Exco Resources Inc · OTC:EXCE
Exco Resources — Investor Day (September 2009)
143 slides from Exco Resources's investor day presentation, Sep 23, 2009
Slide 1: Analyst Meeting
Analyst Meeting September 23, 2009 Exhibit 99.1
Slide 2: Forward Looking Statements
Forward Looking Statements This presentation contains forward-looking statements, as defined in Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. These forward-looking statements relate to, among other things, the following: our future fin
Slide 3: Forward Looking Statements (continued)
Forward Looking Statements (continued) We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reli
Slide 4: Agenda
Introduction Doug Miller Recent Events Steve Smith Asset Overview Hal Hickey East Texas / North Louisiana Mike Chambers Harold Jameson Midstream and Marketing Hal Hickey John Jacobi Steve Estes Appalachia Wendy Straatmann John Johnston Midcontinent and Permian Hal Hickey Reserves Marcia Simpson Fina
Slide 5: Welcome and Introduction
Welcome and Introduction Welcome – Analysts and investors – EXCO management – BG Group management Meeting Objectives – Provide clarity of current asset mix – Update operational results – Highlight exceptional technical teams – Explain growth strategy for the future – Present development plans – Disc
Slide 6: The New EXCO: Focus and Strategy
The New EXCO: Focus and Strategy Analyst Meeting September 23, 2009
Slide 7: Company Overview
Company Overview (1) Significant shale upside with a solid base of conventional assets 1.5 Tcfe of Proved Reserves – 279 Mmcfe/d of current net production, reserve life of 14.7 years and over 70% Proved Developed – 120 Bcfe of shale assets booked as proved with potential for significant reserve adds
Slide 8: EXCO Today: Positioned for Growth
EXCO Today: Positioned for Growth Strategic deals in 2009 have positioned EXCO for unmatched opportunities Announced $1.3 billion joint venture with BG Group Successfully executed our 2009 divestment program Unmatched Opportunities Prepared to deliver 30 – 40% growth for the next five years while ge
Slide 9: Achieving our Goal
Achieving our Goal Maximum equity value growth Right Assets Right People Right Strategy Equity Value Growth We have a significant position in two of the most prolific resource plays in North America along with a focused core of non-shale assets We have a dedicated, industry leading technical staff a
Slide 10: Shifting Our Strategy
Shifting Our Strategy Change in asset base dictated a change in strategy Acquisition driven historically – Sought long-life assets with low risk drilling, strong basis, and proximity to markets – Focused on areas with follow-up acquisition opportunities – Entered East Texas / North Louisiana in 1998
Slide 11: Keys to EXCO's Strategy
Keys to EXCO’s Strategy Capital discipline – Continue to spend within cash flow – Maintain liquidity Held-by-production acreage – Enables the most efficient execution of field development Appropriate development pace – Focus on efficiency and effectiveness to achieve maximum returns Focus on midstre
Slide 12: Supply Trends
Supply Trends Production and rig counts highly correlated US rig count fell from a high of 1,606 to a low of 692 Shift to unconventional plays has driven the recent growth Late 1990’s focus on tight gas plays Early 2000’s focus on shale gas plays High decline rates from tight gas (sand or shale) hav
Slide 13: LNG Tsunami
LNG Tsunami Or lack thereof… Many industry analysts and market participants predicted large influx of LNG for – Never materialized due to: Stronger Asian demand recovery Strong recoveries in Korea and Taiwan; Japan beginning to recover Continued strength in Chinese and Indian demand Chinese markets
Slide 14: Industry Outlook
Industry Outlook Industry, economic and political conditions support a strong rebound in commodity prices Advent of shale gas in the US provides more certainty of future supply – Provides visibility of supply in the medium term, promoting more consumption Government deficits and related borrowings w
Slide 15: Vernon CNG Facility
Vernon CNG Facility EXCO constructed the first CNG fueling station in Louisiana in the last 10 years Results in lower operating costs Cleaner burning fuel 100% of Vernon fleet will be converted by year-end 2010 Promote positive image in the community Using locally produced fuel to support U.S. energ
Slide 16: Our Focus and Strategy: Summary
Our Focus and Strategy: Summary Strong balance sheet provides financial flexibility Successfully shifted our strategy from acquisition and exploitation to shale development Focused asset base provides tremendous growth opportunities Committed to continued investment in people and technology, allowin
Slide 17: Recent Events
Recent Events Analyst Meeting September 23, 2009
Slide 18: Delivering What We Promise
Delivering What We Promise Executing on our 2009 strategic plans Joint venture partner – Joint venture with BG Group positions EXCO for dramatic upstream and midstream growth – Aligns EXCO with a world leader in developing and marketing natural gas Asset sales – Closed ~$450 million in divestitures
Slide 19: Strategy That Delivers
• • Strategy That Delivers Execution of our strategy provided the assets for tremendous future growth Historical Strategy – Organic production growth rate of 5 – 10% – Acquire and exploit long-life assets – Focus on areas with follow- on acquisition opportunities – Balance capital between developmen
