The Woodford Shale Presenter Name: Sam Langford
Woodford Agenda Background & History Development Plan Summary Pilots Results Reserves CAPEX Type Well Economics NAV Model Results Looking Forward
Background & History Key Points Statistically Predictable Low Uncertainty of Outcomes 1 horizontal well/every 2 square miles (excluding 100+ verticals) >650 horizontal wells to date Wells drilled from N to S and shallowest to deepest Industry Activity Increasing not Decreasing Drilling & Production rapidly increasing Benchmark Transaction BP/CHK Purchase Price >$20,000/acre or $35,000/flowing Mcfe/d NFX acreage ~ $1,000 total sunk cost ~$800/acre land cost ~$200/acre for seismic + G&G/Frac Mapping/testing Pilot phase ending Development phase Underway Resource play efficiencies evident
Woodford Shale Play Location TEXAS OKLAHOMA ARBUCKLE MOUNTAINS 200 miles WOODFORD / CANEY SHALES ARKOMA 4 active BASIN NFX rigs OUACHITA MOUNTAINS FAYETT E VI LLE (CANEY) SHALE ARKANSAS LLANO UPLIFT BARNETT (CANEY) SHALE FORT WORTH BASIN FRONTAL BELT SABINE UPLIFT HAYNESVILLE SHALE
Woodford Shale History Milestones 225,000 Leasing Phase Assessment and HBP phase Pilot Phase 200,000 Pad Drilling Begins 175,000 Longer Laterals and Increased Frac Density 150,000 MMCF/D 125,000 100,000 75,000 50,000 1st Woodford Vertical Test Multi-Rig Horizontal Drilling Unveiled Woodford Potential 1 st st Horizontal Woodford Well BP buys CHK 25,000 0 Jan-03 Jul-03 Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08
Woodford NFX Gross Op Production Projection through YE 2008 Daily Production (MMCFD) 275 250 225 200 175 150 125 100 75 NFX Op Production (Horizontal) NFX Op Production Est (Horizontal) NFX Op Production (Vertical) NFX Op Production Est (Vertical) Blevins 3H-9: First Horizontal Production 3/3/05 January 1, 2006 January 1, 2009 CAGR 110% 08 Exit Rate > 250 MM/D Current 220 MM/D 50 25 0 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Monthly Average
Woodford History Industry Production August Estimate Average Daily Production (MMCFD) 550 500 450 400 350 300 250 200 150 100 OBO Production NFX Operated Production NFX Op Production (Vertical) Blevins 3H-9: First Horizontal Production 3/3/05 ~ 550 MM/d 50 0 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Monthly Average
Industry Horizontal Well Spuds August 2008 225 200 175 210 NFX W. I. in 58% of All Wells 17 Operators Well Spuds 150 125 100 103 100 663 TOTAL 75 50 25 0 57 48 40 36 26 24 13 6 NFX Antero DVN CLR CHK Pablo XTO SM PQ XEC Other
Industry Horizontal Rigs Operating August 2008 12 12 10 8 Rigs 6 6 5 5 44 TOTAL 10 Active Operators 4 4 4 3 2 2 2 1 0 NFX DVN CLR XTO Antero CHK PQ Pablo SM XEC
Rig Count By Operator 7 6 Highest Rig Count Since Inception 5 4 3 2 1 0 Q1 07 Q2 07 Q3 07 Q4 07 Q1 08 Q2 08 Q3 08 DVN XTO PQ CLR
Woodford Horizontal Spuds by Quarter August 2008 100 90 80 NFX Operates 32% of All Wells 70 Wells Spud 60 50 40 30 20 10 0 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3QE 2004 2005 2006 2007 2008 NFX OBO
