Exhibit 99.1

March 2013

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 "reserve 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 reserve 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

Mid-Con Production: 50 MMcfe/d (1) 2012 production East Texas Production: 17 MMcfe/d (1) Tulsa Gulf Coast/GOM Production: 24 MMcfe/d (1) Lafayette Other (WY & EF) Production: 2 MMcfe/d (1) Total Production: 93 MMcfe/d (1) Houston Our Properties 2

Mid-Con Production: 50 MMcfe/d (1) Reserves: 184 Bcfe (2) 2012 production 2012 reserves based on 12/31/12 pricing East Texas Production: 17 MMcfe/d (1) Reserves: 48 Bcfe (2) Tulsa Gulf Coast/GOM Production: 24 MMcfe/d (1) Reserves: 30 Bcfe (2) Lafayette Other (WY & EF) Production: 2 MMcfe/d (1) Reserves: 3 Bcfe (2) Total Production: 93 MMcfe/d (1) Reserves: 265 Bcfe (2) Houston Our Properties 3

Mid-Con Production: 50 MMcfe/d (1) Reserves: 184 Bcfe (2) Inventory: 1.1 Tcfe 2012 production 2012 reserves based on 12/31/12 pricing East Texas Production: 17 MMcfe/d (1) Reserves: 48 Bcfe (2) Inventory: 518 Bcfe Tulsa Gulf Coast/GOM Production: 24 MMcfe/d (1) Reserves: 30 Bcfe (2) Inventory: 152 Bcfe Lafayette Other (WY & EF) Production: 2 MMcfe/d (1) Reserves: 3 Bcfe (2) Inventory: 31 Bcfe Total Production: 93 MMcfe/d (1) Reserves: 265 Bcfe (2) Inventory: 1.8 Tcfe Houston Our Properties 4

Core positions provide exposure to each commodity (oil, natural gas, NGLs) allowing for efficient capital allocation depending upon commodity price cycles - operate ~95% of 2013 budget Promoted cost structure in Woodford and Miss Lime enhances returns NGLs E. Texas assets are essentially undeveloped, and have nearly 50,000 gross acres of Horizontal Cotton Valley prospectivity Recent leasing significantly increases liquids rich Woodford inventory Oil Completely undeveloped 54,000 gross acres in the Miss Lime = hundreds of drilling locations Eagle Ford acreage provides 2-3 year inventory Can target Gulf Coast oil rich prospects with low cost recompletions or exploratory wells Gas Woodford and Bossier assets provide significant running room in an improving dry natural gas market Slow-Down In periods of weak prices in oil, natural gas, and NGLs, PQ has demonstrated the ability to reduce capex (2009) and still achieve growth 5 Asset Base Provides Optionality

6 Product Diversification - Gas to Liquids Liquids production up 43% over the last 6 quarters as capital has shifted away from dry gas Keys Drivers to Liquids Transition La Cantera currently producing ~ 86,000 Mcfe/d (20% liquids) - 3rd well is expected to bring total production to 120,000 - 130,000 Mcfe/d (28% liquids) by the second quarter of 2013 Liquids rich Woodford - 21 operated wells in 2012 Average IP rate 2,678 Mcf/d and 344 bbls of NGLs 15 operated wells planned for 2013 54,000 gross/27,000 net acres in Miss Lime - 12 operated wells in 2012 8 well average IP rate 425 Boe (80% oil) 3D seismic shoot expected to enhance geologic model - data expected during 2nd half of 2013 Up 43% (CHART)

La Cantera High Impact Discovery 7

La Cantera Development 8 Lower Cris R-1 Lower Cris R-2, Lobe A Lower Cris R-2, Lobe B Lower Cris R-2, Lobe C (CURRENTLY PRODUCING) 30,000E MCF/D + 555E Bbls of oil 2-3 Year Reserve Life 30,000E MCF/D + 555E Bbls of oil 2-3 Year Reserve Life 30,000 MCF/D + 555 Bbls of oil 2-3 Year Reserve Life 40,000E MCF/D + 740E Bbls of oil 2-3 Year Reserve Life 40,000E MCF/D + 740E Bbls of oil 2-3 Year Reserve Life 40,000 MCF/D + 740 Bbls of oil 2-3 Year Reserve Life

