Attached files
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| 8-K - 8-K - PETROQUEST ENERGY INC | august15presentation.htm |
August 2015
Forward-Looking Statements 2 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 in this presentation are forward-looking statements. Although PetroQuest believes that the expectations reflected in these forward-looking statements are reasonable, these statements are based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014, our estimate of the sufficiency of our existing capital sources, including availability under our senior secured bank credit facility and the result of any borrowing base redetermination, our ability to raise additional capital to fund cash requirements for future operations, the effects of a financial downturn or negative credit market conditions on our liquidity, business and financial condition, 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 ability to find oil and natural gas reserves that are economically recoverable, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, our ability to realize the anticipated benefits from our joint ventures or divestitures, the timing of development expenditures and drilling of wells, hurricanes, tropical storms and other natural disasters, changes in laws and regulations as they relate to our operations, including our fracking 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
Our Properties 3 Gulf Coast Mid-Con Woodford Shale East Texas Cotton Valley • ~52,000 gross acres (~28,000 net acres) • 2Q15 production: 37.4 Mmcfe/d • 2014 wells(2) avg. IP 11.9 Mmcfe/d • 2015 wells avg. IP 14.2 Mmcfe/d • Planning to restart drilling in 4Q15 • 2Q15 production: 34.5 Mmcfe/d • Thunder Bayou discovery producing at ~40 Mmcfe/d Denotes PetroQuest offices East Texas Gulf Coast Mid-Con 2014 PF Reserves (1) 170 Bcfe East Texas Gulf Coast Mid-Con 2Q15 PF Production (1) 75 Mmcfe/d • Sold majority of assets in June 2015 • $280 MM of gross proceeds • Retained East Hoss JV – 38 well program (1) Proforma for Arkoma divestiture (2) Excludes PQ #11 well which experienced mechanical issues during completion.
Arkoma Divestiture Overview 4 Sold majority of Woodford and Mississippian Lime Assets Gross proceeds of $280 million Net operating cash flow of approximately $7.5 million (1Q15) from sold assets Sold approximately 227 Bcfe proved reserves (63% Developed) as of 12/31/14 and 46 MMcfe/d (1Q15) Attractive Valuation Metrics Price/2015E CF(1): 9.3x $/Mcfe Proved Reserves (12/31/14): $1.23 $/Flowing Mcfe/d (1Q15): ~$6,000 ~ $7,000/acre Use of Proceeds Repaid all borrowings under credit facility ~$130 million of cash proceeds and $14 million in deferred payments to balance sheet available to fund future Cotton Valley drilling and/or additional deleveraging (1) 1Q15 annualized field level cash flow
Liquidity and Debt Metrics Post Arkoma Divestiture 19.6 150.1 0 50 100 150 200 1Q15 2Q15 $ M M 5 Liquidity Position (1) Total Debt (net of cash) (2) 421 209 3.2 2.0 1 3 5 0 100 200 300 400 500 1Q15 2Q15 $ M M (1) Liquidity defined as availability under bank credit facility net of working capital (2) $350 MM 10% Senior Notes due 2017 (net of cash); see appendix 2 for reconciliation of Adjusted EBITDA to Net Income TT M D e b t to A d ju st e d E B IT D A
Strategic Rationale for Divestiture Attractive Valuation Metrics Proceeds of 9X cash flow are highly accretive to corporate multiple with sold assets embedded Significantly enhances liquidity and financial flexibility No bank borrowings outstanding post-sale ($70 million borrowing base) ~7X increase in liquidity (adjusted for working capital) Over $2.00/share of cash on hand provides additional deleveraging options Allows for operational focus on Company’s best asset: Cotton Valley Last 9 wells have added over 70 Bcfe of net proved reserves ~1 Tcfe (1) of net risked inventory in Cotton Valley Planning to restart drilling program in fourth quarter 2015 6 (1) PQ internal estimate