Slide 20: Financial Snapshot
Financial Snapshot Significant liquidity with tremendous organic growth (1) As of September 2009 (2) EBITDA and Capital Expenditures for EXCO include 50% of the EBITDA and Capital Expenditures from TGGT. (3) Pro forma for expected shallow Appalachian divestiture (dollars in millions) Current (1) Pro
Slide 21: Joint Venture With BG Group
Joint Venture With BG Group Strategic partner with shared vision Sold 50% interest in Area of Mutual Interest (AMI) – 580 Bcfe of proved reserves and 155 Mmcfe/d within AMI Cash flow implications – Haynesville development will be accelerated, but capital expenditures will be reduced – In addition to
Slide 22: Slide 22
Slide 23: The Right People
The Right People Key driver of our future growth Outstanding growth in technical and support staff – Focus on people has resulted in a tremendous technical staff buildup in the last two years – Technical headcount has increased 70% since January 2008 Relentless focus on Environmental, Health and Saf
Slide 24: The New EXCO: Asset Overview
The New EXCO: Asset Overview Analyst Meeting September 23, 2009
Slide 25: Proved Reserves
Proved Reserves (3) = 1.5 Tcfe 3P Reserves = 3.3 Tcfe 3P+ Reserves = 12.1 – 17.7 Tcfe Current Production = 279 Mmcfe/d Gross acreage: 1,376,000 Net acreage: 1,095,000 Mid-Continent (1) Internal reserve report updated for activity through August with strip pricing, adjusted for differentials and excl
Slide 26: Asset Overview
Asset Overview Strong asset base with outstanding growth potential Haynesville and Marcellus shales – Primary driver of our growth and future potential – Focus of our capital and technical resources Non-shale assets with significant price-contingent upside – Vernon field is a Lower Cotton Valley pla
Slide 27: Asset Overview
Asset Overview HBP position and lower costs are keys Significant HBP position in the Haynesville and Marcellus shales – Haynesville: 44,000 net acres with 71% HBP in the core; evaluating acquisitions of 5,000 additional net acres – Marcellus: 348,000 net acres; 226,000 net fairway acres, with 70% he
Slide 28: Development Strategy
Development Strategy Initial focus on Haynesville; moving towards Marcellus Haynesville development is our primary focus as a result of – Outstanding Haynesville position – Superior returns, even in low commodity price environment – Existing infrastructure and access to multiple markets – Readily av
Slide 29: Development Strategy
Development Strategy Haynesville is our template for Marcellus development Haynesville development – Explore: initiate vertical program to gather science, test zones, design fracs, and develop drilling techniques – Test: apply knowledge from vertical program towards horizontal program – Develop: foc
Slide 30: Capital Focus
Non-shale 31% Haynesville 28% Marcellus 35% Corporate 6% 2010 Capital Focus Preliminary capital plan (dollars in millions) 2010E Haynesville Drilling $ Land Seismic Exploration Other Total Haynesville Marcellus Drilling Land Seismic Midstream Other Total Marcellus Non-shale Drilling Land Seismic Mid
Slide 31: Technology
Technology Investment in technology has been instrumental to our success Commitment to technology – Science and technical initiatives are being fully implemented in both shale plays – Our use of technology and our technical initiatives have resulted in some of the best Haynesville wells in the play
Slide 32: The Right Assets: East Texas / North Louisiana
The Right Assets: East Texas / North Louisiana Analyst Meeting September 23,
Slide 33: East Texas / North Louisiana
East Texas / North Louisiana Introduction Entered the basin in 1998 – Focused on long-life gas Position has grown through key acquisitions – Acquired primarily HBP acreage with Cotton Valley production Discovery of Haynesville play in early 2008 – Resulted in a strategy shift to horizontal developme
Slide 34: East Texas / North Louisiana Division Overview
East Texas / North Louisiana Division Overview Current production (Mmcfe/d): Reserve life (years): 12.6 Gross acreage (thousands): Net acreage (thousands): Producing wells: 1,380 gross / 769 net Reserves Bcfe Gross Net PD PUD Total Proved Probable Possible 1,261 3P 2,387 1,589 Potential 1,403 1,468
Slide 35: Haynesville Shale
Haynesville Shale Asset Overview Producing horizontal wells: 23 gross / 6 net Average WI: ~30% Average NRI: ~23% Reserves Bcfe Gross Net PD PUD Total Proved Probable Possible 1,016 3P 1,207 Potential 1,092 Total 2,299 1,612 Locations Field Highlights
Slide 36: Haynesville Operations Snapshot
th th Haynesville Operations snapshot Production: 238 Mmcf/d gross, 44 Mmcf/d net – Operated: 173 Mmcf/d gross, 40 Mmcf/d net – OBO: 65 Mmcf/d gross, 4 Mmcf/d net – Cumulative gross operated horizontal production: 19.3 Bcfe Drilling: 12 Horizontal Rigs – 12 horizontal rigs; 7 operated & 5 non-operat
Slide 37: Haynesville Development History
Haynesville Development History Measured ramp up to achieve excellence Vertical Program Core Analysis Horizontal Testing Development Drilling Manufacturing – Test and hold acreage – Determine best landing zone – Determine best completion technique – Evaluate rock properties – Determine gas in place
Slide 38: EXCO Operated Haynesville Shale Production
EXCO Operated Haynesville Shale Production Currently 16 operated horizontal wells producing 185 Mmcf/d Gross Production 3/24/08: CHK announces Haynesville as significant play 12/4/08: XCO turns first horizontal well to sales 3/14/08: XCO TD’s first Haynesville vertical well 8/16/08: XCO spuds first
