Exhibit 99.1

August 2010

Company Information 1 Corporate Contact: Matt Quantz - mquantz@petroquest.com 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. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices and significantly depressed natural gas prices since the middle of 2008, the uncertain economic conditions in the United States and globally, the decline in the values of our properties that have resulted in and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters, including the impact of the oil spill in the Gulf of Mexico on our present and future operations, the impact of government regulation, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports PetroQuest has filed with the Securities and Exchange Commission. PetroQuest undertakes no duty to update or revise these forward-looking statements. Prior to 2010, the Securities and Exchange Commission generally permitted oil and gas companies, in their filings, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Beginning with year-end reserves for 2009, the SEC permits the optional disclosure of probable and possible reserves. We have elected not to disclose our probable and possible reserves in our filings with the SEC. We use the terms "unrisked inventory," "gross unrisked reserves," "EUR" 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 unrisked inventory, gross unrisked reserves or EUR 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 unrisked inventory, gross unrisked reserves or EUR 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. 400 East Kaliste Saloom Road, Suite 6000 Lafayette, Louisiana 70508 Phone: (337) 232-7028 Fax: (337) 232-0044 www.petroquest.com

Corporate Characteristics Historical track record of reserve growth through the drill bit and strategic acquisitions 97% drilling success rate for the 6 years ended 12/31/2009 26% 11-year reserves CAGR Balanced, diversified asset portfolio combines longer-life development assets with shorter-life strong cash flow generating assets 3 separate onshore basins - Arkoma, East Texas and Gulf Coast 82% proved reserves in long life basins(1) 54% production in long life basins(2) 69% proved-developed reserves(1) Conservative operator with a track record of drilling within cash flow Significant operational control with 90% of reserves Company operated Strong balance sheet and substantial liquidity position through Woodford JV and $130MM repayment of bank debt Low-risk drilling inventory 91% in long-lived onshore basins(3) 2 As of 6/30/10 Based on Q2 2010 average production As of 12/31/09. Approx. 1.1 Tcfe of unrisked inventory of Woodford reserves subject to potential Woodford JV partner earn-out

A History of Consistent Growth(1 ) Reserves 26% CAGR Production 32% CAGR Cash Flow 82% CAGR Stock price 20% CAGR 3 (1) Beginning in 1999

2010 Operations Overview 4 Capital expenditures in 2010 expected to grow from reduced 2009 spending to approximate 2010 cash flow Large operated position allows for control of timing of investments Woodford JV closed May 2010 $234.6 million total transaction value No developed reserves or production sold Recent operated Woodford performance 4 wells completed during 4Q09 - average IP rate of 6.5 MMcf/d 3 wells completed during May 2010 - average IP rate of 6.8 MMcf/d 15 gross operated Woodford wells planned for 2010 6 wells completed to date 40 MMcfe/d hedged for 2010 at average floor of $5.62 Additional liquids production potential 2 well initial Niobrara drilling program provides exposure to 25% of 21,000 net acres

Our Properties 5 Gulf Coast Region Arkoma Basin Tulsa East Texas Lafayette Houston 82% Reserves (1) We have grown beyond being solely a Gulf Coast Basin company 18% Reserves (1) (1) As of June 30, 2010

1P Reserves (1) Drilling Locations (2) EAST TEXAS BOSSIER (3) ARKOMA (OKLAHOMA) ARKOMA (ARKANSAS) SOUTH LOUISIANA GULF OF MEXICO Our Portfolio Three separate basins - all poised for growth 6 Three separate basins - all core to PQ Unrisked Inventory (2) Reserves are as of December 31, 2009 (reserves are net and in Bcfe) proforma for Woodford JV Unrisked inventory and locations are as of December 31, 2009 (inventory are net in Bcfe; locations are gross) Assumes 160 acre spacing and 60% of acreage assumed prospective 182 359 1,063 338 43 143 2,128 355 180 1,969 2,200 10 15 4,729 EAST TX ARKOMA South Louisiana Offshore GOM UNCONVENTIONAL PLAYS Gulf Coast CONVENTIONAL PLAYS 30 N/A 74 10 16 24 154 91% Long-Life Reserves Estimated 2010 Production

Arkoma Basin 7 Approximately 45,000(1) net acres in the Woodford Shale Approximately 18,000 net acres in the Fayetteville Shale Current production approximately 36,000 Mcf/day net (1) Woodford JV partner has the right to earn approximately 20,000 net acres

Arkoma Basin (1) - Strong Growth Metrics 8 (1) Includes Woodford and Fayetteville 52% CAGR

