Exhibit 99.1

February 2014

Company Information 2 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 integrate the Gulf of Mexico acquisitions with our operations and realize the anticipated benefits of from the acquisitions, any unexpected costs or delays in connection with the integration of Gulf of Mexico acquisitions, our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices, the uncertain economic conditions in the United States and globally, the declines 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, changes in laws and regulations as they relate to our operations, including our fracing operations or our operations in the Gulf of Mexico, 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," "inventory", "unrisked resource potential" 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 EUR, inventory or unrisked inventory 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, EUR or unrisked resource potential 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.Version - 1 400 East Kaliste Saloom Road, Suite 6000 Lafayette, Louisiana 70508 Phone: (337) 232-7028 Fax: (337) 232-0044www.petroquest.com

Our Daily Focus 3 Utilize Strong Gulf Coast Cash Flow to Develop High-Return Onshore Resource Assets

Gulf Coast Cash Flow Magnifies Growth 4 Free Cash Flow Free Cash Flow Free Cash Flow Minimal Reinvestment Capex $* WoodfordDevelopment Cotton Valley Expansion Mississippian Evaluation Gulf Coast Assets * 2007-2013, Gulf Coast has generated ~$400 MM of cash flow in excess of capex.

Reserves as of 12/31/13; production for full year 2013Mid-point of guidanceNet, unrisked resource potential Our Properties 5 (CHART) PRODUCTION:38.0 Bcfe (1)(63% Long Life)2014 Guidance48 Bcfe26% Growth (2)(CHART) RESERVES: 301.8 Bcfe (1) (81% Long Life) (CHART) INVENTORY:2.3 Tcfe (3) (95% Long Life) Denotes PetroQuest offices Tulsa

Valuation Decoupled from Strong Growth Valuation Decoupled from Strong Growth 2014 production mid-point of guidanceYE10 and YE132014 avg. analyst EBITDA from Thomson Reuters as of 2/5/2014Debt as of YE10 and YE13 Closing price at 12/31/10 and 2/5/14 6

7 Onshore Growth Assets Accelerate Development of Long-lived, Low-risk Woodford Shale and Cotton Valley Assets

Mid-Continent 8 OKLAHOMA WoodfordShaleTrend~ 93,000Gross acres Miss Lime Trend ~ 54,000 Gross acres Areas of Interest Tulsa Oklahoma City

Woodford Position - Ramping Up Development 9 Asset Highlights and Current Liquids Rich Focus:Average IP rate: 2,869 Mcf/d and 275 BOE of NGLs/dAverage EUR: 661 MBOE (59% gas - 41% NGL)Producing ~900 Bbls/d net of NGLs*Recent leasing adds significant drilling inventory16 wells drilled in 2013 and 50 wells planned for 201410 multi-well pads throughout 2014First 5 well pad currently completing Legacy Gas Acreage ~60,000 acres Expansion Area Liquids Rich Acreage~35,000 acres * 2013 production

Woodford Liquids Rich Gas 10 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 $ 3.50 $ 25 83% 75% 67% IRR % 1245 BTU, 121 bbl NGL/Mcf $ 4.00 $ 28 106% 96% 87% IRR % Well Cost - $3.75 to $4.25 MM $ 4.50 $ 31 129% 117% 107% IRR % *Henry Hub *Henry Hub *Henry Hub *Henry Hub *Henry Hub *Henry Hub *Henry Hub Payout: 12 Months 2014 Horizontal Well Economics (CHART) Capital $4MM

(CHART) Continuous Improvement in the Woodford 11 PetroQuest Operated Woodford Horizontal Wells 34% Improvement in Average Production

PQ Woodford Performance 12 (CHART) 2014: Most Active Year In Company's History A record 50 Gross Wells expected to be drilled in 2014 Dry Gas Wells

East Texas 13 Horizontal Cotton ValleyProgram

Horizontal Cotton Valley Operator Activity Operator Activity Operator Activity Operator Gross Acres Hor. CV Wells 14

15 PQ CV Horizontal (210 Wells) DevelopmentProgram* PQ 2014 (6 - 7 Wells)CV Drilling Plan Existing CV Horizontal Wells DRILLING INVENTORY GrossFormation Count BCFE Travis Peak Verticals 197 103CV Horizontals 210 1,174Bossier Horizontals 188 940 595 2,217 197 Travis PeakLocations * Additional 500+ Upper & Middle CV Horizontal Prospective Wells PQ Bossier Horizontal Development Horizontal Cotton Valley Inventory

