Petroleum Development Corporation
C.K. Cooper & Company
2nd Annual Small-Cap Oil & Gas Conference
February 16-17, 2006
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. Additionally, we refer in this presentation to estimated reserves and resource potential, both of which include potential resources that do not meet the SEC definition for proved reserves. The information presented is based on limited regional geological, drilling and production data and there can be no assurance that the estimated reserves or resource potential exist and actual results may differ materially from these estimates.
Contact Information:
Investor Relations
Petroleum Development Corporation
PO Box 26, 103 East Main Street
Bridgeport, West Virginia 26330
P: 304.842.6256 F: 304.842.0913 www.petd.com
Management Representatives Presenting
Petroleum Development - Nasdaq NM: PETD
• Thomas E. Riley, President
• Darwin L. Stump, CFO
• Celesta Miracle, VP Investor Relations & Communications
PDC Financial Highlights
• Strong third quarter and nine months
o Record Revenue
o Nine months earnings
o Adjusted cash flow*
• Long-term debt at $14 million, year-end 2005 $24 million
• Total capital expenditures of $11.8 million for Q305
• Total capital expenditures of $54.0 million for three quarters
• Unrealized derivative losses on Company production impacted third quarter and year-to-date income ($7.8 million and $9.3 million before taxes respectively)
• Company closed third partnership in December with $ 36 million in subscriptions
* Adjusted Cash Flow is Net Income plus non-cash charges (Depreciation, Depletion and Amortization, Deferred Income Taxes and unrealized gains and losses on derivative transactions)
Major Sources and Use of Cash
• Sources (9 months)
o * Adjusted Cash Flow* from Operations- $59.4 million
o Property sales- $9.6 million
• Uses
o Drilling and development activities and properties- $50.0 million
o Stock repurchase- $7.9 million
o Debt reduction- $7.0 million
* Adjusted Cash Flow is Net Income plus non-cash charges (Depreciation, Depletion and Amortization, Deferred Income Taxes and unrealized gains and losses on derivative transactions)
Revenue
• Q3 Revenue of $85.8 million
o $72.3 million in 2004
• Nine months revenue of $252.0 million compared to $215.3 million in 2004
• Revenue reflects higher O&G prices, increased production and drilling activity, and property sales
Net Income
• Q3 Net Income of $7.5 million
o $7.9 million in 2004
• $0.46 EPS compared to $0.47 in 2004 (diluted)
• Includes unrealized derivative losses of $7.8 million pre-tax
o After tax impact of unrealized losses was $.30 per share
Adjusted Cash Flow
• 2005 Adjusted Cash Flow of $59.4 million for 9 months
o Up from $47.6 million in 2004
o Reduced by exploratory dry hole cost
• Adjusted Cash Flow is income before deferred income taxes, depreciation, depletion and amortization, and unrealized derivative losses
• Management believes Adjusted Cash Flow is a useful measure in estimating the value of the Company's operations
Q3 2005 Operating Highlights
• Production 3.43 Bcfe, up 10.0% compared to third quarter 2004
• Rocky Mountain Region production increased 20.2% compared to prior year Q3
• 45 wells drilled in Q3 2005
o 30 successful wells in Wattenberg field
o 7 successful wells in the Piceance Basin
o 7 successful NECO infill wells
o 1 exploratory horizontal Bakken well, North Dakota
• 18 additional Codell recompletions
Year-end Production Update
• 4Q production up 4.3% vs. 3Q to 3.57 Bcfe
o Up 12.6% compared to 4Q 2004
• Year-to-year production increased 8% to 13.7 Bcfe
• Rocky Mountain Region increased 15% in 2005
o Rocky Mountain production was 78% of Company total
• Natural gas was 81% of total
Production
• Q3 2005 production of 3.43 Bcfe
o 80% natural gas
• Reflects impact of investment activities
o Partnership investment
o Recompletions
o NECO infill
• Wells turned in-line during the Q3 05
o 37 Partnership Wells (PDC 20% interest)
o 21 Recompletions (PDC 100% interest)
o 26 NECO area wells (PDC approximately 80% interest)
2005 Year-end Reserves
2004 2005
Proved Developed 165.2 Bcfe 178.5 Bcfe
Proved Undeveloped 52.2 Bcfe 96 Bcfe
Total Reserves 274.5 Bcfe 217.4 Bcfe
• Proved developed reserves increased 8.1%
• Proved undeveloped reserves increased 83.9%
• Total reserves increased 26.3%
Rocky Exploration Opportunities
• North Dakota (oil and gas)
o Bakken Shale
§ 9,000' - 11,000' vertical plus 9,000' horizontal
§ 40,000 acres lease and option
o Nesson Formation
§ 6,000' vertical plus 8,000' - 12,000' multi-leg horizontal
§ Approximately 30,000 acres under lease
• Wyoming (gas)
o Lance, Lewis, Fox Hills, Almond, Mesaverde
§ 8,000' to 13,000'
§ 43,000 acres
• NECO/Kansas
o Niobrara
§ 2,000'
§ 60,000 acres
Grand Valley Field Development Opportunity
• Approximately 14,100 net development leasehold acres
o Puckett Land Company
o Chevron Shale Oil Company
o Encana (formerly Tom Brown Inc.)