Slide 39: Industry Best IP Rates
Industry Best IP Rates Initial production rates reported on 165 wells across the Haynesville shale play EXCO’s track record – 4 of the top 6 – 11 of the top 25 – 15 of the top 39 Last 2 EXCO wells are the 2 best wells – IP’s of 30.1 and 29.6 Mmcf/d EXCO operated wells Top 25 Haynesville Shale IP’s 1
Slide 40: EXCO Horizontal Well Cumulative Production
EXCO Horizontal Well Cumulative Production 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 Days on Production EXCO Operated Cumulative Haynesville Shale Production DeSoto Parish - Consistent performance through first 15 wells Well was choked back while treating facility was installed Recent well may be best in play
Slide 41: EXCO DeSoto Parish Typical Well Gross Revenue
EXCO DeSoto Parish Typical Well Gross Revenue Significant revenue stream from a single well Horizontal Haynesville Cumulative Gross Revenue 20 Mmcf/d IP Type Curve $0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 Month $3.00/ mcf $5.00/ mcf $7.00/ mcf
Slide 42: Continued Improvement in Drilling Days
Continued Improvement in Drilling Days Significant driver for decrease in drilling costs Haynesville Horizontals - Days vs Depth Days from Spud 1st Three Haynesville Wells Mid Three Haynesville Wells Last Three Haynesville Wells
Slide 43: East Texas / North Louisiana Staff
East Texas / North Louisiana Staff Continued build up of technical personnel Outstanding growth in technical staff – ~210 field and office personnel Engineers: 28 Engineering support staff: 9 Geoscientists: 15 Geologic support staff: 6 Landmen: 10 Land support staff: 5 – ~80 full time contract Dalla
Slide 44: Technical Staff
Technical Staff Balance of youth and experience 28 Engineers and 15 Geoscientists 1-4 5-10 11-20 21-30 30+ Years of experience Engineers Geoscientists
Slide 45: Field Offices
Field Offices – Waskom – East Texas – Holly – Northwest Louisiana – 4,886 sq ft additional space under construction at Holly office New Field Office Facilities Constructing new offices to support our growing business Waskom Office Holly Office
Slide 46: EXCO Operational Success
EXCO Operational Success Outstanding well results are attributable to operational and technical performance Drilling to TD 100% Casing to TD 100% Successful cement job 100% Frac stages as designed 98% Perforate and isolate 100% Coil tubing drill out 100% Flow to sales on first day 100%
Slide 47: Drilling Rigs
Drilling Rigs One of the most modern, fit for purpose rig fleets in the play All 10 rigs we currently have under contract are less than 3 years old and are “Rapid Move Modular” rigs – Climate controlled Driller cabins – Automated catwalks – Modular style allows rigs to self erect (minimizing the nee
Slide 48: Haynesville Drilling and Completion Demo
Haynesville Drilling and Completion Demo
Slide 49: Haynesville Drilling & Completion Costs
Haynesville Drilling & Completion Costs $0 $2 $4 $6 $8 $10 $12 $14 Q1 2009 Q2 2009 Q3 2009 Future Drilling Costs Completion Costs Drilling and Completion Costs Realizing significant improvements in well costs with more to come Cost reductions primarily due to decreased drilling days, improved drilli
Slide 50: Haynesville Cost Breakdown
Rig and Mobilization 13% Tubing and Surface Equipment 2% Perforating, Flowback, Water, etc. 15% Stimulation 33% Location 5% Casing 13% Cementing, Directional, Fuel, etc. 19% Haynesville Cost Breakdown Our recent wells have cost ~$9 million Casing 23% Mud 15% Directional 39% Stimulation 55% Proppant
Slide 51: Rigs Under Contract
Rigs Under Contract Q3 2009 Q4 2009 Q1 2010 Short term Long term Long Term Contracts $23,500/day - $24,500/day Short Term Contracts $13,000/day - $15,000/day All rigs contracted through year end 2009 are “Rapid Move Modular” rigs (Modular, self-erecting, top drive, improved mud system, with pick-up
Slide 52: Continued Improvement in Completion Process
Continued Improvement in Completion Process No completions have been deferred due to pipeline delays Rig release to first sales 1st qtr 2nd qtr 3rd qtr 18% reduction in days First well – 35 days Last well – 17 days
Slide 53: Development Support
Development Support Water disposal in DeSoto Parish Constructing water gathering system for Cotton Valley and Haynesville – Connecting existing 300+ wells to a common gathering system – 11 common point facilities will transfer water via a 30+ mile line to established disposal field – In service 12/1
Slide 54: Leader in developing alternatives to local surface water
Leader in developing alternatives to local surface water – Cotton Valley produced water – Industrial plant waste water – Evaluating potential recycling initiatives Secured long term contract with service provider at market rates to – Build locations – Lay gathering (water & gas) – Supply parts and o
Slide 55: Haynesville Horizontal Production Curves
Haynesville Horizontal Production Curves Consistent results outperforming original estimate and peers
Slide 56: Rate of Return – Mmcf/d IP Well
Rate of Return – 20 Mmcf/d IP Well Outstanding returns, even in low price environment Horizontal Haynesville CapEx & Price Sensitivity 2.00 2.50 3.00 3.50 4.00 4.50 5.00 5.50 6.00 6.50 7.00 7.50 8.00 Gas Price ($/MCF) 7.5 MM$ CAPEX, 20 Mmcfe/d IP 8.5 MM$ CAPEX, 20 Mmcfe/d IP 9.5 MM$ CAPEX, 20 Mmcfe/