Gulf Coast Drilling Summary Gulf Coast Drilling Summary 9 Focus near term capital on low cost recompletion opportunities, low risk development projects and select high impact onshore drilling prospects Recent Successful Projects NRI First Production Feet of Pay I.P. Rate Broussard Estates #2 (La Cantera Prospect) 17% Sept 12 310' Net TVD 52,000 Mcfe Thibodeaux #1(La Cantera Prospect) 17% March 12 248' Net TVD 36,000 Mcfe Craft Farms 41% June 11 33' Net TVD 4,000 Mcfe SS 72 #1 45% Oct 11 57' Net TVD 444 Boe SS 72 #2 45% Jan 12 50' Net TVD 130 Boe SS 72 #3 45% Jan 12 135' Net TVD 565 Boe SS 72 #4 45% TBD 34' Net TVD TBD 2013 Activity

Encouraging Early Results in Eastern Play Expansion Area 10 Drilling MS Lime Wells PQ Acreage Mississippian Lime Early Core Area Kansas Oklahoma PQ Woodford Activity Area MS Lime Horizontal Activity Area 24 Hour Avg Rate 8 wells - 425 Boe 30 Day Avg Rate 6 wells - 255 Boe PQ Kay PQ Pawnee PQ #9 IP: 1,291 boe/d RRC Average EUR: 485-600 Mboe Spyglass IP: 1,108 boe/d DVN IP: 960 boe/d OEDV IP: 1,185 boe/d SD IP: 885 boe/d PQ Grant

11 Woodford Decline Curves - Experience Yields Improvements

Woodford Shale - Strong Growth Metrics 12 (1) Reserves computed using 12/31/12 pricing of $3.41/mcf 33% CAGR 28% CAGR

Liquids Rich Woodford Program 13 Liquids rich area on Western flank of acreage Average IP rate of 2,678 mcf/d and 344 barrels of NGLs/d Average EUR of 555 MBOE (56% gas - 44% NGL) NGL rich gas @ 1,250 BTU Pricing uplift + JV promote = great returns 12-15 wells planned for 2013 Producing over 900 bbls/d net of NGLs Recent leasing adds 75+ gross drilling locations (CHART)

14 Woodford Liquids Rich - Horizontal Well Economics (CHART) Assumptions: Drilled under JV Promote Price Price Capital (M$) Capital (M$) Capital (M$) IP Rate - 2.6 MMcfd + 350 Bbls NGLs Gas NGL $ 3,750 $ 4,000 $ 4,250 EUR - 4.5 Bcfe $ 3.00 $ 25 62% 55% 49% IRR % 1245 BTU, 109 bbl NGL/Mcf $ 3.50 $ 30 89% 80% 73% IRR % Well Cost - $3.75 to $4.25 MM $ 4.00 $ 35 118% 107% 98% IRR % *Henry Hub

Woodford Liquids Rich Gas-Payback Analysis 15 Assumptions: Drilled under JV Promote CAPEX IP Rate - 2.6 MMcfd + 350Bbls NGLs Gas* NGL $ 4,000 ($M) EUR - 4.5 Bcfe $/MCF $/Bbl $ 3.00 $ 25 18 Payout, Mos 1245 BTU, 109 bbl NGL/Mcf $/MCF $/Bbl $ 3.50 $ 30 12 Payout, Mos Well Cost - $4.0 MM $/MCF $/Bbl $ 4.00 $ 35 9 Payout, Mos *Henry Hub (CHART)

Woodford JV Transaction Summary Woodford JV closed May 2010 whereby partner received 29 Bcfe of PUD reserves and right to earn 50% of Woodford acreage Received cash payments totaling $88 million Through 12/31/12 have utilized drilling carry totaling $75.6 million At 12/31/12 - $71 million of drilling carry remains whereby partner pays 75% of well costs for a 50% ownership 16 16