Liquids Rich Cotton Valley Program 6 non-operated wells completed in 2011Average IP rate of 3.9 Mmcf/d and 244 barrels of NGLs/d9 operated wells completed in 2011 - 2013Average IP rate of 5.5 Mmcf/d and 371 barrels of NGLs/dAverage EUR of 973 MBOE (72% gas - 25% NGL - 3% oil)1 well in 2013 (6.3 Mmcf/d and 458 barrels of NGLs/d)6 well program underway for 2014 16 (CHART) Ramping Up Expanding Existing Operations

Liquids Rich Cotton Valley Program 17 (CHART) Average IP Rates Up 44% True Resource Play - Improving Well Performance With Each New Well

Liquids Rich Horizontal Cotton Valley 18 IRR Assumptions: IP Rate - 6.3 MMcfd, 458 Bbls NGLs EUR - 6.5 Bcfe Well Cost - $5.96 MM (CHART) Horizontal Well Economics Gas* NGL IRR Payback $ 3.50 $ 30 39.7 % 20 Months $ 4.00 $ 35 51.6 % 16 Months $ 4.50 $ 40 65.6 % 12 Months *Henry Hub

Mississippian Lime - Utilizing Science to Enhance Value 19 Drilling MS Lime Wells PQ Acreage Early Core Area Kansas Oklahoma PQ Woodford Activity Area MS Lime Horizontal Activity Area PQ Kay PQ PawneePQ #9 IP: 1,291 boe/d RRCAverage EUR: 485-600 Mboe SpyglassIP: 1,108 boe/d DVNIP: 960 boe/d OEDVIP: 1,185 boe/d SDIP: 885 boe/d PQ Grant Phase I: Exploration - 14 wells - High Visibility / High Variability (market)Phase II: 3-D Acquisition/Reservoir Modeling (2013-2014)Phase III: Development - 2014+ 24 Hour Avg Rate 425 Boe 30 Day Avg Rate 249 Boe PQ 3-D Evaluating PQ 3-D Evaluating

Cash Flowing Gulf Coast Assets 20 XX combined years of experience finding, developing and operating in the Gulf of Mexico and Gulf Coast region Attractive Development Prospects with Minimal Funding Requirements

Gulf Coast 21 Houston Lafayette Areas of Interest:Onshore S. LA / Shallow Water GOM

Gulf Coast Assets: Free Cash Flow Funds Growth 22 Revenues less LOE and severance taxes from GCB(CHART) Over $400MM of Free Cash Flow since 2007 (1)

La Cantera/Thunder Bayou Shallow Fields 23

Thunder Bayou Stratigraphic Cross Section 24

La Cantera/Thunder Bayou Deep Expressions 25

Pelican Point #2 26

PQ Operated Gulf Coast Drilling Summary PQ Operated Gulf Coast Drilling Summary 27 Prospect NRI First Production Feet of Pay I.P. Rate Thibodeaux #1(La Cantera Prospect) 17% March 12 248' Net TVD 36,000 Mcfe Broussard Estates #2 (La Cantera Prospect) 17% Sept 12 310' Net TVD 52,000 Mcfe Broussard Estates #3 (La Cantera Prospect) 17% May 13 54' Net TVD 35,000 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% 2014 34' Net TVD TBD Tokay - SS72 80% Nov 13 209' Net TVD 7,300 Mcfe Near-Term Activity Recent Projects

Funding The Future 28 History of Growth Funded With Cash Flow Total company drilling success rate of 95% Enhanced Liquids Profile Meaningfully Improves Cash Flow and Margins

29 Accelerating Cash Flow Profile Discretionary Cash Flow * Total Production Oil Production (CHART) $MM (CHART) MMcfe/d (CHART) Bbls/d Up 126% 29 * See Appendix 3 for reconciliation of discretionary cash flow to net income** Excludes $2.9MM in non-recurring transaction related costs*** Based on mid-point of guidance ** *** ***