Slide 57: Rate of Return – Mmcf/d IP Well
Rate of Return – 15 Mmcf/d IP Well Outstanding returns, even in low price environment Horizontal Haynesville CapEx & Price Sensitivity 2.00 2.50 3.00 3.50 4.00 4.50 5.00 5.50 6.00 6.50 7.00 7.50 8.00 Gas Price ($/MCF) $7.5 MM CAPEX, 15 Mmcf/d IP $8.5 MM CAPEX, 15 Mmcf/d IP $9.5 MM CAPEX, 15 Mmcf/d I
Slide 58: Technology
Technology Embraced broad set of technologies to achieve our results Reservoir – Object Reservoir Shale Study – Reserves determination and quantification in gas shale – Joint industry Core Consortiums Geological & Geophysical – Whole core rock properties analysis – Petrophysical analysis and rock pr
Slide 59: Moving Forward
Moving Forward Haynesville Current rig contracts – 5 rigs on long term – 5 rigs dedicated on short term with extensions at market rate – Plan to add 4 additional rigs by 1/1/10 Frac water – Multiple sources identified – Successfully tested Cotton Valley and industrial waste water Services – Started
Slide 60: Haynesville Horizontal Rig Program
Haynesville Horizontal Rig Program (1) Average rigs by quarter – EXCO Operated Horizontal Rig Count 7 rigs running today Add 4 more by Nov 2009 Add 3 more in Jan 2010 Horizontal Well Count 2009 - 2010 - 2011 - Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 (1) Includes one rig drilling only Bossier test wells
Slide 61: East Texas / North Louisiana Upside
Bossier – Vertical program underway testing in six counties / parishes – Taking core in two wells – Testing frac and proppant designs – Identifying landing zone – Planning to spud 1st horizontal in 4Q 2009 Cotton Valley horizontal – Identifying landing zone in three fields – Planning to spud 1st hor
Slide 62: Bossier: The next frontier
Bossier The next frontier Top Bossier Top Haynesville Top Limestone +/- 10,000’ +/- 11,500’ +/- 11,900’ Potential gas in place on our acreage is ~17 Tcf Recovery factor to be determined
Slide 63: Cotton Valley Development
Cotton Valley Development Joint venture area Producing wells: 965 gross / 391 net Reserves Bcfe Gross Net PD PUD Total Proved Probable Possible 3P Potential Total 1,158 Locations Field Highlights
Slide 64: Cotton Valley Drilling Economics
Cotton Valley Drilling Economics (1) Vertical wells Average WI 30% Average NRI 23% Mcfe/d IP 1,575 Mcfe/d 1st Month 1,400 % gas / % oil IRR @ Base Case (strip) 20% Typical Well Gross Net Cost - Thousands $2,116 $635 Reserves- Mmcfe 1,445 (1) Includes Cotton Valley, Hosston/Travis Peak combined Year
Slide 65: Pricing Scenarios
Pricing Scenarios A. $4/MCF and $50/Bbl Flat B. Base Case (strip pricing) 2010 - $5.50/MCF and $70/Bbl 2011 - $6.50/MCF and $80/Bbl 2012+ - $7.00/MCF and $80/Bbl C. $8/MCF and $100/Bbl Flat (1) Includes Cotton Valley, Hosston/Travis Peak combined Cotton Valley Drilling Economics (1) Vertical wells
Slide 66: Vernon Field Overview
Vernon Field overview Producing wells: 392 gross / 355 net Reserves Bcfe Gross Net PD PUD Total Proved Probable Possible 3P Potential Total Locations Field Highlights PDP Prob Poss
Slide 67: Vernon Cotton Valley Drilling Economics
Vernon Cotton Valley Drilling Economics Vertical wells Average WI 91% Average NRI 72% Mcfe/d IP 6,500 Mcfe/d 1st Month 3,500 % gas / % oil IRR @ Base Case 23% Year 1 Year 2 Year 3 Year 4 Year 5 5 Yr Cum Terminal Decline Annual Gross Production - Mmcfe 8% Daily Gross Production - Mcfe/d 1,411 % EUR 1
Slide 68: Typical Vernon Area Cotton Valley Economic Analysis
Typical Vernon Area Cotton Valley Economic Analysis 4 / 50 Flat Base Case 8 / 100 Flat $3.3 MM Gross CAPEX $4.1 MM Gross CAPEX $4.9 MM Gross CAPEX Vernon Cotton Valley Rate of Return Pricing Scenarios A. $4/MCF and $50/Bbl Flat B. Base Case (strip price) 2010 - $5.50/MCF and $70/Bbl 2011 - $6.50/MCF
Slide 69: Moving Forward: Cotton Valley and other shallow assets
Moving Forward Cotton Valley and other shallow assets Prepared to exploit Cotton Valley and other shallow assets when commodity prices increase – Develop low risk upside (PUDs, Probables, and Possibles) – Extend the limits of our fields – Implement appropriate infill drilling opportunities – Recompl
Slide 70: The Right Assets: Midstream and Marketing
The Right Assets: Midstream and Marketing Analyst Meeting September 23,
Slide 71: Midstream
Midstream East Texas/North Louisiana – Positioned for Growth
Slide 72: JV Midstream Transaction
JV Midstream Transaction Details Midstream Structure – East Texas/North Louisiana Midstream assets contributed to the newly formed TGGT Holdings, LLC (TGGT) – BG Group purchased 50% of TGGT for $269 million – Planning is underway for expansions in 2010-2012 Vernon upstream and midstream assets were
Slide 73: Midstream – TGGT Holdings, LLC (TGGT)
Midstream – TGGT Holdings, LLC (TGGT) East Texas/North Louisiana – Positioned for Growth Current TGGT Assets – Strategically positioned for industry activity – August revenue throughput averaged 508 Mmcf/d; EXCO equity revenue throughput of 254 Mmcf/d Talco System (Gathering) – 625 miles of gatherin
Slide 74: Haynesville Header System
Haynesville Header System 2009 Plans Strategic pipeline installation program will ensure that EXCO’s produced gas is transported to gas markets Installation of 29 mile pipeline system of 36 inch pipe operated by TGG Pipeline will be installed south of Shreveport and traverse the Holly system Estimat
Slide 75: Midstream – TGGT Haynesville Header System