Liquids Rich Cotton Valley Program 17 6 non-operated wells completed in 2011 Average IP rate of 4.1 mmcf/d and 260 barrels of NGLs/d 8 operated wells completed in 2011/2012 Average IP rate of 5.1 mmcf/d and 366 barrels of NGLs/d Average EUR of 973 MBOE (72% gas - 25% NGL - 3% oil) (CHART)

Panola County Cotton Valley Production 18 18 Legend Cotton Valley Wells PQ CV Vertical Wells PQ CV Horizontal Wells PQ Area of Mutual Interest Bethany Field Area - 548 BCF Beckville Field Area - 243 BCF Carthage Field Area - 4,429 BCF S.E. Carthage Field Area - 225 BCF

Strong Balance Sheet and Liquidity 19 Fiscal discipline and Woodford JV have resulted in significantly reduced bank borrowings Borrowing base recently increased to $130 million Liquidity(1) @ 12/31/12 = $95 million Unused future drilling carry @ 12/31/12 = $71 million Non-core asset sales in Dec and Jan provide ~$20 million in additional capital Liquidity calculated as sum of cash and availability under borrowing base Proved reserves @12/31/12 using YE 2012 pricing 19 12/31/12 Balance Maturity Bank Debt $50MM 2016 10% Notes 150MM 2017 Total Debt $200MM Proved Reserves (2) 265 Bcfe Debt/Proved Mcfe (2) $0.75

(CHART) Since 2008 - Reserves up 43%; debt down 28% 20 Bcfe Total Debt ($MM) 20 Debt Adjusted Reserves per Share up 44%: 1.8 at 12/08 and 2.6 at 12/12 (1) (1) Reserves computed using 12/31/12 pricing of $3.41/mcf and $91.82/bbl

Capital Investment Program (Liquids Focused) 21 2013E $80 - $100 million Drill 30 - 40 Wells (CHART) (1) Based on the mid-point of guidance $135

Focused Effort to Fund Drilling with Cash Flow 22 MM$ Additional $38MM in equity proceeds Additional $60MM in JV proceeds Additional $43MM in proceeds from sale of gathering system 22 For a reconciliation of net income to discretionary cash flow see Appendix-4 Additional $28MM in JV proceeds Additional $20MM in asset sales proceeds - post 9/30

Diversification Strategy Accomplished 23 265.0 Bcfe 32.0 Bcfe 89% Long-life 73% Long-life 68.7 Bcfe 13.3 Bcfe 286% Growth 141% Growth 23 R/P: 8.3 R/P: 5.2 Reserves computed using 12/31/12 pricing of $3.41/mcf and $91.82/bbl Excludes 2012 Fayetteville production

Gulf Coast Assets - Free Cash Flow has Funded Diversification Funded Diversification Funded Diversification 24 Revenues less LOE and Sev taxes from GCB/GOM Capex based upon mid-point of guidance (2)

Closing Summary Diversified asset base with significant control over operations Balanced portfolio combines longer-life development assets with shorter-life strong cash flow generating assets Increased focus on oil and liquids producing assets Forecasting production growth with 35% reduction in spending Track record of aligning capex and cash flow Recent non-core asset sales provide additional liquidity Leverage Phase 2 drilling carry High impact Gulf Coast projects provide significant cash flow and production growth potential Management invested in and aligned with PetroQuest's success through equity ownership 25

26 Appendix

Target of hedging 40%-50% of annual production Hedging positions: 27 Natural Gas Daily Hedged Volumes (Mmbtu) Average Price Feb13 - Dec13 10,000 $3.71 Mar13 - Dec13 5,000 $3.50 Apr13 - Dec13 5,000 $3.74 2013 10,000 $2.00 -$3.00 -$4.09 2013 5,000 $4.00 2014 10,000 $4.08 Oil Daily Hedged Volumes (Bbls) Price 2013 250 $104.75 (1) Appendix - 1 Hedging Positions (1) LLS Index