Woodford Shale Activity 9 Recent Activity Current net production ~ 30 MMcf/d Woodford JV closed May 2010 Three Woodford wells completed in June with average IP of 6.8 MMcf/d 15 gross operated Woodford wells budgeted for 2010 Approximately 43% of 2010 capital budget allocated to Woodford Continued improvement in IP rates and EURs Expected to have a 3-rig Woodford program by year-end Gross Operated Woodford Production First Rig Second Rig Third Rig Drilling Operations Suspended Drilling Operations Resumed

10 Wapanucka Limestone Woodford Shale 3D Seismic Based Drilling 8000' 7000' 6000' 9000' Section Line Section Line Section Line 3D Seismic Profile PQ #27 PQ #9 IP - 12.5 MMcfe IP - 2.9 MMcfe

Woodford Shale PQ Delivers Top Max Monthly Rate 11 Source: compiled from public domain production data coupled with internal production data on newer PQ wells. Data reported: March 2008 - December 2009 PQ WOODFORD PROGRAM PQ delivered highest maximum monthly initial production rate of any company 15% improvement over next operator. Max Monthly Gas Rate, Mcfd

Woodford JV Transaction Summary $234.6MM total transaction value ($128MM guaranteed) $60MM up front payment $28MM in future payments $14MM at November 2011 $14MM dependent upon continued achievement of "base case" performance metrics $146.6MM "drilling carry" where JV partner pays 80% of costs for 50% of the working interest $54MM phase one $92.6MM phase two (upon JV partner's election to participate in phase two) JV Partner receives 24.9 Bcfe of Woodford PUD reserves(1) Right to earn 50% of the Company's undeveloped Woodford acreage 50/50 area of mutual interest (AMI) is formed No developed reserves (and associated production or cash flow) were sold and the Company remains the operator of the assets going forward Creates option to access Eagle Ford/Marcellus through promoted structure 75% for 50% carry on leasehold costs $5 million drilling carry per basin 12 Reserves as of 12/31/09

Woodford Decline Curves 13 (1) Source: Simmons & Company PQ Woodford Year 1 Avg Decline ~60% March 2008 Onward Avg Year 1 Decline % (1) Haynesville: 85% Fayetteville: 64% Marcellus: 62% Eagle Ford: 82% Barnett: 65%

Woodford Horizontal Well Economics (Pre JV) 14 IRR $/Mcf $/Mcf Capital ($M) Capital ($M) Capital ($M) Capital ($M) Assumptions: Price* $4,000 $5,000 $6,000 IRR % IP Rate - 6.0 MMcfd $4.00 18.9% 10.6% 5.5% IRR % EUR - 5.0 Bcf $4.50 26.9% 16.4% 10.2% IRR % Well Cost - $4.0 to $6.0 MM $5.00 35.6% 22.9% 15.1% IRR % *Henry Hub $5.50 45.1% 30.0% 20.7% IRR % $6.00 55.3% 37.8% 26.8%

Woodford Shale - Upside Leverage Woodford Shale - Upside Leverage Ticker Woodford Acres Acres/EV (1) PQ 45,000 (2) 80.8 NFX 165,000 17.6 SM 49,000 16.7 CLR 47,000 5.5 DVN 54,000 1.5 Represents number of acres per million dollars of enterprise value. PQ Woodford acres and enterprise values as of August 3, 2010. Woodford JV partner has the right to earn approximately 20,000 net acres Represents number of acres per million dollars of enterprise value. PQ Woodford acres and enterprise values as of August 3, 2010. Woodford JV partner has the right to earn approximately 20,000 net acres Represents number of acres per million dollars of enterprise value. PQ Woodford acres and enterprise values as of August 3, 2010. Woodford JV partner has the right to earn approximately 20,000 net acres 15 Pontotac Coal Pittsburg Macintosh Haskell Latimer NFX PQ SM DVN Oklahoma Tulsa Oklahoma City Hughes CLR

Fayetteville Shale 16 Approximately 18,000 net acres Current production approximately 6,000 Mcf/day net 5% of 2010 capital budget allocated to Fayetteville

East Texas Anchored by SE Carthage field: 23,900 net acres and avg daily production of 10 MMcf/d Horizontal Cotton Valley program: two wells planned for the second half of 2010 (1st well expected spud in late August) 11% of the 2010 capital budget to East Texas Highly prospective for Haynesville/Bossier; HBP 17

East Texas - Haynesville/Bossier Upside 18 Source: RBC Capital Markets Source: RBC Capital Markets

