Attached files
| file | filename |
|---|---|
| 8-K - 8-K - PETROQUEST ENERGY INC | investorpresentationupdate.htm |
August 2014
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. 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 our acquisitions with our operations and realize the anticipated benefits from the acquisitions, any unexpected costs or delays in connection with the acquisitions, our ability to find oil and natural gas reserves that are economically recoverable, our ability to realize the anticipated benefits from the Fleetwood joint venture, 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
(1) Ryder Scott reserves as of 12/31/13; Average daily production for 2Q:14 (2) Net risked resource potential based on Ryder Scott 12/31/13 reserve assumptions; management estimates Our Properties 3 Mid-Con East Texas Gulf Coast 2Q:14 PRODUCTION: 118 Mmcfe/d (1) (56% Long Life) Mid-Con East Texas Gulf Coast RESERVES: 301.8 Bcfe (1) (81% Long Life) Mid-Con East Texas Gulf Coast INVENTORY: 1.9 Tcfe (2) (96% Long Life) Denotes PetroQuest offices Gulf CoastMid-Con Woodford ShaleEast Texas Cotton Valley • 2Q:14 production: 15.4 Mmcfe/d • Last four wells averaged 12.2 Mmcfe/d IP; highest rate wells to date • ~30% liquids component enhancing returns (25% C4 / C5) • 2Q:14 production: 48.4 Mmcfe/d • JV and high liquids component enhance project returns • Last three wells averaged 7.9 Mmcfe/d IP; 48% liquids • 2Q:14 production: 52.0 Mmcfe/d • Commencing initial two wells in Fleetwood JV in 2H:14 • Thunder Bayou drilling with results expected 4Q:14 (65 Bcfe net unrisked potential)
Industry Activity - Cotton Valley Trend 4 Caplis 26H: 9.3 MMcf/d EGP 23: 7.9 MMcf/d Leonard 25H: 6.8MMcf/d Nobles 13H-1: 30.7 MMcf/d Nobles 13H-2: 22.7 MMcf/d Colquitt 20 17H: 16.8 MMcf/d Berry 24H: 12.1 MMcf/d Berry 25H: 11.1 MMcf/d Walton 23H: 10.8 MMcf/d PQ#13: 12.3 MMcf/d PQ#14: 13.5 MMcf/d PQ#15: 11.4 MMcf/d King 25H: 16.6 MMcf/d Minden GU 3H: 10.0 MMcf/d King 20H: 10.7 MMcf/d Biggs 5H: 12.6 MMcf/d Hancock Smith 2H: 11.3 MMcf/d Twomey Heirs: 11.3 MMcf/d Rogers 6H: 11.2 MMcf/d Maddox 10H: 11.0 MMcf/d Lloyd 6H: 10.9 MMcf/d Ritter 4H: 13.7 MMcf/d Crow 2H: 13.2 MMcf/d Pone 7H: 12.2 MMcf/d Hardy Heirs 2H: 13.9 MMcf/d Jarrell 9H: 8.8 MMcf/d Hardy Heirs 1H: 8.4 MMcf/d Relative Rock Quality Comparison Porosity Marcellus (5%) PQ Cotton Valley (15%) Gulf Coast (30%) Permeability Marcellus (.01 MD) PQ Cotton Valley (150 MD) Gulf Coast (100,000 MD)
0.7 6.3 9.8 0 1 2 3 4 5 6 7 8 9 10 11 61 Vertical Wells (1) 11 Horizontal Wells (1), (2) PQ#9 Av g. B cfe / W el l Cotton Valley Horizontal – Horizontal Uplift 5 Horizontal Completions Realizing 8x EUR Uplift vs. Vertical Wells (1) Represents average EUR for PetroQuest operated wells (2) Does not include most recent 3 wells
6.3 7.4 9.1 12.2 0 2 4 6 8 10 12 14 16 18 20 0 2 4 6 8 10 12 14 16 18 20 2011 2012 2013 2014 2015E Gro ss O pe rat ed W ells Av erag e IP Ra te (M mcf e\d ) Liquids Mmcf Gross Operated Wells Cotton Valley Horizontal –Moving Up the Curve 6 Improving Well Performance (1) (1) 2014 IP rates based off initial 5 wells drilled to date (1)