Industry Activity - Cotton Valley Trend 7 Hutchinson 9: 14.9 MMcfe/d EGP 63: 12.6 MMcfe/d Killen 13: 13.1MMcfe/d Wright 13: 30.3 MMcfe/d Werner 29: 26.7 MMcfe/d Colvin Estate 28: 26.6 MMcfe/d Berry 24H: 11.1 MMcfe/d Breffeilh: 11.1 MMcfe/d Walton 23H: 10.6 MMcfe/d PQ#13: 12.3 MMcfe/d PQ#14: 13.5 MMcfe/d PQ#15: 11.4 MMcfe/d PQ#16: 16.7 MMcfe/d PQ#17: 14.2 MMcfe/d PQ #18: 11.7 Mmcfe/d King 25H: 16.6 MMcfe/d Fullen 11H: 14.5 MMcfe/d Fullen 4H: 13.9 MMcfe/d Biggs 5H: 12.6 MMcfe/d Hancock Smith 2H: 11.3 MMcfe/d Rogers 6H: 11.3 MMcfe/d Lloyd 6H: 11.3 MMcfe/d Ritter 4H: 16.6 MMcfe/d Crow 2H: 17.4 MMcfe/d Pone 7H: 13.3 MMcfe/d Relative Rock Quality Comparison Porosity Marcellus (5%) PQ Cotton Valley (10%) Gulf Coast (28%) Permeability Marcellus (.01 MD) PQ Cotton Valley (10 MD) Gulf Coast (1,000 MD)
Cotton Valley Horizontal – Production Up with Cost Down 8 Improving Well Performance (1) Excludes PQ #11 well which experienced mechanical issues during completion. 2014 and Initial 2015 Horizontal Cotton Valley Results $6.9 $5.6 $5.2 $4.5 4,232 4,106 4,147 3,000 3,500 4,000 4,500 5,000 $4.0 $5.0 $6.0 $7.0 $8.0 2013 2014 (1) 2015 Target La te ra l F e e t A ve rag e D & C C o st D&C (8/8's) $MM Lateral Length 0 2 4 6 8 10 12 14 2011 2012 2013 2014 (1) 2015 Gas Liquids 6.3 7.4 9.1 11.9 14.2 PQ#10 PQ#11 PQ#12 PQ#13 PQ#14 PQ#15 PQ#16 PQ#17 PQ#18 IP Rate (Mmcfe/d) 10.7 7.9 11.7 12.3 13.5 11.4 16.7 14.2 11.7 30 Day Avg. Rate (Mmcfe/d) 9.9 6.7 10.2 13.8 14.5 13.6 16.4 14.1 11.9 60 Day Avg. Rate (Mmcfe/d) 9.1 5.8 8.8 13.4 13.7 13.5 13.9 13.2 N/A 90 Day Avg. Rate (Mmcfe/d) 9.0 5.2 7.7 13.6 11.7 13.0 N/A N/A N/A
Cotton Valley Horizontal Economics 9 Assumptions (1) Gross Well Cost ($MM) 5.0 EUR (Bcfe) 8.6 IP Rate (Mmcfe/d) 11.9 % Gas / Liquids 70% / 30% IRR (%) 47% Payback (Yrs) 1.7 (1) 2014 Avg. well performance; excluding PQ#11; $3.00 gas, $18 NGL and $50 oil Sensitivity to Gas Prices 0 2000 4000 6000 8000 10000 12000 1 1 7 3 3 4 9 6 5 8 1 9 7 1 1 3 1 2 9 1 4 5 1 6 1 1 7 7 1 9 3 2 0 9 2 2 5 2 4 1 2 5 7 2 7 3 2 8 9 3 0 5 3 2 1 3 3 7 3 5 3 3 6 9 3 8 5 4 0 1 4 1 7 4 3 3 4 4 9 4 6 5 4 8 1 M C FP D DAYS FROM FIRST PRODUCTION PQ #9 PQ #10 PQ #12 EUR: 9.8 Bcfe Economic Assumptions $4.5 MM D&C $5.0 MM D&C 35% 56% 77% 29% 47% 65% 20 30 40 50 60 70 80 $2.50 $3.00 $3.50 IR R - % Horizontal CV Well Economics
10 Samson 10 Wells Average IP:10.7 MMcfe/d Cotton Valley Acreage Position MRD 3 Wells Average IP:10.8 MMcfe/d PQ #18 11.7 MMcfe/d 2014-2015 Avg 12.3 MMcfe/d 52,000 Gross Acres (100% HBP) 236 Gross Future Locations (118 Net)
11 One Year (6 wells) Cotton Valley Growth 5.7 9.5 4 5 6 7 8 9 10 BCF E 67% Growth in Production 12/31/13 12/31/14 • 2014 growth metrics above achieved with 6 gross wells and net capital of ~ $39 million resulting in F&D of ~ $0.76/Mcfe. • Plan to restart drilling in 4Q15 with 6-7 gross wells planned in 2016 47.6 89.2 20 30 40 50 60 70 80 90 BCF E 87% Growth in Reserves 12/31/14 PROVED RESERVES PRODUCTION 12/31/13
Cotton Valley – Significant Undrilled Inventory 12 47.6 106.5 826 0 100 200 300 400 500 600 700 800 900 E. Texas Proved 12/31/13 E. Texas Proved 6/30/2015 Net Risked Potential BCF E (9 New Wells) ~125% Growth in reserves since Jan 2014 * * Assumes 118 net locations at ~7.0 BCFE per well. The EUR assumption represents the average of the 18 horizontal wells drilled to date.