Near-Term Gulf Coast Drilling Inventory Near-Term Gulf Coast Drilling Inventory 19 Focus near term capital on low cost recompletion opportunities, low risk development projects and select high impact onshore drilling prospects 41% of 2010 capex budget allocated to GOM/GC basin (includes approximately $7mm for P&A work) No present impact on operations relative to BP oil spill 16% of reserves(1) and 19% of production(2) derived from shallow water Gulf of Mexico No deepwater assets 12/31/09 reserves pro forma for Woodford JV Q2 2010 production

Strong Balance Sheet and Liquidity 12/31/08 6/30/10 Bank Debt Outstanding $130MM $0 Cash on Hand $24MM $58MM Total Liquidity(1) $40.1MM $161.1MM Net Debt/Proved Mcfe(2)(3) $1.29 $0.58 Net Debt/Proved Dev. Mcfe(2)(3) $2.07 $0.80 Net Debt/Adjusted EBITDA (TTM)(4) 1.18x 0.6x % of Reserves Long Lived(5) 68% 82% % of Production Long Lived(6) 47% 54% 20 Focus for past 18 months has been on building liquidity and de-leveraging the balance sheet Liquidity calculated as sum of net working capital and availability under borrowing base Reserves as of 12/31/09 pro forma for Woodford JV Net debt calculated as total debt less net working capital For a reconciliation of Adjusted EBITDA to net income, see Appendix 1 As of 6/30/2010 Q2 2010 average production

21 Refinancing of Senior Notes 7-Year Notes issued at par to yield 10% Extends debt maturity from 2012 to 2017 Lower coupon generates ~$1 million in annual interest expense savings Provides improved covenant package allowing for full use of $100 million borrowing base Extends maturity of credit facility to 2013

Focused Effort to Fund Drilling with Cash Flow 22 MM$ $126 million liquidity build $/mcfe Net debt is calculated as debt less net working capital 6/30/10 balance sheet and 12/31/09 reserves, pro forma for Woodford JV Estimated 2010 Cap Ex $100-110MM Additional $38MM in equity proceeds Additional $60MM in JV proceeds Additional $43MM in proceeds from sale of gathering system

Capital Investment Program - Diversification Reduces Risk 23 $59 million Drilled 82 Wells 2009 2008 $280 million Drilled 150 Wells 2010E $100 - $110 million Drill 70 - 90 Wells

Production Mix 24 24 During the first 6 months of 2010, liquids generated 40% of non-hedged revenues

Hedging Positions Target of hedging 40%-50% of annual production - approximately 50% of the second half of 2010 estimated gas production is hedged (based on mid-point of production guidance) Gas hedging positions (costless collars) 25

Summary of Diversification Efforts 26 * Using the SEC's previous reporting methodology, proved reserves would have been 202.2 Bcfe (194% growth; year end 2009 prices of $5.79 per mcf and $79.36 per Bbl) 160% Growth 157% Growth

Comparative Valuation Notes: Company stock prices and estimates are as of 8/03/2010. Analyst cash flow per share estimates per Bloomberg. The analysts' opinions, estimates or forecasts (and therefore the estimates) are theirs alone, are not those of PetroQuest or its management and may not reflect PetroQuest's actual or anticipated results PetroQuest undertakes no obligation to review or confirm analysts' expectations. P/2010E CF Multiple(1) 17.2 5.6 3.2 2.8 11.2 5.4 3.1 5.5 6.9 4.8 5.5 10.3 3.9 7.9 6.7 3.6 P/2011E CF Multiple(1) 8.9 3.7 3.0 2.0 8.8 5.1 2.4 3.8 4.7 4.7 5.3 7.4 3.7 6.5 5.0 3.5 Brigham Exploration Carrizo Oil & Gas Chesapeake Energy Clayton Williams Continental Resources Devon Energy GMX Resources Goodrich Petroleum Petrohawk Energy Newfield Exploration Quicksilver Resources Range Resources Sandridge Energy Southwestern Energy Average PetroQuest Energy Callon Petroleum Energy XXI Mariner Energy McMoran Exploration Plains Exploration Stone Energy W&T Offshore Average PetroQuest Energy Resource Peer Group Gulf Coast Peer Group P/2010E CF Multiple(1) 3.6 4.0 5.1 7.1 4.2 1.4 1.9 3.9 3.6 27 P/2011E CF Multiple(1) 2.9 3.3 3.9 5.7 3.9 1.4 1.8 3.3 3.5