• 127 wells drilled to date
• 941 potential locations available for drilling on 15 acre density (Approval for increased well density required in some areas)
• 773 locations available for PDC Corporate development
o 168 allocated for future Partnership drilling activity (PDC WI 25%, 42 additional net wells)
Grand Valley Field Development Potential
• Drilling & Completion cost of approximately $2.0 Million per well
• Average Estimated Ultimate Recoverable (EUR) gas reserves 1.0 - 1.5 BCF
• Finding & development cost net to PDC of approximately $2.00 per Mcf @1.25 BCF EUR and 80% NRI
• Unconfirmed resource potential of 815 Bcf(15 acre well density and 1.25 BCF per well) net to PDC's interest.
Grand Valley Field, Puckett Leasehold
• 7,393 acre Puckett Land Company leasehold
o Entire leasehold held by production (HBP)
o 66 wells have been drilled to date
o Portion of leasehold approved for 10 acre density
o Applying for 10 acre density on remaining acreage
• 6,400 acres remaining and available for development, assuming 15 acres per existing drilled well
• 427 potential drilling locations on 15 acre density (Approval for increased well density required for approximately 50 wells)
• 327 available for PDC Corporate development, approximately 100 allocated for future Partnership drilling activity (PDC WI 25%, 25 net wells)
Grand Valley Field, Chevron Leasehold
• 14,508 acre Chevron Shale Oil Company leasehold
o 6,314 acres on a quarter section checkerboard pattern sold in 2005 to Piceance Gas Resources, LLC
• 8,194 net PDC acres
o 50 wells drilled to date
o Majority of leasehold approved for 10 acre increased density
o Applying for 10 acre increased density on remaining acreage
• 7,444 acres available for development assuming 15 acres per drilled well
• 496 potential drilling locations on 15 acre density
• 446 available for PDC Corporate development, approximately 50 allocated for future Partnership drilling activity (PDC WI 25%, 12.5 net wells)
Grand Valley Field, Encana Leasehold
• 440 acre Encana farmout leasehold
• 11 wells have been drilled to date
• 18 remaining locations on approximately 15 acre spacing (4.5 net wells to PDC interest)
• Remaining wells allocated for future Partnership drilling
North Dakota Bakken Horizontal Opportunity
• Approximately 59,400 net acres of leasehold across 7 Project areas
• Leasehold acquisition continuing
• PDC ownership includes various interests from 5-100% WI in an alternating checkerboard pattern of 1,280 acre stand-up blocks with 80% NRI
• Operations will include non-operated properties
• 40-50 net well total potential with successful results in each project area
North Dakota Bakken Horizontal Opportunity
• Average Estimated Ultimate Recover (EUR) of approximately 300,000 BO or more
• Current estimated well cost $4.2M
• Estimated finding and development cost of approximately $2.91 per MCFE ($17.50 per BOE)
• �� Unconfirmed resource potential of approximately 13.5 MMBO net to PDC's interest.
North Dakota Bakken Initial Test Well
• 1st well, Fedora 34-22H, drilled successfully to a measured depth of 18,315' with a true vertical depth of 10,780' (lateral length of approximately 7,500')
• Date of first production October 1, 2005 Cumulative production as of 2/6/06 approximately 23,350 BO and 12,500 Mcf
• Current production approximately 200 BOPD and 150 MCFD
• 2nd well, Violet-Olson 31-29H, drilled to a measured depth of 18,411' and a true vertical depth of 9,943' (lateral length of 8,468)
• Estimated completion activity in next 30 days
North Dakota Nesson Horizontal Opportunity
• Approximately 30,000 net leasehold acres (80% NRI)
• PDC ownership on a section by section basis varies from 5-100%
• Development potential from 25 to 50 net wells or more
• Operations will encompass Operated and Non-Operated properties
• Development will require single long leg horizontal wells and shorter multi lateral wells
North Dakota Nesson Horizontal Potential
• Nesson horizon depths range from 5,000' to 6,000'. Lateral horizontal displacement ranges from 8,000 to 10,000 feet or more
• Drilling and completion cost of approximately $1,500,000
• Average Estimated Ultimate Recovery of 100,000 BO or more and 50-100MMcf
• Finding and Development cost of approximately $16.67 / BOE
• Unconfirmed Resource Potential estimated between 2.25 MMBOE and 4.5 MMBOE net to PDC interests.
Sustaining Growth
• The market for partnership interests in oil and gas wells is at record levels
• PDC sold a record $116 million in 2005
• Currently working on 2006 offering with planned $100 million offering
• The Company invested approximately $8.5 million in the fourth quarter in non-partnership drilling in Wattenberg field
• Successful exploratory well in North Dakota Bakken shale
• Second Bakken shale exploratory test is currently underway with well in horizontal leg
• Company has contracted for two additional rigs for North Dakota and other deeper prospects
• Strong balance sheet allows ample funding for additional acquisitions if available
2006 Drilling Plans
• Rockies: Plan drilling in Wattenberg and Piceance
o Partnership funds split between areas
o About 3-4 Wattenberg wells per Piceance well
o PDC will have a 25% interest in future partnerships (30% interest in last 2005 partnership)
• 2 or more Bakken exploratory tests. Additional exploratory and development wells planned pending successful results of initial test wells
• 3 Nesson horizontal wells to be drilled in 1Q 2006. PDC non-operated interest of approximately 33%.
• New area tests on NECO properties
• Sweetwater test planned in first or 2nd quarter of 2006
• Continue search for additional opportunities
Petroleum Development Corporation
February 16-17, 2006
