Petroleum Development Corporation
2007 Analyst Meeting
New York, New York
January 22, 2007
NASDAQ GSM:PETD
Introductions
• Celesta Miracle, VP Communications and Investor Relations
• Steve Williams, Chief Executive Officer
• Thomas Riley, President
• Eric Stearns, Executive Vice President Exploration and Production
• Rick McCullough, Chief Financial Officer and Treasurer
Order of Presentation
• History and Overview - Steve Williams
• 2006 and 2007 Operating Overview - Thomas Riley
• 2007 Drilling, Production & Reserves - Eric Stearns
• 2006 and 2007 Financial Guidance- Rick McCullough
• Summary and Wrap Up - Thomas Riley
• Questions - Steve Williams
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
Cautions for Guidance Information
• Major changes resulting from acquisitions
• Income, cash flow and balance sheet impacted by:
§ Prices, prices, prices
§ Timing of development work
§ Success of drilling operations
§ Development costs
§ Actual reserves and production
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
Peer Group Comparisons
2003-2005 CAGR
Measure PDC Peer Group
ROCE 23% 16%
Revenue Growth 36% 42%
EBIT Growth 78% 71%
EPS Growth 62% 59%
Total Shareholder
Return 85% 47%
Peer group was comprised of Unit Corporation, St. Mary Land & Exploration Company, Cabot Oil & Gas Corporation, Penn Virginia Corporation, Whiting Petroleum Corporation, Range Resources Corporation, Encore Acquisition Company, Berry Petroleum Company, KCS Energy Incorporated, Quicksilver Resources Inc, Clayton Williams Energy Incorporated, and Brigham Exploration Company, Magnum Hunter Resources Incorporated, and Cimarex Energy Company.
Core Operating Areas
Rocky Mountains
2006 Proved Reserves: 301 Bcfe
2006 Production: 14.1 Bcfe
2007E Production: 24 Bcfe
Michigan Basin
2006 Proved Reserves: 19.6 Bcfe
2006 Production: 1.6 Bcfe
2007E Production: 1.8 Bcfe
Appalachian Basin
2006 Proved Reserves: 35.1 Bcfe
2006 Production: 1.4 Bcfe
2007 Production: 2.6 Bcfe
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Core Operating Areas
Operate 3,000 wells in three major regions
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Core Operating Areas
Active Development Areas
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Core Operating Areas
Active Exploration Area
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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
Key Capabilities and Assets
• Industry professionals
• Development history in non-conventional reservoirs
• Successfully add opportunities in new areas
• Partnership operations
• Drilling inventory
• Acquisition successes
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
2006 and 2007 Operating Overview
Thomas Riley
2006 Summary
• Capital Expenditures were $155 Million
• Company bought back 1.6 million shares (10% of outstanding)
• Production grew from 13 Bcfe in 2005 to 17 Bcfe in 2006 (30% increase)
• Proved reserves grew 30% from 275 Bcfe @ YE 2005 to estimated 356 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
2007 Summary
• CapEx expected to be $201 Million in 2007
• Production growth of 65% (28 Bcfe estimated in 2007 compared to 17 Bcfe in 2006)
• PDP Reserves expected to grow >50% during 2007
• Plan $100 Million Partnership offering
2007 Drilling, Production & Reserves
Eric Stearns
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
Grand Valley Field, Piceance Basin, Colorado
Past and Future Highlights
• 2006 $354 Million sale of acreage to Marathon
• Progress continues on access road construction project
§ Total cost $18 Million
§ Partners Williams, Berry and Marathon
§ Estimated completion date June 2007
• Commenced 50 MMcfd compression and pipeline expansion project
§ Estimated in service date June 2007
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
§ 2 WOC
• 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
§ 3 WOC
• 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
2006 and 2007 Financial Guidance
Rick McCullough
Forward-Looking Statements (Reminder)