Debt Metrics - Poised for Improvement with Growing Cash Flow Profile 31 Debt/EBITDA Comparison Debt/EBITDA Comparison EBITDA calculated as 3Q13 EBITDA annualized (excludes $2.9MM in non-recurring transaction costs)Total debt as of 12/31/13Interest calculated as 3Q13 interest expense + 3Q13 capitalized interest annualizedReserves as of 12/31/13 Liquidity calculated as sum of cash and availability under borrowing baseSee reconciliation of EBITDA to net income on appendix 2 Borrowing base reaffirmed at $200 million 12/31/13 Liquidity(5):Liquidity = $133 million Future drilling carry = $51.6 million Debt Ratios (CHART)

Capital Investment Program (Liquids Focused) 32 2014E $115 - $125 million (2)Drill 65 - 70 Wells Production based on the mid-point of guidanceExcludes $25 million estimate for cap overhead & interest (CHART) (CHART) Over 100% Increase in Drillbit Activity

Committed to Fund Drilling with Cash Flow 33 MM$ Total Direct CapEx and Cash Flows for the period between 2005 and 2012 PQ has balanced Capex and cash flow over the past 8 years (1) (1) Other proceeds include: sale of gathering system, equity proceeds, JV proceeds and other asset sales (CHART)

The Opportunity GROWTH: Positioned to post record reserves and production in 2014 through internally funded budgetVALUE: Currently trading at 1.8x analyst 2014E cash flow estimate (1)CATALYSTS: High impact Gulf Coast projectsSignificant increase in operational data points Substantial leverage to potentially under supplied gas marketBalanced, diversified asset portfolio(2)3 core basins - Mid-Con, East Texas, Gulf Coast/GOM81% proved reserves in long-life basins 63% production in long-life basins124% liquids growth (2012-2014E) 34 Based on Thomson Reuters average analyst CF estimate and stock price as of 2/5/20142013

Appendix 35

Appendix - 1 Hedging Positions 36 Natural Gas Daily Hedged Volumes (Mmbtu) Price 2014 10,000 $4.00 2014 20,000 $4.20 Mar14 - Dec14 5,000 $4.29 Oil Daily Hedged Volumes (Bbls) Price 2014 400 $101.15 (1) 2014 350 $93.26 (2) Jan14 - Jun14 450 $100.58 (1) LLS IndexWTI Index Current hedge portfolio locks in over $100 million in 2014 revenue

Appendix - 2 Adjusted EBITDA represents net income (loss) before income tax, interest expense (net), dividends, depreciation, depletion, amortization, non-cash stock compensation expense, gain on sale of gathering assets, accretion of asset retirement, non-cash derivative expense, ceiling test writedowns and loss on early extinguishment of debt and non-cash legal settlement. 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. 37 ($ in thousands) 2008 2009 2010 2011 2012 3Q13 9M13 Net Income (Loss) ($102,100) ($95,330) $41,987 $5,409 ($137,218) $383 $6,652 Income tax expense (benefit) (55,581) (14,635) 1,630 (1,810) 1,636 17 (474) Interest expense & dividends 14,467 17,754 15,091 14,787 14,947 9,358 17,905 Depreciation, depletion, and amortization 134,340 84,772 59,326 58,243 60,689 22,475 49,882 Loss on early extinguishment of debt - - 5,973 - - - - Gain on sale of gas gathering assets (26,812) - - - - - - Non cash stock compensation 9,582 6,328 7,137 4,833 6,910 1,310 3,105 Non cash gain on legal settlement - - (4,164) - - - - Accretion of asset retirement obligation 1,317 2,452 1,306 2,049 2,078 543 1,203 Derivative (income) expense - - - - 233 45 202 Ceiling test writedown 266,156 156,134 - 18,907 137,100 - - Adjusted EBITDA $241,372 $157,475 $128,286 $102,418 $86,375 $34,131 $78,475

Appendix - 3 ($ in thousands) 2008 2009 2010 2011 2012 2Q13 3Q13 9M13 Net income (loss) ($96,960) ($90,190) $47,126 $10,548 ($132,079) $4,949 $1,670 $10,506 Reconciling items: Deferred tax expense (benefit) (55,581) (14,635) 1,630 (1,810) 1,636 (840) 17 (474) Gain on sale of assets (26,812) (485) - - - - - - Non-cash gain on legal settlement - - (4,164) - - - - - Depreciation, depletion and amortization 134,340 84,772 59,326 58,243 60,689 14,536 22,475 49,882 Non-cash share based compensation 9,582 6,328 7,137 4,833 6,910 1,224 1,325 3,105 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 1,317 1,512 1,306 2,049 2,078 328 543 1,203 Other 1,492 913 1,334 625 1,114 (388) 687 936 Discretionary cash flow $233,534 $146,801 $119,668 $93,395 $77,448 $19,809 $26,717 $65,158 Changes in working capital accounts (45,096) (23,176) 18,250 25,400 13,770 (8,292) (12,102) (29,834) Settlement of asset retirement obligations (19,377) (1,803) (6,274) (905) (2,627) (22) (2,321) (2,415) Net cash flow provided by operating activities $169,061 $121,822 $131,644 $117,890 $88,591 $11,495 $12,294 $32,909 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. 38