Midstream – TGGT Haynesville Header System Provides efficient well hook-up and market access 36” Stage 1 – 5 miles 95% complete 36” Stage 2 – 7 miles 36” Stage 3 – 8 miles 36” Stage 4 – 8.5 miles LIG & Gulf South & CP Sales Point Regency Sales Point Gathering laterals Centerpoint Sales Tap 2009 – 29
Slide 76: Midstream - Vernon System
Midstream - Vernon System Provides coordination between Vernon upstream and midstream Vernon System (Gathering) – August equity revenue throughput averaged 127 Mmcf/d – 177 miles of intrastate pipeline from 4” to 16” pipe – One treating plant and access to four pipeline markets – 250 Mmcf/d of capac
Slide 77: Midstream Average Daily Volume
Midstream Average Daily Volume 1,000 1,500 2,000 2,500 2009E 2010E 2011E Talco TGG Legacy Haynesville Header Midstream Significant volume growth with additional potential
Slide 78: East Texas / North Louisiana Midstream Summary
East Texas / North Louisiana Midstream Summary Strategic pipeline system TGG and Talco Assets – Strong demand for access due to industry Haynesville activity – Significant opportunities for growth and expansion Plan to spend at least $60 million annually on capital projects and evaluate future expan
Slide 79: Gas Marketing
Gas Marketing Haynesville Marketing Strategy Share Marketing responsibilities for all volumes 50/50 with BG within the JV Currently moving all Haynesville volumes into Gulf South and Crosstex LIG New interconnect with Centerpoint scheduled to be in service November 1, 2009 New interconnect with Rege
Slide 80: Current Firm Transportation Agreements
Current Firm Transportation Agreements (1) Actively pursuing firm transportation – EXCO upstream has secured 475 Mmcf/d on Regency Haynesville Expansion Project – Working on securing an additional 1 Bcf/d of firm transportation Average FT per quarter (Mmcf/d) Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010
Slide 81: Gross Operated JV Throughput Forecast
Gross Operated JV Throughput Forecast Holly Caspiana Field only Holly Caspiana Gross Operated JV Production 1,529 1,639 1,359 1,057 - 1,000 1,200 1,400 1,600 1,800 2,000 Year Non-Shale - Operated Shale - Operated Firm Transport Potential Firm Transport
Slide 82: Haynesville Pipeline Proposed Projects
Haynesville Pipeline Proposed Projects Additional 3 rd Party Firm Transportation Opportunities Strategic planning to secure the takeaway capacity for the substantial growth in EXCO Haynesville gas production In Service Capacity Proposed Pipeline Project Date Bcf/d Term (yrs) Diameter Receipt / Deliv
Slide 83: The Right Assets: Appalachia
The Right Assets: Appalachia Analyst Meeting September 23, 2009
Slide 84: Appalachia
Appalachia Introduction Entered the basin in 2004 – Focused on long-life gas and consolidation opportunities Position has grown through numerous acquisitions – Acquired key assets in Pennsylvania and northern West Virginia with HBP acreage Focus on Marcellus play in late 2007 – Resulted in a strateg
Slide 85: Appalachia Division Overview
Appalachia Division Overview Devonian Sands & Shale OH KY WV VA PA Producing wells: 6,189 gross / 5,620 net Reserves Bcfe Gross Net PD PUD Total Proved Probable Possible 3P 2,125 1,968 Potential 6,992 - 12,620 3,865 - 7,004 3,691-6,754 Total 7,489 - 13,117 5,990 - 5,659 9,129 - 8,722 Locations Portf
Slide 86: Focus on the Marcellus
Focus on the Marcellus Largest areal extent of the major shale plays – EXCO has 348,000 net acres in the play Approximately 226,000 net fairway acres 70% of acreage is HBP Key PA average WI 100%, average NRI 84% Massive reserve potential – ~6 – 11 Tcf potential on EXCO acreage Drilling activity and
Slide 87: Marcellus Development Strategy
Marcellus Development Strategy Measured ramp up to achieve excellence Vertical Program Core Analysis Horizontal Testing Development Drilling Manufacturing – Test and hold acreage – Determine best landing zone – Determine best drilling and completion practices for each area – Evaluate rock properties
Slide 88: 2
2
Slide 89: Marcellus current activity and drilling areas
- Drill verticals to test the play: – Obtain additional reservoir data (core, pressure data, etc.) – Test drilling, completion, and production techniques – Identify horizontal drilling targets Acquire seismic – Identify geologic hazards – Identify favorable, naturally fractured areas to target Solid
Slide 90: Marcellus Test Status
Marcellus Test Status Completed vertical wells are showing promising initial results – Cores indicate favorable TOC (4-10%), thickness (80'-200'), porosity (4-10%), and permeability (up to 0.04 mD) – Production results have been in-line with the best competitor results 200-400 Mcf/d sustained rates
Slide 91: EXCO Horizontal Marcellus 4.0 Bcfe Type Curve
EXCO Horizontal Marcellus 4.0 Bcfe Type Curve Marcellus Shale NE PA Test well – Drilling Economics Average WI 100% Average NRI 82% Mcfe/d IP 4,880 Mcfe/d st Month 3,750 % gas / % oil IRR @ Base Pricing 24% Typical Test Well Gross Net Cost - Thousands $5,000 $5,000 Reserves - Mmcfe 4,000 3,198 Year 1
Slide 92: Rate of Return – Marcellus
Rate of Return – Marcellus Economics improve as we move forward Test Develop Manufacture
Slide 93: Rate of Return – Marcellus
Rate of Return – - Marcellus Test Develop Manufacture
Slide 94: Marcellus Economics
Marcellus Economics Based on competitor results, we could exceed our current forecast 1,000 10,000 Marcellus Operator 1 Marcellus Operator 2 EXCO NE PA Marcellus Operator 1 Marcellus Operator 2 EXCO NE PA Initial Rate(Mmcfe): 8,500 5,000 4,880 Initial Decline (%): EUR (Bcfe): 4.5+ 4.4 3.9