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
Growing Financial Base
2004 2005 2006E
Operating Income (Millions) $57.2 $76.2 $372.81
Adjusted Cash Flow (Millions)2 $61.8 $69.1 $339.11
1 Includes the sale of leasehold for $354 Million which resulted in a $330 Million pretax and $202 Million after tax gain
2 Adjusted cash flow is income before deferred taxes, depreciation, depletion, amortization and unrealized derivative gains or losses
Impact of 1031 Transactions
2006 Financial Statements
• No further P&L impact expected in 4Q
• Unexpended amounts classified as current asset (approximately $109 million)
• Expense 2006 IDC
• Deferred tax liability for a portion of gain will be reclassified current, net of IDC deferral
• Unioil (not 1031) will have nominal impact on 2006
• All other transactions will impact 2007
§ Subsequent events in 2006 10-K footnotes
Impact of 1031 Transactions
2007 Financial Statements
• Cash flow - $109 million unexpended gain less 2006 taxes payable 3/15/2007 of approximately $20 million available for corporate purposes
• Operating Cost - Will increase due to acquisitions and additional development activity
• Well Operations Revenue - partnership purchase will reduce well operations revenue
• CapEx - $201 million for 2007
• Debt - Throughout the year will vary from $50 - 150 Million; comparable to 2006 levels
2006 Results (Estimated and Unaudited)
2006 Guidance
YTD 9/30/06 Full Year 2006
Revenues (Millions) $209 $273
Expenses
DD&A ($/Mcfe) $1.86 $1.89
G&A ($/Mcfe) $1.08 $1.03
Gain on Sale of Leasehold
(Millions) $328 $328
Operating Income (Millions) $362 $373
Net Income (Millions) $230 $239
2007 Guidance
(Millions)
Revenues $375 - - 410
Expenses
DD&A $58 - - 65
G&A $14 - - 16
Operating Income $82 - 95
Net Income $47 - - 54
2007 Projection
• Growing CapEx (in Millions)
§ 2005 $107
§ 2006E $155
§ 2007E $201
• G&A1 (in Millions)
§ 2005 $7.0 $0.51 per Mcfe
§ 2006E $17.5 $1.03 per Mcfe
§ 2007E $14-16 $0.50 - 0.56 per Mcfe
1 G&A in 2006 and 2007 reflects 2005 10-K restatement and ongoing SOX compliance and partnership restatement costs
2007 Projection - Key Assumptions
• Forward Prices (January 11, 2007)
§ Nymex gas $6.84/Mcf
§ Basis range +$.29 to -$1.85/Mcf
• NYMEX Oil - $55.33/Bo
• Assumed sales mix
§ 72% natural gas
§ 28% oil
2007 Projection - Key Assumptions
• CapEx largely funded by cash flow and 1031 proceeds
• Continuing growth in staffing
• New partnership Drilling Program in mid-2007
§ $100 Million in subscriptions planned
2007 Projection - General Points
• Reduced interest income compared to 2006
• Greater oil and natural gas production
• Significant re-frac opportunity associated with acquisitions with expected near-term payback
• Sensitivity to changing oil and natural gas prices
§ 10% change impacts net income by $11 million and EPS by $.70 per share
Natural Gas Floors for 2007
Period Appalachian & Mich Northeast, Colorado, (NECO) Piceance Wattenberg
Jan - Mar 94% @ $6.84 (Nymex) 40% @ $6.50 (Panhandle Eastern) 50% @ $5.06 (CIG)
Apr - Oct 94% @ $6.84 (Nymex) 55% @ $5.50 (Panhandle Eastern) 50% @ $4.73 (CIG) 50% @ 4.00 (CIG)
Nov - Dec 40% @ $7.00 (Nymex) 18% @ $5.75 (Panhandle Eastern) 50% @ $5.25 (CIG)
Cautionary Comments Regarding 2007 Guidance
Many factors are subject to variation from estimates, including:
• Drilling results - reserves and production rates
• Timing and cost of development activities
• Gas & oil price volatility
§ Basis volatility in Rockies markets
• Growing base of oil production
• Substantial CapEx associated with acquisitions
• Impact of commodity price derivatives
Summary and Wrap-up
Thomas Riley
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, Reserves, Reserves
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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Keeping the Powder Dry
• Strong production growth
• High exit rate in 2007 - strong base for 2008
• Increased organizational strength
• Low debt
• Looking for opportunities
Questions
Steve Williams