Appendix 4 - GOM Assets Acquired 39 Producing Field (Gas)Producing Field (Oil)Legacy Field WD 89 D-1WD 89 D-2WD 89 D-3WD 89 D-4WD 89 D-5 GA 186L A-1 ST MP 72/74 WC 401 EC 222 La Cantera SS 72/225 SS 238 C-1 (#6)SS 238 C2 EI 246 J-1EI 246 J-2EI 246 J-3 VR 229 A-1 EC 160 A-7EC 160 A-8 EC 65 D-1 EC 65 D-2

Proved 3P Reserves 5.3 MMBoe 8.5 MMBoe PV10(1) $171 MM $278 MM F&D per BOE $36.41 $22.66 Price/PV10 1.1x 0.7x Price per BOE/D(2) ~$45,000 ~$45,000 Appendix 5 - Acquisition Overview Appendix 5 - Acquisition Overview 40 PQ operates ~80% of productionUpside: Interest in 7 - 5,000 acre Blocks which our technical team will explore As of July 1, 2013 with strip pricing averaging $4.37 /Mcf and $92.32 BblBased on May 2013 production Attractive Price for Cash Generating Assets $MM $278

Appendix 6 - History of Positive Reserve Revisions - Main Pass #74 Example 41 1P Reserves 3P Reserves Lease Line Water Level at Discovery SEC Booked Reserves Original Booked Reserves (1P) 2003: 7.6 Bcfe (net) Positive Reserve Revisions (3P): 23.7 Bcfe (net)Cumulative Produced Reserves 2003 - 2012 : 31.3 Bcfe (net)

Appendix 7 - Woodford JV Transaction Summary Woodford JV closed May 2010 whereby partner received 29 Bcfe of PUD reserves and right to earn 50% of Woodford acreageReceived cash payments totaling $88.0 millionThrough 12/31/13 have utilized drilling carry totaling $95.0 millionAt 12/31/13 - $51.6 million of drilling carry remains whereby partner pays 75% of well costs for a 50% ownershipUnder accelerated program all wells drilled in 2013 and 2014 are expected to benefit from promoteEnables all liquids rich acreage to be HBP with promoted dollars 42

Source: compiled from public domain production data Data reported: March 2008 - December 2012 Max Monthly Gas Rate, Mcfd Appendix 8 - PQ Woodford Performance 43

Appendix 9 - La Cantera Development 44 40,000 MCF/D + 740 Bbls of oil2-3 Year Reserve Life 30,000E MCF/D + 500 Bbls of oil2-3 Year Reserve Life 40,000E MCF/D + 800 Bbls of oil2-3 Year Reserve Life 30,000 MCF/D + 500 Bbls of oil2-3 Year Reserve Life 30,000 MCF/D + 500 Bbls of oil2-3 Year Reserve Life 40,000E MCF/D + 800 Bbls of oil2-3 Year Reserve Life Lower Cris R-1 Lower Cris R-2, Lobe A Lower Cris R-2, Lobe B Lower Cris R-2, Lobe C (CURRENTLY PRODUCING) (CURRENTLY PRODUCING) ~200 feet of potential pay

Appendix 10 - Panola County Cotton Valley - Room to Run Appendix 10 - Panola County Cotton Valley - Room to Run 45 LegendCotton Valley Wells PQ CV Vertical Wells PQ CV Horizontal Wells PQ Area of Mutual Interest Carthage Field Area - 4.4 TCF of Unrisked Resource Potential 2.2 Tcfe of CV/TP/BossierUnrisked Resource Potential

400 East Kaliste Saloom Road, Suite 6000 Lafayette, Louisiana 70508 Phone: (337) 232-7028 Fax: (337) 232-0044 www.petroquest.comNYSE: PQ 47