6.4 7.9 9.8 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5 10.0 Initial Booking (7/1/2013) Ryder Scott Res. Booking (1/1/2014) Performance Revision (7/1/2014) Bcf e Cotton Valley Horizontal – Increasing EURs 7 PQ#9 Well - Upward Reserve Revisions Booked EURs PQ#9 PQ#10 PQ#12 PQ#13 PQ#14 PQ#15 IP Rate (Mmcfe/d) 9.1 11.2 11.9 12.3 13.5 11.4 Original Reserve Booking (Bcfe) 6.4 7.4 6.4 TBD TBD TBD Updated Reserve Booking (Bcfe) 9.8 TBD TBD T T T
Cotton Valley Horizontal Economics 8 Assumptions (1) Gross Well Cost ($MM) 6.8 EUR (Bcfe) 9.8 IP Rate (Mmcfe/d) 9.1 % Gas / Liquids 70% / 30% IRR (%) 70% Payback (Yrs) 1.2 (1) Return and payback assumptions based on PQ#9 Performance; $4.00 gas / $27.00 NGL / $100 oil pricing Sensitivity to Gas Prices Carthage Cotton Valley Horizontal Type Curve 50% 70% 90% 110% $3.75 $4.00 $4.25$6.8MM D&C $6.0MM D&C IRR: 101% Payback: 0.9 years IRR: 84% Payback: 1.0 year IRR: 85% Payback: 1.0 year IRR: 70% Payback: 1.2 years IRR: 70% Payback: 1.2 years IRR: 57% Payback: 1.4 years Economic Assumptions 0 2,000 4,000 6,000 8,000 10,000 12,000 1 31 61 91 121 151 181 211 241 271 301 M C FP D DAYS FROM FIRST PRODUCTION PQ #9 PQ #10 PQ #12 PQ #9: EUR: 9.8 Bcfe
Cotton Valley Horizontal Planned Activity and Inventory 9 2014 - 2015 Expected Drilling Program Horizontal Cotton Valley Inventory • Approximately 10 year drilling inventory using 2015’s accelerated pace PQ 2015 (18 wells) CV Horizontals PQ 2014 (6 wells) CV Horizontals PQ 2011 – 2013 CV Horizontal Wells PQ CV Horizontal well Inventory
Cotton Valley Drilling to Unlock NAV 10 48.1 506 0 100 200 300 400 500 600 E. Texas Proved 12/31/13 Net Risked Potential BCF E
Mid-Continent Woodford Shale 11 • We currently have a ~34,000 net JV acre position in the West Relay Field which lies approximately 8 miles to the west of our producing North Relay Field • Since our development program began at the beginning of 2014 we have successfully drilled 14 gross (5.9 net) wells with significantly higher IP rates and % liquids • Recently added a second rig with expectations to double well count in 2H:14 with plans to drill 26 gross (10.9 net) wells • PetroQuest pays 25% for a 50% interest in all wells through May 2015 (estimated) West Relay Field Overview
Woodford Position – Ramping Up Development 12 Legacy Dry Gas Acreage ~50,000 net JV acres (1) Relay Area (Liquids Rich Gas): • ~34,000 net JV acres (1) • 2 rigs running Hoss Area JV ( Dry Gas): • 38 well program • 2015 (2 rigs running) (1) PQ owns approximately 50% of net JV acres
36.3% 48.6% 4.6 7.1 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 North Relay (31 well avg.) West Relay (14 well avg.) Av era ge IP Rat e ( Mm cfe \d ) NGLs Gas West Relay Program - Strong Initial Results 13 Higher IP Rates and Liquids Mix
Woodford Liquids Rich Gas –West Relay Field 14 Price JV Terms Gas* NGL IRR $ 3.75 $ 23.00 95% $ 4.00 $ 26.00 117% $ 4.25 $ 29.00 145% *Henry Hub JV Terms (1), (2) EUR (Bcfe) 4.6 Gross Well Cost ($MM) 4.0 IP Rate (Mmcfe/d) 7.1 % Gas / Liquids 51% / 49% IRR (%) 117% Payback (Yrs) 1.1 Sensitivity to Gas Prices 50% 75% 100% 125% 150% 175% $3.75 $4.00 $4.25 IRR: 117% Payback: 1.1 years IRR: 145% Payback: 1.0 year IRR: 95% Payback: 1.2 years Economic Assumptions (1) Assumptions based on 14 gross well average historical results to date and management estimates (2) Return and payback assumptions based on $4.00 gas / $26.00 NGL pricing
