Petroleum Development Corporation
NASDAQ Oil and Gas Conference
London, England
Presenter: Steven R. Williams, CEO
March 6, 2007
Forward-Looking Statements
This information contains predictions, estimates and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those included in the forward-looking statements include the timing and extent of changes in commodity prices for oil and gas, the need to develop and replace reserves, environmental risks, drilling and operating risks, risks related to exploration and development, uncertainties about the estimates of reserves, competition, government regulation and the ability of the Company to meet its stated business goals.
Contact Information:
Investor Relations
Petroleum Development Corporation
120 Genesis Blvd. PO Box 26
Bridgeport, West Virginia 26330
Phone: 304.842.6256 Fax: 304.842.0913 www.petd.com
Increasing Production
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Increasing Proved Reserves
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5-year Stock Performance
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Factors Contributing to Success
• Consistent, scaleable results
• Lower risk projects
• Diversification - with focus areas
• Quality workforce and operations
• Flexibility to pursue options
§ Development
§ Acquisitions
§ Exploration
Core Operating Areas
Rocky Mountains
2006 Proved Reserves: 301 Bcfe
2006 Production: 14.1 Bcfe
2007 Production: 24 Bcfe*
Michigan Basin
2006 Proved Reserves: 19.6 Bcfe
2006 Production: 1.6 Bcfe
2007 Production: 1.8 Bcfe*
Appalachian Basin
2006 Proved Reserves: 35.1 Bcfe
2006 Production: 1.4 Bcfe
2007 Production: 2.6 Bcfe*
*Estimated
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Core Operating Areas
Active Development Areas
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Core Operating Areas
Rocky Mountains
Added interests through
1031 Exchange and other purchase
Michigan Basin
Added interests through
1031 Exchange
Appalachian Basin
Added interests through 1031 Exchange
2006 Summary
• Capital Expenditures were $155 Million
• Company bought back 1.6 million shares (10% of outstanding)
• Production grew from 13.7 Bcfe in 2005 to 17 Bcfe in 2006 (23% increase)
• Proved reserves grew 30% from 275 Bcfe @ YE 2005 to estimated 350 Bcfe @ YE 2006
• Lease sale of $354 Million
• $90 Million in Partnership subscriptions
Acquisitions Summary
• During December 2006 and January 2007, closed $209 Million in acquisitions ($18 Million non-1031)
• 3P reserves acquired total an estimated 153 Bcfe (84% proved)
• Acquisitions primarily in existing operating areas
§ Wattenberg Field, DJ Basin Colorado
§ Appalachian and Michigan Basins
• From $300 Million in 1031 funds, estimated incremental $20 Million in current taxes
Acquisitions Summary (continued)
• Purchases in Wattenberg Field focus on continued development through re-fracs, Niobrara completions and new locations
• Purchased remaining interests in 44 older PDC partnerships, increasing working interest percentages in 718 existing wells primarily in Appalachia and Michigan
• Initial undeveloped acreage position in Barnett Shale play
§ Entry into area similar to PDC initial venture into Rockies area in 1999
Strategic Focus in 2007 and Beyond
• Development operations in core areas
§ Accelerate development on 1031 property additions
• Seek strategic acquisitions
• Develop management, technical and support teams for future needs
• Seek high potential exploration opportunities
• Maintain focus on increasing long-term shareholder value
2007 Projected Drilling, Production & Reserves
2007 Operation and Production Forecast
2006 2007E % Increase
Gross Exit Rate Production (MMCFE/d) 121 182 50%
Net Company Exit Rate Production (MMCFE/d) 53 100 88%
Net Company Production (Bcfe) 17 28 65%
• Drill 419 wells (34 non-operated)
• 164 re-fracs and/or re-completions
• Total drill & complete (D&C) cost estimated $203 Million
• Capital increase of approximately 70% over 2006
Grand Valley Field, Piceance Basin, Colorado
• 148 wells drilled to date
• YE 2006 daily gross production 45 MMcfed
• YE 2006 net daily production 13 MMcfed
• 5,120 Acres available for drilling on 10 acre Spacing
• 470 locations
§ 263 PUD locations
• 137 Planned for Partnership drilling (PDC WI 37%)
• 126 100% WI PDC
§ 207 remaining other locations
Grand Valley Field, Piceance Basin, Colorado
