directional efforts to stay in zone to connect with highest - Raised capital to deploy in attractive oily Austin Chalk permeability for best flow conduit • Volume commitment of 14 million BBLs which should be covered by • Increased completed lateral length existing wells - Drilling from off unit locations so horizontal at first legal take point • Option to increase daily disposal capacity up to 35 million BBLS for a - Permitting multiple unit Production Sharing Agreement (PSA) wells higher volume commitment • Future EUR improvement in the Davis and Vaughn Sands Cost Per Lateral Foot (2011 – 2017) $3,000 $2,500 $2,000 In 2017, we achieved our goal of < $1000/Lat Foot, even with rising completion costs $1,500 $1,000 $500 2011 2012 2013 2014 2015 2016 2017 $0 PQ 1 PQ 2 PQ 3 PQ 4 PQ 5 PQ 6 PQ 7 PQ 9 PQ 10 PQ 11 PQ 12 PQ 13 PQ 14 PQ 15 PQ 16 PQ 17 PQ 18 PQ 19 PQ 20 PQ 21 PQ 22 PQ 23 PQ 24 PQ 25 PQ 26 PQ 27 PQ 28 PQ 29 PQ 30 Drilling $ / Lateral Foot Completion $ / Lateral Foot Total $ / Lateral Foot 14 Seaport Global Securities LLC. Member FINRA/SIPC. $ / Lateral Foot

Midstream Overview Favorable Production Outlets Gas Midstream Acreage Dedication Gas - Favorable path to Henry Hub – current differential to HH is minus $0.15 • MarkWest Energy (Cryogenic Processing - Gas to MarkWest (CVX and PQ South) or Woodland Midstream (PQ North) for compression with higher fees) and plant processing - PetroQuest operated southern and Chevron co-owned acreage dedicated NGL - MarkWest has favorable access to Mt. Belvieu NGL market through July 31, 2022 - Majority of NGLs from Woodland plant are combined with condensate and sold at higher price - Average plant yield: 52.1 BBL/MMCF Condensate - Trucked with favorable LLS treatment (32% NYMEX WTI) - Average gas shrinkage: 17.3% with Woodland Midstream Facility 1.0057 residual BTU - Average condensate yield is: 4.8 BBL/MMcf NGL Bullet Tank • Woodland Midstream (JT Processing online Dehy Reboiler HP Inlet July 1, 2017) Stabilizer LP Inlet - PetroQuest operated acreage to the Recycle Residue x 2 north is dedicated through July 1, 2022 (400 to 800 - Average plant yield is: 1.6 BBL/MMCF psi) Dehy Towers (69% NYMEX WTI) - Average gas shrinkage: 3.2% with 1.1057 residual BTU Low Pressure - Average condensate yield: 12.9 (200 to 1200 BBL/MMcf (169% increase) psi) Stabilizer JT Skid - Almost $4 million dollar revenue High Pressure increase in the 12 months online (800 to 1200 psi) 15 Seaport Global Securities LLC. Member FINRA/SIPC.Midstream Overview Favorable Production Outlets Gas Midstream Acreage Dedication Gas - Favorable path to Henry Hub – current differential to HH is minus $0.15 • MarkWest Energy (Cryogenic Processing - Gas to MarkWest (CVX and PQ South) or Woodland Midstream (PQ North) for compression with higher fees) and plant processing - PetroQuest operated southern and Chevron co-owned acreage dedicated NGL - MarkWest has favorable access to Mt. Belvieu NGL market through July 31, 2022 - Majority of NGLs from Woodland plant are combined with condensate and sold at higher price - Average plant yield: 52.1 BBL/MMCF Condensate - Trucked with favorable LLS treatment (32% NYMEX WTI) - Average gas shrinkage: 17.3% with Woodland Midstream Facility 1.0057 residual BTU - Average condensate yield is: 4.8 BBL/MMcf NGL Bullet Tank • Woodland Midstream (JT Processing online Dehy Reboiler HP Inlet July 1, 2017) Stabilizer LP Inlet - PetroQuest operated acreage to the Recycle Residue x 2 north is dedicated through July 1, 2022 (400 to 800 - Average plant yield is: 1.6 BBL/MMCF psi) Dehy Towers (69% NYMEX WTI) - Average gas shrinkage: 3.2% with 1.1057 residual BTU Low Pressure - Average condensate yield: 12.9 (200 to 1200 BBL/MMcf (169% increase) psi) Stabilizer JT Skid - Almost $4 million dollar revenue High Pressure increase in the 12 months online (800 to 1200 psi) 15 Seaport Global Securities LLC. Member FINRA/SIPC.

Summary of Cotton Valley Track record of low cost Cotton Valley wells with increasing EURs and lower costs Large inventory of locations Attractive acreage position with the majority held by production Significant takeaway capacity available through existing pipelines and facilities, and upside existing with optimized gas processing Opportunity to grow and add value through Joint Ventures with promoted partners 16 Seaport Global Securities LLC. Member FINRA/SIPC.Summary of Cotton Valley Track record of low cost Cotton Valley wells with increasing EURs and lower costs Large inventory of locations Attractive acreage position with the majority held by production Significant takeaway capacity available through existing pipelines and facilities, and upside existing with optimized gas processing Opportunity to grow and add value through Joint Ventures with promoted partners 16 Seaport Global Securities LLC. Member FINRA/SIPC.