Gulf Coast – Free Cash Flow Generator 15 Houston Lafayette Areas of Interest: Onshore S. LA / Shallow Water GOM Key Operating Metrics Fleetwood Project Area (1) Free Cash Flow Revenues less LOE and severance taxes from GCB (2) 1H:14 Capex excludes non-cash Fleetwood accruals Gulf Coast Assets: Free Cash Flow Funds Growth (1)(2) 0 20 40 60 80 100 120 140 160 180 200 2007 2008 2009 2010 2011 2012 2013 1H14 $ M M Gulf Coast Cash Flow Gulf Coast Capex Over $400MM of Free Cash Flow since 2007 La Cantera / Thunder Bayou Ten Year Drilling Success Rate: 73% PV-10 ($MM) (12/31/13): $ 255 2Q:14 Production (Mmcfe/d) 52 % Gas: 69% % NGL: 9% % Oil: 22%
Fleetwood JV Overview • Announced a $24 million joint venture agreement to develop a conventional onshore oil play • $10MM cash; $14MM carry to earn an average 50% w.i. in partners interest in Fleetwood project area • 30,000 gross acre position in West Baton Rouge, Pointe Coupee, Iberville Parishes • Includes exclusive rights to ~200 sq. mile 3D license • PQ operated(1) • 2H:14 target spud date for initial wells (Widgeon and Mallard) 16(1) PetroQuest expects to operate all but one of the drilling projects Mallard Widgeon • Repeatable, oil focused horizontal play (25% w.i.; operated) • $4.0 - $6.5 million D&C cost (8/8th’s) • 40 gross (10 net) drilling locations identified • Net unrisked reserve potential of ~ 3.8 Mmboe (86% oil) • Additional leasing opportunities available with early success • 13 nearby vertical wells have an average EUR of 80 Mboe / well • Uplift with horizontal well estimated at 3x – 5x • Lower Wilcox Prospect (25% w.i.; non-operated) • $3.5 - $5.5 million D&C cost (8/8th’s) • 17,500 foot single pipe test of a 4-way closure • Net unrisked reserve potential of ~ 36 Bcfe Fleetwood JV Overview
LaCantera/Thunder Bayou Deeper Pool Tests 17
LaCantera/Thunder Bayou Stratigraphic Cross Sections 18
PQ Operated Gulf Coast Drilling Summary Prospect WI Total Depth Gross Unrisked Reserves Spud Date Thunder Bayou 50% 21,000’ 162 Bcfe Drilling Widgeon (Fleetwood) (40 potential future locations) 25% 10,000’ 19,000 Mboe 2H:14 Mallard (Fleetwood; Non-operated) 25% 17,500’ 181 Bcfe 2H:14 Gadwall (Fleetwood) 50% 15,000’ 62 Bcfe 2015 Pintail (Fleetwood) 50% 9,700’ 72 Bcfe 2015 19 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% 2015 34’ Net TVD TBD Tokay – SS72 80% Nov 13 209’ Net TVD 7,300 Mcfe Eagle Crest 47% Aug 14 29’ Net TVD 877 Boe Near-Term Activity Recent Projects
20 Liquids Production Will Drive Cash Margin Expansion Bbls/d of Oil Bbls/d of NGLs Product Diversification – Gas to Liquids 3,889 1000 2000 3000 4000 5000 6000 7000 2011 2012 1H13 2H13 1Q14 2Q14 3Q14E* 4Q14E* 2,612 2,964 3,472 4,593 4,787 GOM Acquisition 6,622 B ar re ls of L iq u id s/D ay * Mid-point of guidance 5,567 5,833