• 1.3 Bcfe per well
• 1.04 net Bcfe @80% NRI
• D&C cost of $2.0 Million / well
• Development cost of $ 1.92 / Mcfe
• Wells drilled directionally from multi-well pads
Grand Valley Field, Piceance Basin, Colorado
2007 Drilling
• Drill 56 wells
• 42 Partnership (PDC 37% WI)
• 14 PDC (100% WI)
• 29.54 Net wells
• 30.7 Bcfe added by drilling
• $59 Million D&C cost
2007 Field Total
• 6.9 Bcfe net production for 2007
• 89% increase over 2006
Wattenberg Field, DJ Basin, Colorado
• 976 wells (drilled and purchased)
• 2006 gross exit rate 40 MMcfed
• 2006 net exit rate 18.6 MMcfed
• 9,000 acres available for drilling
• 540 locations
§ 220 40 acre PUD locations
§ 70 20 acre rule 318-A locations
§ 250 remaining other locations
§ 800 Codell and/or Niobrara re-fracs
• PDC and Partnership development
Wattenberg Field, DJ Basin, Colorado
• 0.3 Bcfe per well (includes re-frac)
• 0.24 net Bcfe @80% NRI
• D&C cost of $490K per well plus $180K for re-frac
• Development cost of $ 2.79/Mcfe or $16.75/Boe
• Producing and undeveloped properties from Unioil and EXCO
Wattenberg Field, DJ Basin, Colorado
2007 Drilling
• Drill 204 wells
§ 100 Partnership (PDC 37% WI)
§ 104 PDC (100% WI)
• 140 Net wells
• 164 re-completions and re-fracs
• 33.9 Bcfe added by drilling
• $93 Million D&C cost
2007 Field Total
• 11.2 Bcfe net production for 2007
• 68% increase over 2006
NECO Field Area, Eastern DJ Basin, Colorado
• 268 operated wells
• 2006 exit rate 10.7 MMcfed
• 2006 net exit rate 8.5 MMcfed
• 29,160 acres available for drilling
• 8 defined structures (3D and 2D seismic)
• 107 PUD locations
• 250 potential locations
NECO Field Area, Eastern DJ Basin, Colorado
• 0.28 Bcfe per well
• 0.22 net Bcfe @80% NRI
• D&C cost of $234K per well
• Development cost of $1.06/Mcfe
NECO Field Area, Eastern DJ Basin, Colorado
2007 Plan
• Drill 141 wells, PDC 100% WI
• 31 Bcfe added by drilling
• $33 Million D&C cost
• 4.5 Bcfe net production for 2007
• 44% increase over 2006
• Acquiring 50 square miles of additional 3D seismic
• Potential addition of 100-200 locations
• Anticipate incremental 5 MMcf/d takeaway capacity in area from Cheyenne-Plains pipeline project
Horizontal Bakken and Nesson Projects, Western Williston Basin, North Dakota
Bakken
• 6 wells drilled to date (3.8 net)
§ 4 in production
• Gross production 350 Boe/d
• Net Company production 275 Boe/d
• 54,285 Acres available for drilling
Nesson
• 10 wells drilled to date (2.7 net)
§ 7 in production
• Gross production 420 Boe/d
• Net Company production 130 Boe/d
• 35,331 Acres available for drilling
Horizontal Bakken and Nesson Projects, Western Williston Basin, North Dakota
Bakken Nesson
Reserves per well 200 MBoe 95 MBoe
Net reserves 160 MBoe 76 MBoe
D&C Costs $4.5 Million $2.9 Million
Development Costs $28 / Boe $38 /Boe
• PDC and other operators working to determine:
§ Optimum horizontal well design, length, orientation and number of legs
§ Efficient stimulation design
§ Define where it works and why
• Achieving answers impacts future success
Horizontal Bakken and Nesson Projects, Western Williston Basin, North Dakota
Bakken Nesson
2007 Drilling 6 7
Net Wells (PDC37%) 2.2 2.6
Reserves Added by Drilling 355 MBoe 197 MBoe
D&C Cost $10 Million $7.5 Million
2007E Net Production 138 MBoe 103 MBoe
Increase from 2006 28% 77%
Appalachian and Michigan Operation Areas
Appalachian Michigan
Operated Wells 1455 204
2006 YE Proved Reserves 35.1 Bcfe 19.6 Bcfe
2007 Acquisition Proved Reserves* 30.1 Bcfe 4.6 Bcfe
% of 2006 YE Proved 85% 23%
2007E Production E* 2.6 Bcfe 1.8 Bcfe
Increase from 2006* 86% 20%
* 2007 Reserve and production increase due to purchase of Partnership interests
Recap
• 2007 will be a busy year
§ Drilling 419 wells
§ Re-frac and/or re-completions on 164 wells
• Production increasing to 100 MMcfe (net) per day by year end
§ 88% increase over year end 2006
§ Annualized rate of 36 Bcfe
• Proved reserves increase by >50% during year
Reserves (Projected)
YE 2006 YE 2007E
Total 356 >500
Producing 147 270
• 129 Bcfe Proved Reserves added through 1031 acquisitions (1/17/07)
• YE 2007 PDP reserves an increase of 84% over YE 2006
Increasing Production - Projected 2007
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Petroleum Development Corporation
NASDAQ Oil and Gas Conference
London, England
Presenter: Steven R. Williams, CEO
March 6, 2007