Slide 95: Technical Efforts
Technical Efforts Reservoir – Object Reservoir Collaborative Exploitation Project – Haas Petroleum Engineering Services – rd party engineering and shale modeling – Core Lab Core Consortium Geology & Geophysics – Coring / tight rock analysis – Hunt Wallace Petrophysics for shale quality prediction –
Slide 96: Appalachia Staff and Facilities
Appalachia Staff and Facilities Continued build up of technical personnel Outstanding growth in Marcellus technical staff – Engineers: 13 – Engineering support staff: 6 – Geologist / Geophysicist: 10 – Geology support staff: 5 – Landmen: 8 – Land support staff: 12 Relocation of Marcellus technical s
Slide 97: Technical Staff
Technical Staff Balance of youth and experience 13 Engineers and 10 Geologists 1-4 5-10 11-20 21-30 30+ Years of experience Engineers Geologists
Slide 98: Development Issues
Development Issues Identifying solutions to potential development issues Land – 70% HBP allows us to dictate pace of development – Holding our limited term acreage through timely drilling Size of play – “Plays within the Play” requires regional delineation efforts – Focused on best reservoir / econo
Slide 99: Marcellus Summary
Marcellus Summary Huge potential Strong acreage position, large HBP in blocks along fairway – Fairway acreage: ~ 226,000 net – High NRI Large play with unique challenges – Spans ~400 miles along mountain front Working to solve potential issues – Water regulation – Access to markets Horizontal testin
Slide 100: Additional Upside
Additional Upside Huron horizontal potential in West Virginia – Future drilling at appropriate commodity pricing – 146,000 gross, 129,000 net acres – ~1 Tcf of potential reserves Shallow Devonian sands in Pennsylvania and West Virginia – Future drilling at appropriate commodity pricing – Bradford, V
Slide 101: EXCO Horizontal Lower Huron Bcfe Type Curve
EXCO Horizontal Lower Huron 1 Bcfe Type Curve Additional Upside Huron Shale Drilling Economics Average WI 100% Average NRI 85% Mcfe/d IP Mcfe/d 1st Month % gas / % oil IRR @ Base Case 16% Year 1 Year 2 Year 3 Year 4 Year 5 5yr Cum. Terminal Decline Annual Gross Production - Mmcfe 73.7 49.4 42.1 38.1
Slide 102: Appalachian Division: Huron New Drill Economics
Appalachian Division Huron New Drill Economics Pricing Scenarios A. $4/MCF and $50/Bbl Flat B. Base Case (strip price) 2010 - $5.50/MCF and $70/Bbl 2011 - $6.50/MCF and $80/Bbl 2012+ - $7.00/MCF and $80/Bbl C. $8/MCF and $100/Bbl Flat
Slide 103: EXCO Shallow Pennsylvania Mmcfe Type Curve
EXCO Shallow Pennsylvania 130 Mmcfe Type Curve Additional Upside Shallow Pennsylvania Drilling Economics Average WI 100% Average NRI 87.5% Mcfe/d IP Mcfe/d st Month % gas / % oil IRR @ Base Case 22% Typical Well Gross Net Cost – Thousands $240 $240 Reserves - Mmcfe Year 1 Year 2 Year 3 Year 4 Year 5
Slide 104: Appalachian Division: Shallow Pennsylvania Operating Area
Appalachian Division Shallow Pennsylvania Operating Area Pricing Scenarios A. $4/MCF and $50/Bbl Flat B. Base Case (strip price) 2010 - $5.50/MCF and $70/Bbl 2011 - $6.50/MCF and $80/Bbl 2012+ - $7.00/MCF and $80/Bbl C. $8/MCF and $100/Bbl Flat
Slide 105: Moving Forward: Appalachia
Moving Forward Appalachia Begin horizontal development nd half 2010, continue appropriate vertical program – 1 top hole rig paired with 1 built-for-purpose horizontal rig Pad drilling Spacing – 1 vertical rig for testing and to hold acreage Target areas based on – Best reservoir – Economics – Acreag
Slide 106: The Right Assets: MidContinent and Permian
The Right Assets: MidContinent and Permian Analyst Meeting September 23, 2009
Slide 107: Midcontinent and Permian
Midcontinent and Permian Significant upside outside the shales Solid base of shallow decline, long life assets Tremendous free cash flow generation Price contingent upside Divested non-strategic assets with low potential in these areas Have been focusing on improving base production and lowering ope
Slide 108: Mid-Continent Assets
Mid-Continent Assets Division overview Producing wells: 1,285 gross / 857 net Reserves Bcfe Gross Net PD PUD Total Proved Probable Possible 3P Potential Total 1,044 Locations Portfolio Highlights Current production (Mmcfe/d): Reserve life (years): 15.9 Gross acreage (thousands): Net acreage (thousan
Slide 109: Golden Trend Economics
Average WI 65% Average NRI 51% Mcfe/d IP Mcfe/d 1st Month % gas / % oil IRR @ Base case 35% Typical Well Gross Net Cost - Thousands $2,586 $1,668 Reserves- Mmcfe 1,177 Year 1 Year 2 Year 3 Year 4 Year 5 Terminal Decline Annual Gross Production - Mmcfe 10% Daily Gross Production - Mcfe/d EUR % 17.4 1
Slide 110: Mid-Con Golden Trend Average PUD Economic Analysis
PPT-112-AnalystDay09.22.09 Mid-Con Golden Trend Average PUD Economic Analysis 4.00 Base 8.00 Gas Price ($/MCF) $2.3 MM CAPEX $2.6 MM CAPEX $2.8 MM CAPEX 20% ROR Golden Trend IRR Graph Pricing Scenarios A. $4/MCF and $50/Bbl Flat B. Base Case (strip pricing) 2010 - $5.50/MCF and $70/Bbl 2011 - $6.50/
Slide 111: Mocane Laverne Drilling Economics
Average WI 56% Average NRI 48% Mcfe/d IP Mcfe/d 1st Month % gas / % oil IRR @ Base case 38% Typical Well Gross Net Cost - Thousands $845 $477 Reserves- Mmcfe Year 1 Year 2 Year 3 Year 4 Year 5 Terminal Decline Annual Gross Production - Mmcfe 10% Daily Gross Production - Mcfe/d EUR % 20.0 11.8 9.0 7.