Significant Sequential Cash Flow Growth* 21 $38.4 MM $54.7 MM $69.6 MM 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 1H13 2H13 1H14 D iscr et io n ar y CF ($ M M ) * See Appendix 3 for reconciliation of discretionary cash flow to net income
$142 $128 $183 $74.1 $121.0 $- $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 2011 2012 2013 1H:13 1H:14 Operating & Financial Metrics 22 Revenue ($MM) Avg. Net Daily Production (Mmcfe/d) PV-10 ($MM) (2) Discretionary Cash Flow ($MM) (1) (1) Please see reconciliation of discretionary cash flow in appendix 3 (2) Please see the Company’s annual 10-K for a reconciliation of PV-10 to standardized measure Oil NGL Gas $341 $239 $475 $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 2011 2012 2013 83 93 104 109 118 122 - 128 134 - 140 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 15 160 2011 2012 2013 1Q:14A 2Q:14A 3Q:14E 4Q:14E $93.4 $77.4 $92.6 $37.9 $69.6 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 2011 2012 2013 1H13 1H14
Debt Metrics – Poised for Improvement with Growing Cash Flow Profile 23 Debt/EBITDA Comparison 2013 2Q14 Target Debt to EBITDA (1)(4) 2.9X 2.5X ~2.0X Interest Coverage (2) (4) 3.5X 4.4X ~5.0X Debt to Proved Mcfe (5) $1.41 $1.40 ~ $1.00 (1) EBITDA calculated 2Q14annualized (2) Interest calculated as interest expense + capitalized interest annualized (3) Liquidity calculated as sum of cash and availability under borrowing base (4) See reconciliation of EBITDA to net income on appendix 2 (5) Proved reserves as of 12/31/13 and Debt as of 6/30/2014 (6) Peer EBITDA reported by Bloomberg for TTM 6/30/2014 Debt Ratios 1.7x1.8x 2.0x2.0x2.0x 2.1x2.3x 2.5x2.6x 2.6x 3.1x3.2x 3.2x 3.6x 4.2x 5.1x 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x D e b t to E B IT D A (6 )
Relative Market Valuation 24 Estimated P/CFPS for PetroQuest vs. Peers(1) 9.6x 8.6x 4.8x 4.2x 4.0x 3.8x 3.1x 3.0x 2.9x 2.7x 2.3x 2.0x 2.0x 1.9x 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 8.0x 9.0x 10.0x MRD RRC PDCE UPL CRZO GDP AREX SGY CPE BBG PQ PVA EXXI WTI ES T. 20 1 5 P /CFP S (1) Bloomberg Best Estimate as of 8/6/2014
The Opportunity GROWTH: Positioned to post record reserves and production in 2014 VALUE: Currently trading at 2.3x analyst 2014E cash flow estimate (1) CATALYSTS: Significant leverage to emerging Cotton Valley play High impact Gulf Coast projects Balanced, diversified asset portfolio(2) Growth in all 3 core basins – Mid-Con, East Texas, Gulf Coast/GOM 81% proved reserves in long-life basins 63% production in long-life basins 154% liquids growth (2012-2014E) 25 (1) Based on Bloomberg Best Estimate as of 8/6/2014 (2) December 2013
26 Appendix
Appendix 1 - Hedging Positions 27 Natural Gas Daily Hedged Volumes (Mmbtu) Price 2014 10,000 $4.00 2014 20,000 $4.20 Mar14 – Dec14 5,000 $4.29 2015 5,000 $4.32 Oil Daily Hedged Volumes (Bbls) Price 2014 400 $101.15 (1) 2014 350 $93.26 (2) Jul14 – Dec14 250 $100.90 (1) (1) LLS Index (2) WTI Index NGL (Natural Gasoline) Daily Hedged Volumes (Mmbtu) Price Jul14 – Dec14 100 $91.56
