Form 8-K PETROQUEST ENERGY INC For: Jan 12
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E-mailUNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
___________________________________________________________
FORM 8-K
___________________________________________________________
Current Report
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED):
January 12, 2016
__________________________________________________________
PETROQUEST ENERGY, INC.
(Exact name of registrant as specified in its charter)
DELAWARE (State of Incorporation) | 72-1440714 (I.R.S. Employer Identification No.) |
400 E. Kaliste Saloom Rd., Suite 6000 Lafayette, Louisiana (Address of principal executive offices) | 70508 (Zip code) |
Commission File Number: 001-32681
Registrant’s telephone number, including area code: (337) 232-7028
___________________________________________________________
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)
Item 7.01. Regulation FD Disclosure
PetroQuest Energy, Inc. (the “Company”) is filing herewith a copy of a presentation that will be used during January as Exhibit 99.1.
In accordance with General Instruction B.2 of Form 8-K, the foregoing information, including Exhibit 99.1, shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section, nor shall such information and Exhibit be deemed incorporated by reference in any filing under the Securities Act of 1933 or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.
Item 9.01 Financial Statements and Exhibits
(d) Exhibits
Exhibit Number | Description of Exhibit |
99.1 | January 2016 Presentation |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Date: January 12, 2016
PETROQUEST ENERGY, INC.
/s/ J. Bond Clement
J. Bond Clement
Executive Vice President, Chief Financial Officer and Treasurer
January 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 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 2
Our Properties 3 Gulf Coast Mid-Con Woodford Shale East Texas Cotton Valley • ~52,000 gross acres (~28,000 net acres) • 3Q15 production: 29 Mmcfe/d • 2014 wells(1) avg. IP 11.9 Mmcfe/d • 2015 wells avg. IP 14.2 Mmcfe/d • 2 well program for 2016 • 3Q15 production: 44 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 2014 PF Reserves (1) 170 Bcfe East Texas Gulf Coast Mid-Con 3Q15 Production 81 Mmcfe/d • Sold majority of assets in June 2015 • $280 MM of gross proceeds • Retained East Hoss JV – 38 well program (1) Excludes PQ #11 well which experienced mechanical issues during completion. 3Q15 Production Mix 73% Gas 17% NGL 10% Oil
Arkoma Divestiture Recap 4 Sold majority of Woodford and Mississippian Lime Assets in June 2015 Gross proceeds of $280 million represents over 9X cash flow Significantly enhances liquidity and financial flexibility Repaid all borrowings under credit facility $55 MM undrawn credit facility $159 MM (1) in cash available to fund future Cotton Valley drilling and/or additional deleveraging 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 of net risked inventory in Cotton Valley (1) Cash balance as of 9/30/15
Industry Activity - Cotton Valley Trend 5 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)
6 One Year (6 well) CV Drilling: A Proxy for 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. 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 Horizontal – Production Up with Costs Down 7 Improving Well Performance (1) Excludes PQ #11 well which experienced mechanical issues during completion. 2014 -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 Wells: 3 5 1 6 3 PQ#10 PQ#11 PQ#12 PQ#13 PQ#14 PQ#15 PQ#16 PQ#17 PQ#18 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 12.2 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 12.3 101% 60 Day Avg. Rate (Mmcfe/d) 9.1 5.8 8.8 13.4 13.7 13.5 13.9 13.2 11.3 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 10.6 87% 24 H R IP R at e ( M M C FE /D )
1st Year Cotton Valley Profile (1) 8 Drill & Complete Cost Total 1st Year Production Field Level Cash Flow (2) % of Payout 1st year Payout Period $5,000 M 2.3 Bcfe (6.3 MMcfe/d) $3,624 M 72% 30 mth (1) 2014 Avg. well performance; excluding PQ #11 (2) Price assumptions: $2.50/Mcf, $15Bbl of NGL and $40/Bbl of Oil - 2,000 4,000 6,000 8,000 10,000 12,000 1 2 3 4 5 6 7 8 9 10 11 12 M M cf e/ d Month
Cotton Valley Horizontal Economics 9 Assumptions (1) Gross Well Cost ($MM) 5.0 EUR (Bcfe) 8.6 IP Rate (Mmcfe/d) 11.9 % Gas / Liquids 70% / 30% IRR (%) 29% Payback (Yrs) 2.5 (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 $4.5 MM D&C $5.0 MM D&C 18% 35% 56% 13% 29% 47% 0% 10% 20% 30% 40% 50% 60% 70% 80% $2.00 $2.50 $3.00 Horizontal CV Well Economics
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 10 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