Horizontal Cotton Valley Net Present Value Creation 13 18 PQ Operated Wells Gross PV-10 ($M) (1) Current Gross Well Cost ($M) (2) Gross NPV ($M) PQ #1 - 2011 7,280 5,000 2,280 PQ #2 - 2011 6,860 5,000 1,860 PQ #3 - 2011 9,744 5,000 4,744 PQ #4 - 2012 4,871 5,000 -129 PQ #5 - 2012 10,956 5,000 5,956 PQ #6 - 2012 8,472 5,000 3,472 PQ #7 - 2012 5,870 5,000 870 PQ #8 - 2012 8,012 5,000 3,012 PQ #9 – 2013 9,946 5,000 4,946 PQ #10 - 2014 10,907 5,000 5,907 PQ #11 - 2014 5,466 5,000 466 PQ #12 - 2014 4,983 5,000 -17 PQ #13 - 2014 10,512 5,000 5,512 PQ #14 - 2014 8,842 5,000 3,842 PQ #15 - 2014 15,086 5,000 10,086 PQ #16 - 2015 8,861 5,000 3,861 PQ #17- 2015 10,670 5,000 5,670 PQ #18 - 2015 10,080 5,000 5,080 Average 8,745 5,000 3,745 NET – NPV of 18 well average (WI 50%) (3) 1,873 Outstanding Shares 64,774 Avg Net - NPV of well/share $0.03/share 236 gross drilling locations value/share $7.08/share (1) 6/30/15 SEC price: $3.39/mcf of gas, $71.68/Bbl of oil and $19.35/Bbl of NGL (2) 2015 average well cost (3) Average working interest for the 236 future drilling locations
Gulf Coast – Free Cash Flow Generator 14 Houston Lafayette Areas of Interest: Onshore S. LA / Shallow Water GOM Key Operating Metrics (1) Cash Flow = Revenues less lease operating expenses and severance taxes from Gulf Coast/Gulf of Mexico. Please see Appendix 4 for reconciliation. (2) 2014 Capex excludes non-cash Fleetwood accruals and 2013 Capex excludes GOM acquisition. Gulf Coast Assets: Free Cash Flow Funds Growth (1)(2) La Cantera / Thunder Bayou Ten Year Drilling Success Rate: 70% PV-10 ($MM) (12/31/14): $ 209 2Q15 Production (Mmcfe/d) 35 % Gas: 65% % NGL: 10% % Oil: 25% Over $400MM of Free Cash Flow since 2007 ~$40 MM FCF 0 20 40 60 80 100 120 140 160 180 200 2007 2008 2009 2010 2011 2012 2013 2014 $ M M Gulf Coast Cash Flow Gulf Coast Capex
LaCantera/Thunder Bayou Deeper Pool Tests 15 ERATH FIELD Composite Outline of Field Pay 1.4 TCFE SOUTH ERATH DISCOVERY MID CRIS R HILCORP LIVE OAK FIELD 680 BCFG 11.7 MMBO STONE LA MONTANA PROSPECT 2015 /2016 SPUD LACANTERA DISCOVERY VOLUMES Booked – 125 BCFE 3P - 180 BCFE TIGRE LAGOON/ SOUTH TIGRE LAGOON FIELDS Composite Oultine of Field Pays Cris I, Disc B, Siph d, Planulina 565 BCFE THUNDER BAYOU 228 feet of Net Pay IP: ~40,000 MCFE Booked – 40 BCFE 3P – 150 BCFE
Thunder Bayou Supports Near-Term Production Growth 16 69 78 60 65 70 75 80 1Q15PF 3Q15E (1) Proforma for Arkoma divestiture (2) Mid-point of 3Q15 production guidance Production (MMcfe/d) (2) • Initiated production from Thunder Bayou late-June • Well is currently flowing at gross rate of 40 Mmcfe/d comprised of: • 800 BBls/d of oil • 1,200 BBls/d of NGLs • 28,000 Mcf/d of gas • Recompletion scheduled for 1H16 in the primary sand package (116-137 Bcfe) • Expected to provide significant increase in well’s gross production rate for ~$800k (1)
Woodford Position 17
Woodford Dry Gas – East Hoss Joint Venture 18 Price JV Terms Gas* IRR $ 3.00 39% $ 3.50 57% $ 4.00 77% *Henry Hub JV Terms (1), (2) EUR (Bcf) 4.3 Gross Well Cost ($MM) 5.0 IP Rate (Mmcf/d) 4.0 % Gas 100% IRR (%) 57% Payback (Yrs) 1.4 • 38 dry gas wells included in joint venture • JV provides extremely beneficial cost sharing provisions for PQ • Currently completing 8 wells (Avg NRI 15%) Sensitivity to Gas Prices Economic Assumptions East Hoss Joint Venture Agreement (1) Assumptions based on average historical results to date and management estimates (2) Return and payback assumptions based on $3.50 gas 57% 82% 109% 39% 57% 77% 0% 20% 40% 60% 80% 100% 120% $3.00 $3.50 $4.00 IR R Capex 4MM$ Capex 5MM$
