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| 8-K - 8-K - PETROQUEST ENERGY INC | april2016presentation8k.htm |
April 2016
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 our ability to pay dividends on our Series B Preferred stock, our ability to satisfy continued listing standards of the New York Stock Exchange with respect to our common stock or to cure any continued listing standard deficiency with respect thereto, the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014, our ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing market, our ability to post collateral to satisfy our offshore decommission obligations, our ability to reduce leverage or refinance our senior notes due 2017, 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 3
Our Properties 3 Gulf Coast Mid-Con Woodford Shale East Texas Cotton Valley • ~52,000 gross acres (~28,000 net acres) • 4Q15 production: 24 Mmcfe/d • 2014 wells(1) avg. IP 11.9 Mmcfe/d • 2015 wells avg. IP 14.2 Mmcfe/d • 2016 wells avg. IP 13.7 Mmcfe/d • 4Q15 production: 37 Mmcfe/d • Thunder Bayou discovery producing at ~30 Mmcfe/d • Thunder Bayou recompletion expected during 1H16 is expected to significantly increase production rate Denotes PetroQuest offices East Texas Gulf Coast Mid- Con 2015 Reserves 178 Bcfe East Texas Gulf Coast Mid-Con 4Q15 Production 73 Mmcfe/d • Sold majority of assets in June 2015 • $280 MM of gross proceeds • Completed East Hoss JV – 38 well program • 4Q15 production: 12 Mmcfe/d (1) Excludes PQ #11 well which experienced mechanical issues during completion. 4Q15 Production Mix 75% Gas 15% NGL 10% Oil Recently raised 1Q16 production guidance to 81-82 Mmcfe/d
Balance Sheet Strengthening Actions 4 Sold Oklahoma Assets in June 2015 for $280 million (9x cash flow) Repaid all bank borrowings with a portion of asset sale proceeds Completed Exchange Offer for Unsecured Senior Notes due 2017 ~$214MM of $350MM – 10% 2017 Notes exchanged for ~$145MM of new 2L – 10% 2021 Notes, ~$53.6MM in cash and ~4.3MM shares Exchange eliminates ~$70MM in debt generating $7MM in annual interest savings and extends maturity or eliminates 61% of 2017 maturity Through bank debt repayment and exchange, PQ has retired or extended maturity on ~70% of its 12/31/14 debt
Change to Leverage Profile Since 12/31/14 ($000) A. Total debt down 34% ($144 million) B. 68% of total debt at 12/31/14 repaid or maturity extended C. Provides ~$9MM in annual fixed charge savings ($0.30/Mcfe margin enhancement) (1) 12/31/2014 3/31/2016 5 (1) Based on annualized midpoint of 1Q16 guidance
Change to Maturity Profile ($000s) 75 350 0 50 100 150 200 250 300 350 Bank Debt Notes 3/31/16 2016 2017 6 - 136 145 0 50 100 150 200 250 300 350 2016 2017 2021 12/31/14
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 PQ #19: 12.5 Mmcfe/d PQ #20: 14.8 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 Costs Down 8 Improving Well Performance (1) Excludes PQ #11 well which experienced mechanical issues during completion. Recent Horizontal Cotton Valley Results $6.9 $5.6 $5.2 $3.9 4,232 4,106 4,147 4,535 3,000 3,500 4,000 4,500 5,000 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 2013 2014 (1) 2015 PQ #20 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 2016 Gas Liquids 6.3 7.4 9.1 11.9 14.2 Wells: 3 5 1 6 3 2 13.7 PQ#10 PQ#11 PQ#12 PQ#13 PQ#14 PQ#15 PQ#16 PQ#17 PQ#18 PQ #19 PQ #20 Avg. % of IP IP Rate (Mmcfe/d) 10.7 7.9 11.7 12.3 13.5 11.4 16.7 14.2 11.7 12.5 14.8 12.5 N/A 30 Day Avg. Rate (Mmcfe/d) 9.9 6.7 10.2 13.8 14.5 13.6 16.4 14.1 11.9 11.4 11.5 12.2 98% 60 Day Avg. Rate (Mmcfe/d) 9.1 5.8 8.8 13.4 13.7 13.5 13.9 13.2 11.3 N/A N/A 11.4 93% 90 Day Avg. Rate (Mmcfe/d) 9.0 5.2 7.7 13.6 11.7 13.0 12.3 12.2 10.9 N/A N/A 10.6 87% 24 H R IP R at e ( M M C FE /D )
1st Year Cotton Valley Profile (1) 9 Drill & Complete Cost Total 1st Year Production Field Level Cash Flow (2) % of Payout 1st year Payout Period $4,000 M 2.3 Bcfe (6.3 MMcfe/d) $3,624 M 91% 22 mth (1) 2014 Avg. well performance; excluding PQ #11 (2) Price assumptions: $2.50/Mcf, $15Bbl of NGL and $40/Bbl of Oil - 2,000 4,000 6,000 8,000 10,000 12,000 1 2 3 4 5 6 7 8 9 10 11 12 M M cf e/ d Month