11 Cotton Valley Acreage Position 52,000 Gross Acres (100% HBP) ~600 Gross Future Locations (300 Net)
Gulf Coast – Free Cash Flow Generator 12 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 3Q15 Production (Mmcfe/d) 44 % 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 13 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 Recompletion: Low Cost Production Boost 14 • TB currently flowing from the lowest interval at gross rate of ~30 Mmcfe/d comprised of: • ~550 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 15 Current Zone ~30 MMCFE/d from 48 net feet of pay 2016 Recompletion 154 net feet of pay
Summary Arkoma Divestiture - significant liquidity building and deleveraging event Zero drawn on $55 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 Modest Cotton Valley drilling along with Thunder Bayou recompletion provides ability to maintain production with minimal capex Liquidity position (~$159 million cash @ 9/30/15) and control of operations provide flexibility to navigate current environment 16
17 Appendix
Appendix 1 - Hedging Positions 18 Natural Gas Daily Hedged Volumes (Mmbtu) Price Jan16 - Jun16 10,000 $3.22
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. 19 ($ in thousands) 2010 2011 2012 2013 2014 3Q15 LTM 3Q15 Net Income (Loss) available to common stockholders $41,987 $5,409 ($137,218) $8,943 $26,051 ($51,910) ($233,488) Income tax expense (benefit) 1,630 (1,810) 1,636 320 (2,941) 6 (1,473) Interest expense & preferred dividends 15,091 14,787 14,947 27,025 34,420 9,813 37,350 Depreciation, depletion, and amortization 59,326 58,243 60,689 71,445 87,818 13,687 76,080 Loss on early extinguishment of debt 5,973 - - - - - - Share based compensation expense 7,137 4,833 6,910 4,216 5,248 1,194 5,245 Gain on Asset Sale (828) (22,359) Non-cash gain on legal settlement (4,164) - - - - - - Accretion of asset retirement obligation 1,306 2,049 2,078 1,753 2,958 825 3,242 Derivative (income) expense - - 233 (233) - - - Ceiling test writedown - 18,907 137,100 - - 40,212 214,618 Adjusted EBITDA $128,286 $102,418 $86,375 $113,469 $153,554 $12,999 $79,215
Appendix 3 - Discretionary Cash Flow Reconciliation ($ in thousands) 2011 2012 2013 2014 9M15 Net income (loss) $10,548 ($132,079) $14,082 $31,190 ($231,379) Reconciling items: Income tax expense (benefit) (1,810) 1,636 320 (2,941) 1,079 Depreciation, depletion and amortization 58,243 60,689 71,445 87,818 52,686 Share based compensation expense 4,833 6,910 4,216 5,248 4,022 Gain on Asset Sale - - - - (22,359) Ceiling test write down 18,907 137,100 - - 214,618 Accretion of asset retirement obligation 2,049 2,078 1,753 2,958 2,507 Other 625 1,114 1,240 2,188 1,679 Discretionary cash flow $93,395 $77,448 $93,056 $126,461 $22,853 Changes in working capital accounts 26,686 13,770 (29,867) 55,370 2,952 Payments to settle asset retirement obligations (905) (2,627) (3,335) (3,623) (1,826) Net cash flow provided by operating activities $119,176 $88,591 $59,854 $178,208 $23,979 Note: Management believes that discretionary cash flow is relevant and useful information, which is commonly used by analysts, investors and other interested parties in the oil and gas industry as a financial indicator of an oil and gas company’s ability to generate cash used to internally fund exploration and development activities and to service debt. Discretionary cash flow is not a measure of financial performance prepared in accordance with generally accepted accounting principles (“GAAP”) and should not be considered in isolation or as an alternative to net cash flow provided by operating activities. In addition, since discretionary cash flow is not a term defined by GAAP, it might not be comparable to similarly titled measures used by other companies. 20
Appendix 4 – Gulf Coast/GOM Free Cash Flow Reconciliation ($ 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 21 (1) 2014 Capex excludes non-cash Fleetwood accruals and 2013 Capex excludes GOM acquisition.
Appendix 5 - La Cantera Development 22 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 23 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 24 $ 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 25 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 10 - Woodford Position 26
Appendix 11 - Woodford Dry Gas – East Hoss Joint Venture 27 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 should be complete by YE 2015 • JV provides beneficial cost sharing provisions for PQ 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$
Company Information 28 400 East Kaliste Saloom Road, Suite 6000 Lafayette, Louisiana 70508 Phone: (337) 232-7028 Fax: (337) 232-0044 www.petroquest.com Version 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.
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