28 Appendix - 2 Comparative Credit Metrics Net Debt / LTM Adjusted EBITDA(1) Source: FactSet, public filings Note: Based on latest filings, pro forma for announced M&A and capital markets activity (1) Net debt calculated as total debt less cash and cash equivalents Net Debt / Proved Developed Reserves ($/Mcfe) (1) Net Debt / Proved Developed Reserves ($/Mcfe) (1) (CHART)

29 Appendix - 3 Adjusted EBITDA represents income before interest expense (net), dividends, income tax, depreciation, depletion, amortization, accretion of asset retirement obligation, non-recurring or unusual gains, losses on early extinguishment of debt, derivative expense 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) 2008 2009 2010 2011 2012 Net Income (Loss) ($96,960) ($90,190) $47,126 $10,548 ($132,079) Income tax expense (benefit) (55,581) (14,635) 1,630 (1,810) 1,636 Interest expense & dividends 14,467 17,754 15,092 14,787 14,947 Depreciation, depletion, and amortization 134,340 84,772 59,326 58,243 60,689 Loss on early extinguishment of debt - - 5,973 - - Gain on sale of gas gathering assets (26,812) - - - - Non cash gain on legal settlement - - (4,164) - - Accretion of asset retirement obligation 1,317 2,452 1,306 2,049 2,078 Derivative Expense - - - - 233 Ceiling test writedown 266,156 156,134 - 18,907 137,100 Adjusted EBITDA $236,927 $156,287 $126,289 $102,724 $84,604 29

30 Appendix - 4 ($ in thousands) 2004 2005 2006 2007 2008 2009 2010 2011 2012 Net income (loss) $16,348 $21,417 $23,986 $40,619 ($96,960) ($90,190) $47,126 $10,548 ($132,079) Reconciling items: Deferred tax expense (benefit) 8,511 12,477 14,604 23,664 (55,581) (14,635) 1,630 (1,810) 1,636 Gain on sale of assets - - - - (26,812) (485) - - - Non-cash gain on legal settlement - - - - - - (4,164) - - Depreciation, depletion and amortization 35,435 43,747 85,858 119,969 134,340 84,772 59,326 58,243 60,689 Stock based compensation - - 5,651 9,818 9,582 6,328 7,137 4,833 6,910 Loss on early extinguishment of debt - - - - - - 5,973 - - Ceiling test write down - - - - 266,156 156,134 - 18,907 137,100 Accretion of asset retirement obligation 833 1,253 1,513 923 1,317 1,512 1,306 2,049 2,078 Other 1,732 4,289 1,140 1,187 1,492 913 1,334 625 1,114 Discretionary cash flow $62,859 $83,183 $132,752 $196,180 $233,534 $146,801 $119,668 $93,395 $77,448 Changes in working capital accounts 7,451 (9,993) (13,130) 33,607 (45,096) (23,176) 18,250 25,400 13,770 Settlement of asset retirement obligations - - (252) (6,058) (19,377) (1,803) (6,274) (905) (2,627) Net cash flow provided by operating activities $70,310 $73,190 $119,370 $223,729 $169,061 $121,822 $131,644 $117,890 $88,591 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. 30

31 Appendix - 5 Horizontal Cotton Valley

Appendix - 6 PQ Woodford Performance 32 Source: compiled from public domain production data Data reported: March 2008 - December 2011 PQ WOODFORD PROGRAM PQ delivered highest maximum monthly initial production rate of any company ~10% improvement over next operator. Max Monthly Gas Rate, Mcfd 32

Appendix - 7 Woodford Position 33

APC NFX EOG Wells > 800 BOPD COG Wells > 800 BOPD EP ROSE CRZO XOM CHK GDP PQ Acreage Dimmit County - app. 600 net acres LaSalle County - app. 1,700 net acres Volatile Oil/ Gas Window Appendix - 8 Eagle Ford Position HK APC & CHK Wells >1000 BOPD 34 PQ PQ CHK 6 wells completed Avg IP: 425 Boe/d

35 Appendix 9 - Niobrara Position

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