Cotton Valley Horizontal Economics 10 Assumptions (1) Gross Well Cost ($MM) 4.0 EUR (Bcfe) 8.6 IP Rate (Mmcfe/d) 11.9 % Gas / Liquids 70% / 30% IRR (%) 42% Payback (mth) 22 (1) 2014 Avg. well performance; excluding PQ#11; $2.50 gas , $15 NGL and $40 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 $4.0 MM D&C 22% 42% 67% 0% 10% 20% 30% 40% 50% 60% 70% 80% $2.00 $2.50 $3.00 Horizontal CV Well Economics 31% @ strip pricing
11 Last 9 Cotton Valley Wells: Maximum Growth with Minimal Wells 5.7 11.1 4 5 6 7 8 9 10 11 12 BCF E 95% Growth in Production 12/31/13 12/31/15 • Growth metrics above achieved with only 9 gross wells. 47.6 114 20 30 40 50 60 70 80 90 100 110 120 BCF E 140% Growth in Reserves 12/31/15 PROVED RESERVES PRODUCTION 12/31/13
MCFADDEN-BAGLEY UNI 1 42365359740000 CUMGAS : 153,052 MCF CUMOIL : 835 BBLS CUMWTR : 22,183 BBLS 2/15/2006 8 2 0 0 8 2 5 0 8 3 0 0 8 3 5 0 8 4 0 0 8 4 5 0 8 5 0 0 8 5 5 0 8 6 0 0 8 6 5 0 8 7 0 0 8 7 5 0 8 8 0 0 8 8 5 0 8 9 0 0 8 9 5 0 9 0 0 0 9 0 5 0 9 1 0 0 9 1 5 0 9 2 0 0 9 2 5 0 9 3 0 0 9 3 5 0 9 4 0 0 9 4 5 0 9 5 0 0 9 5 5 0 9 6 0 0 9 6 5 0 9 7 0 0 9 7 5 0 9 8 0 0 9 8 5 0 9 9 0 0 9 9 5 0 1 0 0 0 0 1 0 0 5 0 1 0 1 0 0 1 0 1 5 0 1 0 2 0 0 1 0 2 5 0 1 0 3 0 0 1 0 3 5 0 8250 8250 8300 8300 8350 8350 8400 8400 8450 8450 8500 8500 8550 8550 8600 8600 8650 8650 8700 8700 8750 8750 8800 8800 8850 8850 8900 8900 8950 8950 9000 9000 9050 9050 9100 9100 9150 9150 9200 9200 9250 9250 9300 9300 9350 9350 9400 9400 9450 9450 9500 9500 9550 9550 9600 9600 9650 9650 9700 9700 9750 9750 9800 9800 9850 9850 9900 9900 9950 9950 10000 10000 10050 10050 10100 10100 10150 10150 10200 10200 10250 10250 10300 10300 10350 10350 10400 10400 10450 10450 10500 10500 10550 10550 SE CARTHAGE PETRA 6/17/2013 10:36:53 AM “C&D” Sands Davis Sand E4 Sands Roseberry/Eberry Sand Vaughn Sand PetroQuest -- McFadden Bagley #1 GR Resistivity Den. Porosity Cotton Valley Benches 9,000’ 10,000’ 9,500’ 8,500’ E Sands Multi Bench Cotton Valley Opportunities 12 Taylor/Sexton Bench Gross Drilling Locations* C&D 90 Vaughn 114 Davis 182 E4 65 E 95 Eberry/Roseberry 41 Sexton/Taylor 14 Total Gross Drilling Locations 601 * Locations based on 1500’ spacing within area of estimated economic net feet of pay determined by offsetting vertical well logs Cotton Valley Drilling Locations (1) (1) (1) PQ tested benches horizontally NOTE> All of the above benches are productive on PQ acreage through >140 vertical wells and all benches have been tested horizontally in close proximity to PQ acreage
13 Cotton Valley Acreage Position 52,000 Gross Acres (100% HBP) ~600 Gross Future Locations (300 Net)
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) (12/31/15): $ 59 4Q15 Production (Mmcfe/d) 37 % Gas: 68% % NGL: 11% % Oil: 21% Over $430MM of Free Cash Flow since 2007 0 100 200 300 400 500 600 700 800 900 Gulf Coast Cash Flow Gulf Coast Capex $ M M
Thunder Bayou/La Cantera Summary 15 Thunder Bayou (1 Well) La Cantera (3 Wells) Current Gross Production: ~80 MMCFE/D Cumulative Gross Production: ~122 BCFE Remaining Gross 3P Reserves: ~208 BCFE
Thunder Bayou/La Cantera 3P Value Remaining Gross 3P Reserves 208 Bcfe 1Q16 Cash Margin/Mcfe (1) $1.80 Remaining Gross 3P Value(undiscounted) $374 MM PQ Weighted Avg. NRI 31% Net Value to PQ $116 MM Shares O/S 70,537,000 Value per Share $1.64 16 (1) Revenues (oil, gas and ngl) less lifting costs (LOE and sev taxes)
Thunder Bayou Recompletion: Low Cost Production Boost 17 • TB currently flowing from the lowest interval at gross rate of ~30 Mmcfe/d comprised of: • ~600 BBls/d of oil • ~900 BBls/d of NGLs • ~21,000 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
Thunder Bayou 2016 Recompletion 18 Current Zone ~30 MMCFE/d from 48 net feet of pay 2016 Recompletion 154 net feet of pay
Summary Significantly improved balance sheet with Arkoma divestiture/ debt exchange Extinguished or extended maturity on 70% of debt since 12/31/14 Zero drawn on $42 million borrowing base (subject to covenant compliance) with large cash balance post-exchange Modest Cotton Valley drilling along with Thunder Bayou recompletion provides relatively stable production profile in 2016 with minimal capex 2016 capex guidance of $20-$25MM – down ~70% from 2015 2016 focus on preserving liquidity and strengthening balance sheet Suspending preferred dividend provides $0.17/Mcfe of margin enhancement (1) Corporate goal of 25% reduction in cash costs from 2015 Evaluating additional asset sales and JV arrangements Considering options for further deleveraging and maturity extension on remaining 2017 Notes 19 (1) Based on annualized midpoint of 1Q16 guidance