Summary Arkoma Divestiture - significant liquidity building and deleveraging event Zero drawn on $70 million borrowing base Large cash position provides additional deleveraging options for $350 million 10% Senior Notes due September 2017 Focused Strategy to develop significant Low-Risk inventory “Primary Focus” – Multi-year inventory Horizontal Cotton Valley development “Cash flow generator” with high historical success rate – Gulf Coast/GOM Restart of Cotton Valley drilling along with Thunder Bayou recompletion offers 2016 growth potential with reduced capex Liquidity position ($150 million@ 6/30/15)* and control of operations provide flexibility to navigate current environment 19 * Availability under bank credit facility net of working capital
20 Appendix
Appendix 1 - Hedging Positions 21 Natural Gas Daily Hedged Volumes (Mmbtu) Price 2015 20,000 $3.97 2015 10,000 $3.52 Mar15 - Dec15 10,000 $3.00 Apr15 – Sep15 5,000 $2.89 July15 - Jun16 10,000 $3.22 Total 55,000 $3.49 Average Oil Daily Hedged Volumes (Bbls) Price Feb15 – Dec15 250 $54.00 (1) Mar15 – Dec15 250 $59.35 (1) Total 500 $56.68 Average (1) LLS Index NGL (Propane) Daily Hedged Volumes (Bbls) Price Mar15 – Dec15 250 $25.62
Appendix 2 – Adjusted EBITDA Reconciliation Adjusted EBITDA represents net income (loss) available to common stockholders before income tax expense (benefit), interest expense (net), preferred stock dividends, depreciation, depletion, amortization, loss on early extinguishment of debt , share based compensation expense, non-cash gain on legal settlement , accretion of asset retirement obligation, derivative (income )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) available to common stockholders to Adjusted EBITDA for the periods presented. 22 ($ in thousands) 2010 2011 2012 2013 2014 2Q15 LTM 2Q15 Net Income (Loss) available to common stockholders $41,987 $5,409 ($137,218) $8,943 $26,051 ($61,083) ($176,907) Income tax expense (benefit) 1,630 (1,810) 1,636 320 (2,941) 2,000 (1,868) Interest expense & preferred dividends 15,091 14,787 14,947 27,025 34,420 9,883 35,874 Depreciation, depletion, and amortization 59,326 58,243 60,689 71,445 87,818 18,345 84,687 Loss on early extinguishment of debt 5,973 - - - - - - Share based compensation expense 7,137 4,833 6,910 4,216 5,248 1,350 5360 Gain on Asset Sale (21,531) (21,531) Non-cash gain on legal settlement (4,164) - - - - - - Accretion of asset retirement obligation 1,306 2,049 2,078 1,753 2,958 823 3,141 Derivative (income) expense - - 233 (233) - - - Ceiling test writedown - 18,907 137,100 - - 65,495 174,406 Adjusted EBITDA $128,286 $102,418 $86,375 $113,469 $153,554 $15,282 $103,162
Appendix 3 - Discretionary Cash Flow Reconciliation ($ in thousands) 2011 2012 2013 2014 6M15 Net income (loss) $10,548 ($132,079) $14,082 $31,190 ($180,756) Reconciling items: Income tax expense (benefit) (1,810) 1,636 320 (2,941) 1,073 Depreciation, depletion and amortization 58,243 60,689 71,445 87,818 38,999 Share based compensation expense 4,833 6,910 4,216 5,248 2,828 Gain on Asset Sale - - - - (21,531) Ceiling test write down 18,907 137,100 - - 174,406 Accretion of asset retirement obligation 2,049 2,078 1,753 2,958 1,682 Other 625 1,114 1,240 2,188 1,162 Discretionary cash flow $93,395 $77,448 $93,056 $126,461 $17,863 Changes in working capital accounts 26,686 13,770 (29,867) 55,370 (11,051) Payments to settle asset retirement obligations (905) (2,627) (3,335) (3,623) (1,186) Net cash flow provided by operating activities $119,176 $88,591 $59,854 $178,208 $5,626 Note: Management believes that discretionary cash flow is relevant and useful information, which is commonly used by analysts, investors and other interested parties in the oil and gas industry as a financial indicator of an oil and gas company’s ability to generate cash used to internally fund exploration and development activities and to service debt. Discretionary cash flow is not a measure of financial performance prepared in accordance with generally accepted accounting principles (“GAAP”) and should not be considered in isolation or as an alternative to net cash flow provided by operating activities. In addition, since discretionary cash flow is not a term defined by GAAP, it might not be comparable to similarly titled measures used by other companies. 23