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. 28 ($ in thousands) 2008 2009 2010 2011 2012 3Q13 4Q13 2013 1H14 Net Income (Loss) ($102,100) ($95,330) $41,987 $5,409 ($137,218) $383 $2,291 $8,943 $19,635 Income tax expense (benefit) (55,581) (14,635) 1,630 (1,810) 1,636 17 794 320 - Interest expense & dividends 14,467 17,754 15,091 14,787 14,947 9,358 9,120 27,025 17,583 Depreciation, depletion, and amortization 134,340 84,772 59,326 58,243 60,689 22,475 21,563 71,445 42,130 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 1,111 4,216 2,716 Non cash gain on legal settlement - - (4,164) - - - - - - Accretion of asset retirement obligation 1,317 2,452 1,306 2,049 2,078 543 550 1,753 1,499 Derivative (income) expense - - - - 233 45 (31) (233) - 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 $35,398 $113,469 $83,563
Appendix 3 - Discretionary Cash Flow Reconciliation ($ in thousands) 2011 2012 1H13 2H13 2013 1H14 Net income (loss) $10,548 ($132,079) $8,836 $5,246 $14,082 $22,202 Reconciling items: Deferred tax expense (benefit) (1,810) 1,636 (491) 811 320 - Depreciation, depletion and amortization 58,243 60,689 27,407 44,038 71,445 42,130 Non-cash share based compensation 4,833 6,910 1,780 2,436 4,216 2,716 Ceiling test write down 18,907 137,100 - - - - Accretion of asset retirement obligation 2,049 2,078 660 1,093 1,753 1,499 Other 625 1,114 (249) 991 742 1,094 Discretionary cash flow $93,395 $77,448 $38,441 $54,615 $93,056 $69,641 Changes in working capital accounts 25,400 13,770 (17,732) (12,270) (30,002) 34,252 Settlement of asset retirement obligations (905) (2,627) (94) (3,241) (3,335) (1,149) Net cash flow provided by operating activities $117,890 $88,591 $20,615 $39,104 $59,719 $102,744 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. 29
Appendix 4 -Fleetwood –Widgeon Sensitivity to Well Cost 30 Widgeon IRR - Sensitivity to Well Cost 0% 10% 20% 30% 40% 50% 60% 70% 80% $5.5 $6.0 $6.5 IR R Capital, MM$ 400 MBO 300 MBO 200 MBO
Appendix 5 - Woodford Dry Gas – Hoss Field Joint Venture 31 Price JV Terms Gas* IRR $ 3.75 55% $ 4.00 65% $ 4.25 70% *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 (%) 60% Payback (Yrs) 1.4 • 38 dry gas wells included in new joint venture • JV provides extremely beneficial cost sharing provisions for PQ • Drilling expected to commence in late 2014 / early 2015 Sensitivity to Gas Prices 20% 40% 60% 80% 100% 120% $3.75 $4.00 $4.25 IRR: 70% Payback: IRR: 65% Payback: 1.4 years IRR: 55% Payback: 1.5 years Economic Assumptions Hoss Joint Venture Agreement (1) Assumptions based on average historical results to date and management estimates (2) Return and payback assumptions based on $4.00 gas
Company Information 32 400 East Kaliste Saloom Road, Suite 6000 Lafayette, Louisiana 70508 Phone: (337) 232-7028 Fax: (337) 232-0044 www.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 our acquisitions with our operations and realize the anticipated benefits from the acquisitions, any unexpected costs or delays in connection with the acquisitions, our ability to find oil and natural gas reserves that are economically recoverable, our ability to realize the anticipated benefits from the Fleetwood joint venture, 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