20 Appendix
Appendix 1 - Hedging Positions 21 Natural Gas Daily Hedged Volumes (Mmbtu) Price Jan16 - Jun16 10,000 $3.22 July16 – Dec16 5,000 $2.50
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, gain on asset sale, 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 2015 Net Income (Loss) available to common stockholders $41,987 $5,409 ($137,218) $8,943 $26,051 ($299,977) Income tax expense (benefit) 1,630 (1,810) 1,636 320 (2,941) 2,673 Interest expense & preferred dividends 15,091 14,787 14,947 27,025 34,420 38,905 Depreciation, depletion, and amortization 59,326 58,243 60,689 71,445 87,818 63,497 Loss on early extinguishment of debt 5,973 - - - - - Share based compensation expense 7,137 4,833 6,910 4,216 5,248 4,617 Gain on Asset Sale (21,937) Non-cash gain on legal settlement (4,164) - - - - - Accretion of asset retirement obligation 1,306 2,049 2,078 1,753 2,958 3,259 Derivative (income) expense - - 233 (233) - - Ceiling test writedown - 18,907 137,100 - - 266,562 Adjusted EBITDA $128,286 $102,418 $86,375 $113,469 $153,554 $57,599
Appendix 3 - Discretionary Cash Flow Reconciliation ($ in thousands) 2011 2012 2013 2014 2015 Net income (loss) $10,548 ($132,079) $14,082 $31,190 ($294,838) Reconciling items: Income tax expense (benefit) (1,810) 1,636 320 (2,941) 2,673 Depreciation, depletion and amortization 58,243 60,689 71,445 87,818 63,497 Share based compensation expense 4,833 6,910 4,216 5,248 4,617 Gain on Asset Sale - - - - (21,937) Ceiling test write down 18,907 137,100 - - 266,562 Accretion of asset retirement obligation 2,049 2,078 1,753 2,958 3,259 Other 625 1,114 1,240 2,188 2,259 Discretionary cash flow $93,395 $77,448 $93,056 $126,461 $26,092 Changes in working capital accounts 26,686 13,770 (29,867) 55,370 6,789 Payments to settle asset retirement obligations (905) (2,627) (3,335) (3,623) (2,776) Net cash flow provided by operating activities $119,176 $88,591 $59,854 $178,208 $30,105 Note: Management believes that discretionary cash flow is relevant and useful information, which is commonly used by analysts, investors and other interested parties in the oil and gas industry as a financial indicator of an oil and gas company’s ability to generate cash used to internally fund exploration and development activities and to service debt. Discretionary cash flow is not a measure of financial performance prepared in accordance with generally accepted accounting principles (“GAAP”) and should not be considered in isolation or as an alternative to net cash flow provided by operating activities. In addition, since discretionary cash flow is not a term defined by GAAP, it might not be comparable to similarly titled measures used by other companies. 23
Appendix 4 – Gulf Coast/GOM Free Cash Flow Reconciliation ($ in thousands) 2007-2015 Revenues $1,005,705 Lease Operating Expense (184,505) Severance Tax (25,480) Field level cash flow $795,720 Capital Expenditures (1) (361,794) Free Cash Flow $433,926 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 - Cotton Valley Horizontal – Horizontal Uplift 27 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
Appendix 8 - Woodford Position 28
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 3 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 our ability to pay dividends on our Series B Preferred stock, our ability to satisfy continued listing standards of the New York Stock Exchange with respect to our common stock or to cure any continued listing standard deficiency with respect thereto, the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014, our ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing market, our ability to post collateral to satisfy our offshore decommission obligations, our ability to reduce leverage or refinance our senior notes due 2017, 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.