NFX Development Plan Summary 40-acre spacing Wells approx. 660 apart 8 wells per section Avg. Lateral Length >4100 ~ 4.0 Bcf per well (average) $5.6 - $6.0MM per well (average) F&D Metric $1.75 - $2.00/mcf NFX Net Estimated Reserves: Booked PDP at YE 07 300 Bcf (excl. 300 Bcf PUD) Estimated Future Reserves 5.6-6.2 Tcf Total NFX Net Reserves 5.9 6.5 Tcf NFX Net Future CAPEX $9.6 - $10.3B
Pilot Results Key Points Spacing Downspacing Recovery Efficiency Costs Pad Drilling Optimal Development 40 acre EUR Reduction Similar to Barnett Approx. 50% R.E. on 40 acre spacing Significant Cost Reductions Optimizes Reserves, NPV & Metrics
Effect of Downspacing 80 to 40 acre 80 ACRES 40 ACRES 660 1,320 660 330 660 25% 5.3 BCF/WELL 4.0 BCF/WELL REDUCTION 21.2 4 WELLS Bcf 5.3 BCF/WELL 30.4 ~35% R.E. 32.0 Bcf 8 WELLS 4.0 BCF/WELL ~50% R.E. 60+ BCF OGIP 60+ BCF OGIP
Shale Characteristics Comparison Silica = Brittleness PARAMETER TARGET RANGE Western Arkoma WOODFORD Fort Worth CANEY/ BARNETT Eastern Arkoma CANEY/ FAYETTEVILLE North Louisiana HAYNESVILLE/ BOSSIER Total Organic Carbon Thermal Maturity Vitrinite % Ro 2 10% 3 10% 3 8% 3 8% 3 5% 1.1 3.0% 1.1 3.0% 1.2 2.0% 1.2 4.0%? Mineralogy/ Silica Content 30 30 80% 60 80% 40 60% 40 60% <40%? Gas Filled Porosity 2 8% 3 6.5% 3 5.5% 3 5.5% 6 10% Depth (feet) NA 6,000 14,000 6,000 9,000 1,500 6,500 10,500 13,500 Thickness (feet) NA 100 220 300 500 50 325 200 240
COMPACT (Hi Net/Gross) INTERVAL HIGH SILICA / LOW CLAY NATURAL FRAC BOUNDARIES FAYETTEVILLE LOG COMPARISONS WOODFORD BARNETT HAYNESVILLE 2300 7000 11300 350 8000 150 350 200
Cattle Pilot Frac Mapping
Pad Wells Dramatic Improvements Drilling Cost / Lateral Foot $2,500 (54%) Hashed well / HBP well (54%) (72%) $2,000 (48%) $1,500 (43%) (27%) (41%) (52%) (46%) $1,000 $500 $- 1 2 3 4 5 6 7 8 9
YTD Increased Density Drilling Pilot Cost $1,600 $1,400 $1,200 59% decrease $1,000 $800 $600 $400 $200 $0 1st well 2nd well 3rd well 4th well 5th well 6th well 2008 Avg. Drill $/lateral foot
Development Plan Methodology Key Points 10% Acreage Assumed Non-commercial for development 150,000 Net Acres Developed 90% of Development Acreage 3-D D Seismic in Hand Reserves - Based on 50 Pilot Wells Costs - Based on 17 Multi-Well Pads Breakeven (10% IRR) Gas Price F&D @ $1.75 = $5.00/Mcf @ $2.00 = $5.50/Mcf
Development Plan - Methodology Lateral Length Scenarios 5280 175 FAULT 5280 5 4620 Lateral Length
Horizontal Well Cost per Lateral Foot Total Drill & Complete $4,000 $3,500 2006 41 wells $2,605 per lateral ft avg 2,521' lateral length avg 2007 91 wells $2,487 per lateral ft avg 2,428' lateral length avg 2008 40 wells $1,546 per lat ft avg 4,224' lat length avg $3,000 10-well Moving Average $2,500 38% Reduction in Cost/Lateral Foot from 2007 $2,000 $1,500 $1,000 $500 ASSESSMENT PILOT $-
Horizontal Well Cost per Lateral Foot Total Drill & Complete Last 20 wells $1,800 20 Most Recent Wells Average $1,370 / lateral ft $1,600 $1,400 Average $1,200 $1,000 $800 $600 $400 $200 $-
Development Plan - Methodology Drilling Performance Improvements 77% improvement 600 Feet/Day 500 400 300 39% improvement 200 100 0 Q1 07 Q2 07 Q3 07 Q4 07 Q1 08 Q2 08 Q3 08 Avg. Vertical Ft./Day Avg. Lateral Ft./Day
Development Plan - Methodology Completion Cost Improvement $900 $800 $700 47% decrease $600 $500 $400 $300 $200 $100 $0 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 Avg. Compl $/Lateral Foot