Appendix 4 – Gulf Coast/GOM Free Cash Flow Reconciliation ($ in thousands) 2007 2008 2009 2010 2011 2012 2013 2014 Revenues $197,453 $198,949 $86,880 $100,618 $86,371 $61,788 $100,049 $121,859 Lease Operating Expense (18,483) ( 25,091) (18,907) (18,437) (16,292) (15,122) (21,407) (24,843) Severance Tax (4,931) (5,649) (2,633) (3,449) (2,866) (1,048) (2,176) (2,312) Field level cash flow $174,039 $168,209 $65,340 $78,732 $67,213 $45,618 $76,466 $94,704 Capital Expenditures (1) (65,770 ) (60,219) (15,677) ( 31,497) ( 31,082) (20,665) (43,872) (56,737) Free Cash Flow $108,269 $107,990 $49,663 $47,235 $36,131 $24,953 $32,594 $37,967 24 (1) 2014 Capex excludes non-cash Fleetwood accruals and 2013 Capex excludes GOM acquisition.
Appendix 5 - La Cantera Development 25 15,000 MCF/D + 250 Bbls of oil 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 (CURRENTLY PRODUCING) 16,000 MCF/D + 240 Bbls of oil 1,500 MCF/D + 42 Bbls of oil 35,000 MCF/D + 700 Bbls of oil
Appendix 6 - Panola County Cotton Valley – Room to Run 26 Legend Cotton 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/Bossier Unrisked Resource Potential
Appendix 7 - Strong Track Record of Funding Drilling with Cash Flow 27 $ M M Total Direct CapEx and Cash Flows for the period between 2005 and 2014 PQ has balanced Capex and cash flow over the past 10 years (1) (1) Other proceeds include: sale of gathering system, equity proceeds, JV proceeds and other asset sales $1,228 $1,263 $190 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 Direct CapEx (excluding acq.) Cash Flow Other Proceeds
Appendix 8 - Cotton Valley Horizontal – Horizontal Uplift 28 Horizontal Completions Realizing 12x EUR Uplift vs. Vertical Wells (1) Ryder Scott estimate excluding PQ #11 well which experienced mechanical issues during completion 0.7 8.6 0 1 2 3 4 5 6 7 8 9 10 61 Vertical Wells 2014 Horizontal Wells (1) A vg . B cfe / W e ll
Company Information 29 400 East Kaliste Saloom Road, Suite 6000 Lafayette, Louisiana 70508 Phone: (337) 232-7028 Fax: (337) 232-0044 www.petroquest.com Version 1 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 in this presentation are forward-looking statements. Although PetroQuest believes that the expectations reflected in these forward-looking statements are reasonable, these statements are based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014, our estimate of the sufficiency of our existing capital sources, including availability under our senior secured bank credit facility and the result of any borrowing base redetermination, our ability to raise additional capital to fund cash requirements for future operations, the effects of a financial downturn or negative credit market conditions on our liquidity, business and financial condition, 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 ability to find oil and natural gas reserves that are economically recoverable, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, our ability to realize the anticipated benefits from our joint ventures or divestitures, the timing of development expenditures and drilling of wells, hurricanes, tropical storms and other natural disasters, changes in laws and regulations as they relate to our operations, including our fracking 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.