28 Closing Summary Continue to diversify reserve base into resource plays Results in a balanced portfolio that combines longer-life development assets with shorter- life strong cash flow generating assets Woodford JV generates significant liquidity and allows accelerated monetization of long-term acreage development Strong reserve and production growth in the Woodford Shale Balance sheet provides flexibility and substantial liquidity Repayment of $130 million of bank debt since August 2009 No borrowings outstanding on $100 million borrowing base Established as a best-in-class operator in the highly productive Woodford Shale Management invested in and aligned with PetroQuest's success through substantial equity ownership

29 Appendix

30 Appendix - 1 Adjusted EBITDA represents income before interest expense (net), income tax, depreciation, depletion, amortization, accretion of asset retirement obligation and ceiling test writedowns. We have reported Adjusted EBITDA because we believe Adjusted EBITDA is a measure commonly reported and widely used by investors as an indicator of a company's operating performance. We believe Adjusted EBITDA assists such investors in comparing a company's performance on a consistent basis without regard to depreciation, depletion and amortization, which can vary significantly depending upon accounting methods or nonoperating factors such as historical cost. Adjusted EBITDA is not a calculation based on generally accepted accounting principles, or GAAP, and should not be considered an alternative to net income in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions and other sources and uses of cash which are disclosed in our consolidated statements of cash flows. Investors should carefully consider the specific items included in our computation of Adjusted EBITDA. While Adjusted EBITDA has been disclosed herein to permit a more complete comparative analysis of our operating performance relative to other companies, investors should be cautioned that Adjusted EBITDA as reported by us may not be comparable in all instances to Adjusted EBITDA as reported by other companies. Adjusted EBITDA amounts may not be fully available for management's discretionary use, due to certain requirements to conserve funds for capital expenditures, debt service and other commitments, and therefore management relies primarily on our GAAP results. Adjusted EBITDA is not intended to represent net income as defined by GAAP and such information should not be considered as an alternative to net income, cash flow from operations or any other measure of performance prescribed by GAAP in the United States. The above table reconciles net income (loss) to Adjusted EBITDA for the periods presented. ($ in thousands) 2005 2008 2009 LTM Net Income (Loss) $21,417 (152,541) ($90,190) $3,986 Income tax expense (benefit) 12,477 (55,581) (14,635) 10,633 Interest Expense 12,371 9,327 12,615 10,240 Depreciation, depletion, and amortization 43,747 134,340 84,772 63,307 Accretion of asset retirement obligation 1,253 1,317 2,452 2,204 Ceiling test writedown - 266,156 156,134 52,552 Adjusted EBITDA $91,265 $203,018 $151,148 $142,922

31 Appendix - 2 6 months ($ in thousands) 2004 2005 2006 2007 2008 2009 2010 Net income (loss) $16,348 $21,417 $23,986 $40,619 ($96,960) ($90,190) $37,532 Reconciling items: Deferred tax expense (benefit) 8,511 12,477 14,604 23,664 (55,581) (14,635) (1,380) Gain on sale of assets 0 0 0 0 (26,812) (485) 0 Non-cash gain on legal settlement 0 0 0 0 0 0 (4,164) Depreciation, depletion and amortization 35,435 43,747 85,858 119,969 134,340 84,772 28,728 Stock based compensation 0 0 5,651 9,818 9,582 6,328 3,752 Ceiling test write down 0 0 0 0 266,156 156,134 0 Accretion of asset retirement obligation 833 1,253 1,513 923 1,317 1,512 876 Other 1,732 4,289 1,140 1,187 1,492 913 787 Discretionary cash flow $62,859 $83,183 $132,752 $196,180 $233,534 $146,801 $66,131 Changes in working capital accounts 7,451 (9,993) (13,130) 33,607 (45,096) (23,176) 5,576 Settlement of asset retirement obligations 0 0 (252) (6,058) (19,377) (1,803) (5,389) Net cash flow provided by operating activities $70,310 $73,190 $119,370 $223,729 $169,061 $121,822 $66,318 Note: Management believes that discretionary cash flow is relevant and useful information, which is commonly used by analysts, investors and other interested parties in the oil and gas industry as a financial indicator of an oil and gas company's ability to generate cash used to internally fund exploration and development activities and to service debt. Discretionary cash flow is not a measure of financial performance prepared in accordance with generally accepted accounting principles ("GAAP") and should not be considered in isolation or as an alternative to net cash flow provided by operating activities. In addition, since discretionary cash flow is not a term defined by GAAP, it might not be comparable to similarly titled measures used by other companies.

400 East Kaliste Saloom Road, Suite 6000 Lafayette, Louisiana 70508 Phone: (337) 232-7028 Fax: (337) 232-0044 www.petroquest.com NYSE: PQ 32