Slide 112: Mid-Con Mocane Laverne Average PUD Economic Analysis
PPT-112-AnalystDay09.22.09 Mid-Con Mocane Laverne Average PUD Economic Analysis 4.00 Base 8.00 Gas Price ($/MCF) $761 M CAPEX $845 M CAPEX $930 M CAPEX 20% ROR Mocane Laverne IRR Graph Pricing Scenarios A. $4/MCF and $50/Bbl Flat B. Base Case (strip pricing) 2010 - $5.50/MCF and $70/Bbl 2011 - $6.50
Slide 113: Permian Basin Division Overview
Permian Basin Division Overview Producing wells: 328 gross / 267 net Reserves Bcfe Gross Net PD PUD Total Proved Probable Possible 3P Potential Total 1,101 Locations Portfolio Highlights Current production (Mmcfe/d): Reserve life (years): 10.5 Gross acreage (thousands): Net acreage (thousands):
Slide 114: Sugg Ranch Field
Sugg Ranch Field Producing wells: 281 gross / 270 net Reserves Bcfe Gross Net PD PUD Total Proved Probable Possible 3P Potential Total Locations Field Highlights
Slide 115: Sugg Ranch Drilling Economics
Sugg Ranch Drilling Economics Typical Well Gross Net Cost - Thousands $735 $713 Reserves - Mmcfe Average WI 97% Average NRI 73% Mcfe/d IP Mcfe/d 1 st Month % gas / % oil IRR @ Base case 49% Year 1 Year 2 Year 3 Year 4 Year 5 5 Yr Cum Terminal Decline Annual Gross Production - Mmcfe 6% Daily Gross Pr
Slide 116: Sugg Ranch IRR Graph
PPT-112-AnalystDay09.22.09 Sugg Ranch IRR Graph Sugg Wells Capex & Price Sensitivity Base Gas Price ($/MCF) $662M CAPEX $735M CAPEX $809M CAPEX 20% ROR Pricing Scenarios A. $4/MCF and $50/Bbl Flat B. Base Case (strip pricing) 2010 - $5.50/MCF and $70/Bbl 2011 - $6.50/MCF and $80/Bbl 2012+ - $7.00/MC
Slide 117: Reserves Discussion
Reserves Discussion Analyst Meeting September 23, 2009
Slide 118: SEC Reserves Definitions
SEC Reserves Definitions Major changes and impact on EXCO Major changes – Definition of “current price” changed – Modern technology allowed to establish certainty levels – ‘Certainty’ criterion replaced by ‘reasonable certainty’ for PUDs – Optional disclosure of probable and possible reserves allowe
Slide 119: Haynesville Shale Booking Challenges
Haynesville Shale Booking Challenges Waiting on final 2009 SEC Reserves Guidance Can statistically support IP rates and initial declines, but decisions must be made concerning: – b factor (shape of curve) assumptions – Terminal decline assumptions – Drainage/spacing assumptions Each company may take
Slide 120: Haynesville Shale Booking Challenges
Haynesville Shale Booking Challenges Proved Reserves - Reasonable certainty in an emerging play in DeSoto Parish Current certainties in DeSoto Parish – Our average IP is 24.1 Mmcf/d – Initial declines are 70 to 80% range – Most wells produced about 0.5 Bcf in the first – days – Five wells have produ
Slide 121: Decline Curve Behavior – Appalachian Basin Example
Decline Curve Behavior – Appalachian Basin Example Significance of using different “b” values: using too low of a “b” factor would significantly underestimate reserves 10 20 30 b = 2.367 (actual) Year b = 1.0 b = 0.0 b = 0.5 b = 1.0 would result in 57% of actual production b = 0.5 would result in 38
Slide 122: Options on Booking Proved Undeveloped Locations
Options on Booking Proved Undeveloped Locations Booking 2 PUD offsets and probable reserves on 160 acre spacing with possible reserves on 80 acre spacing Scenario #1 – 16 Locations/80 Acre Spacing/2 Sections Drilled in Year 1: •1 Proved producing well Booked: •2 Proved Undeveloped (PUD) locations •2
Slide 123: Options on Booking Proved Undeveloped Locations
Options on Booking Proved Undeveloped Locations Booking 4 PUD offsets and probable reserves on 160 acre spacing with possible reserves on 80 acre spacing PROVED PRODUCING PROVED UNDEVELOPED PROBABLE UNDEVELOPED POSSIBLE UNDEVELOPED 5,280 ft 5,280 ft Figure B - Wellbore Reserves Classifications Theor
Slide 124: Reserves – EOY 2009 and Beyond
Reserves – EOY 2009 and Beyond Positive outlook for EXCO Flexibility on booking of shale asset reserves for many years to come High graded reserves and resource base Unquantified resources in the Bossier and other areas Utilizing advanced technologies to support reserves bookings Testing tighter spa
Slide 125: Financial Review
Financial Review Analyst Meeting September 23, 2009
Slide 126: Financial Strategy
Financial Strategy Free cash generation – Capital program funded internally – Target $100 to $200 million of free cash Acquisitions financed with debt, equity, and free cash flow – Supported by 3 – 5 year hedges Maintain rolling three year hedge – Target hedge levels: Year 1: 70 – 90% Year 2: 50 – 7
Slide 127: Liquidity and Financial Position
Liquidity and Financial Position Pro forma for BG Group transaction and 2009 divestitures (1) June 30, 2009 cash includes $58 million of deposits received in the second quarter related to Q3 divestitures and the JV transactions (2) $38 million was deposited before June 30, 2009 (3) $20 million was d