Horizontal Woodford Type Curve 4 Bcfe Typical Well MCFD 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 Typical Well Economic Assumptions Net Revenue Interest: 81.0% Fixed LOE ($/MCF): $0.45 Production Tax (% of Revenue): - Production Tax (first 48 months or PO) 1.09% - Production Tax (thereafter): 7.09% Wellhead Pricing vs. Henry Hub ($/MCF): -$0.75 Gas Quality (BTU/CF) 1050 Total Fuel Gas %(Wellhead to Perryville): 8.0% 500-0 62% 28% 18% 13% 11% 7% 1 2 3 4 5 6 7 8 9 10 End of Year
Type Well Economics Flat HH Gas Prices Henry Hub Price $/MMBTU (Flat) F&D = $1.75 $5 $7 $9 NPV @ 10% ($M) 150 3550 6700 ROR (%) 11 30 50 PAYOUT (Months) 80 32 20 F&D = $2.00 NPV @ 10% ($M) (500) 2850 5850 ROR (%) 9 23 39 PAYOUT (Months) 95 37 23
NAV Model Results Key Points Model assumes 4 Bcf EUR & $5.8 MM type well 2250 Operated wells drilled beginning MY 2008 Projected results smoother than actual Rig Fleet Increasing from 12 to 30 over 4 years Production Growth NFX Gross Operated Production Projected to reach 1.5 Bcf/d 10 Year CAGR 20% Gathering infrastructure in place, expanding No production delays or curtailments Firm Transportation Secured Differentials to HH Fixed
NAV Model Results NFX W.I. D&C Capex Projection 1,000 Rig Fleet Assumption 35 900 12 Rigs Currently Increasing to 30 MY 2012 30 30 800 27 700 25 $ Millions 600 500 400 13 17 22 20 15 Year-end Rig Count 300 10 200 5 100 0 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 6 months Operated Drilling Capital Non-operated Drilling Capital Operated Year-end Rig Count 0
NAV Model Results Gross Operated Production Projection - 10-Year Horizon 1,400 1,200 1,000 CAGR 20% 800 MMCFD 600 400 200 0 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 YEARS
Woodford Shale Production Area Midcontinent Express and Gulf Crossing Pipelines Arkoma Connector Pipeline Perryville Hub NFX FIRM TRANSPORTATION Mid-Cont Express (MEP): 300 MMcf/d Boardwalk: Up to 300 MMcf/d LaClede: 50 MMcf/d Henry Hub
NFX GROSS OPERATED PRODUCTION Firm Transportation Capacity 900 800 700 650 MMCFD 600 550 MMCFD MMCFD 500 400 465 MMCFD Boardwalk Expansion 300 200 NFX Gross Op. Prod MEP 100 0 LaClede Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12
NAV Model Results NFX NPV @ 10% $8,000 $7,889 $7,000 $6,333 $6,000 $5,000 $4,777 $ Millions $4,000 $3,220 $60/sh $3,000 $48/sh $2,000 $24/sh $36/sh $1,000 $- $7.00 $8.00 $9.00 $10.00 Flat Gas Price ($/MMBtu) 132 mm shares Existing New OBO
Future Well Designs Goal: Lower Cost per Foot STANDARD EXTENDED LATERAL DUAL LATERAL STACKED LATERAL SUPER EXTENDED LATERAL 1 MILE 1 MILE 1 MILE 1 MILE 1 MILE 1 MILE 1 MILE WOODFORD WOODFORD CANEY WOODFORD 2 MILES In Progress 4 th Qtr 08 WOODFORD
NFX Development Plan Summary 40-acre spacing Wells approx. 660 apart 8 wells per section Ave Lateral Length >4100 ~ 4.0 Bcf per well (average) $5.6 - $6.0MM per well (average) F&D Metric $1.75 - $2.00/mcf NFX Net Estimated Reserves: Booked PDP at YE 07 300 Bcf (excl. 300 Bcf PUD) Estimated Future Reserves 5.6-6.2 Tcf Total NFX Net Reserves 5.9 6.5 Tcf NFX Net Future CAPEX $9.6 - $10.3B
Presenter Name: Sam Langford