Slide 128: Derivatives Position
Derivatives Position Pro forma production currently 279 Mmcfe/d Total of 132 Bcfe hedged at $8.95 per Mcfe PEPL basis swaps for the remainder of 2009; 10 Mmcf/d swapped at NYMEX minus $1.10 (1) Based on midpoint of production guidance NYMEX Contract Contract Equivalent Contract natural gas price per
Slide 129: Accounting Effects of Transactions
Accounting Effects of Transactions Expect to recognize ~$470 million of book gains – Goodwill will also be reduced by $143 million Formation of TGGT Holdings – Midstream company will be accounted for as an equity investment – 50% of TGGT’s net income included as “Income in equity investment” Gatheri
Slide 130: Five Year Projections
Five Year Projections Based on our current expectations for activity levels, commodity prices, general economic conditions and service costs 2010 is an estimate of capital budget to be presented to the Board in the fall Reflects development of existing asset base without giving effect to any additio
Slide 131: Slide 131
Slide 132: Production Profile
Production Profile Growth profile initially driven by Haynesville development Marcellus contribution accelerates in 2012 and beyond Opportunity to increase Marcellus activity through improvement in infrastructure, regulatory environment and service availability No impacts from Bossier potential Incr
Slide 133: Production Profile and Proved Reserve Growth
Production Profile and Proved Reserve Growth Projected Average Production Midpoint - 1,000 1,200 1,400 2010E 2011E 2012E 2013E 2014E Base Conventional Wedge Haynesville Wedge Marcellus Wedge Proved Reserves (Tcfe) 2010E 2011E 2012E 2013E 2014E Low 1.7 3.0 4.3 5.0 5.5 High 1.8 3.2 4.8 5.5 6.0
Slide 134: SuomM wg suommu ul §
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Slide 135: Projected Financial Results
Projected Financial Results EBITDA grows in-line with projected production growth – 4x in 4 years Free cash flow generation accelerates as Marcellus program becomes cash flow positive Projected EBITDA Midpoint $- $500 $1,000 $1,500 $2,000 $2,500 2010E 2011E 2012E 2013E 2014E Projected Free Cash Flow
Slide 136: 2010 and 2011 Preliminary Upstream Guidance
and 2011 Preliminary Upstream Guidance Low High Low High NYMEX: Oil - Per Bbl 75.00 $ 75.00 $ 80.00 $ 80.00 $ Gas - Per Mcf 5.50 $ 5.50 $ 6.50 $ 6.50 $ Differentials: Oil (2.75) $ (3.25) $ (2.75) $ (3.25) $ Gas 94% 98% 94% 98% Production: Oil - Mbbls Gas - Mmcf 119,376 133,420 188,593 213,501 Equiva
Slide 137: TGGT Operating Forecast
TGGT Operating Forecast EXCO’s Ownership is 50% of TGGT $ in millions Low High Low High Low High Low High Low High Revenue Throughput (Bcf/d) 1.3 1.4 1.9 2.1 2.6 2.8 2.9 3.2 3.2 3.5 Cash Revenue $ $ $ $ $ $ $ $ $ $ Cash Expenses $ $ $ $ $ $ $ $ $ $ EBITDA $ $ $ $ $ $ $ $ $ $ Total Capital $ $ $ $ $
Slide 138: Net Asset Value
In millions, except per share and per unit Low Case High Case E&P Proved Reserves - 1.5 Tcfe at $2.00 & $2.50 per Mcfe 2,976 $ 3,720 $ Unproved Reserves (1) (Conventional) - 1.5 Tcfe at $.20 & $.40 per Mcfe Unproved Reserves (Haynesville) - 2.2 Tcfe at $.30 & $.50 per Mcfe 1,090 Unproved Reserves (B
Slide 139: Valuation Analysis: EXCO Trading Multiples
(1) Peer analysis from Thomson First Call as of September 18, 2009 for 2010 & 2011 EBITDA and 2010 Cash Flow per Share. EXCO’s estimates are based on midpoint of projections. (2) EBITDA and Cash Flow includes 50% of the EBITDA or Cash Flow from TGGT for the respective year. EXCO Trading Multiples (1
Slide 140: Enterprise Value Comparisons to Peers
1) Enterprise value based on stock price as of close on September 18, 2009 and proved reserves updated for any announced acquisition or divestitures year to date. XCO’s production based on current production. 2) EBITDA is from Thomson First Call projections for full year as of September 18, except f
Slide 141: Peer Valuation Comparison
(1) Peer analysis from Thomson First Call estimates for as of September 18, 2009, unless information provided publicly by peer, which was midpoint of peer guidance. Interest expense was based on a Q2 2009 run rate with adjustments made for publicly announced acquisitions, divestitures, or debt offer
Slide 142: Financial Summary
Financial Summary Well hedged Prepared to deliver sustained organic production growth of – 40% per year Shale development and production growth results in a decreasing operating cost structure Strong balance sheet enables us to capitalize on opportunities in our focus areas Low development cost per
Slide 143: Analyst Meeting
Analyst Meeting September 23, 2009