Petroleum Development Corporation

BMO Capital Markets

2008 Appalachian Conference

January 10, 2008

Steven R. Williams, Chairman & CEO

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.

The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company uses in this presentation the terms “probable” and “possible” reserves, which SEC guidelines prohibit in filings of U.S. registrants. Probable reserves are unproved reserves that are more likely than not to be recoverable. Possible reserves are unproved reserves that are less likely to be recoverable than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

Contact Information

Investor Relations: Petroleum Development Corporation

120 Genesis Boulevard, PO Box 26, Bridgeport, West Virginia 26330

Phone: 304.842.3597, Fax: 304.842.0913, www.petd.com

Recent Developments

·   Richard McCullough named to succeed Steve Williams as CEO

o   Currently serves as CFO

o   Extensive financial and energy experience

o   Approximately 8 month transition period

·   North Dakota Bakken Shale properties sold for $34.7 million

o   Estimated $3-5 million after-tax gain in fourth quarter 2007

o   Company retained Nesson formation projects including 58,000 leasehold acres in Burke County

Company Snapshot

·   Market Cap (12/31/07)

o   $ 881 million

·   Estimated 2007 Year-end Proved Reserves

o   650+ Bcfe*

·   3-P Reserves @YE2007

o   1+ TCFE**

·   Annual Production

o   28 Bcfe (2007E)

·   Diluted Average Shares Outstanding (2007)

o   Down 7.5% from 2006

* Reserves are based on internal Company estimates.

        ** Reserves included in probable and possible categories do not meet the SEC definitions of proved reserves and may be subject to greater risk of recovery than reserves meeting SEC requirements.

Rocky Mountains

·   2006 Proved Reserves: 265.5 Bcfe

·   2006 Production: 14.1 Bcfe

·   2007E Production: 24 Bcfe

Michigan Basin

·   2006 Proved Reserves: 21.2 Bcfe

·   Production: 1.4 Bcfe

·   2007E Production: 1.8 Bcfe

Barnett Shale

·   Exploratory project

·   December 2007 drilling

Appalachian Basin

·   2006 Proved Reserves: 36.0 Bcfe

·   2006 Production:  1.5 Bcfe

·   2007E Production: 2.6 Bcfe

Key Value Drivers

·   Proven Track Record

o   5-year 850% return to shareholders

o   66% year-over-year production growth

o   55% year-over-year reserve growth

·   Visible Built-in-Growth

o   More than 1 Tcfe of 3P reserves provides significant near-term growth potential

o   Large multi-year, low risk drilling inventory

o   Recently added 47 Bcfe of proved reserves in Southwestern Pennsylvania (15.8 Bcfe producing)

·   Strong Financial Position

o   Strong balance sheet

o   Debt-to-cap 26% (end of 3rd Qtr)

See Slide 2 regarding Forward Looking Statements

Third Quarter Highlights

·   Record three month production of 7.72 Bcfe

o   Record nine month production of 19.5 Bcfe

o   On track with 28 Bcfe guidance for 2007

·   Adjusted Cash Flow from Operations* = $31.6 million; up substantially despite impact of lower realized prices in Rockies

·   Drilled 95 gross new wells including 4 in the Appalachian Basin

o   80.8 net wells

o   264 gross (220.4 net) wells for 9 months

* Adjusted cash flow from operations is defined as cash flow from operations before changes in assets and liabilities.  EBITDA is defined as Net Income + Interest, net + Income Taxes + Depreciation, depletion, amortization. These are non-GAAP measures.  See slide 27 for further information.

See Slide 2 regarding Forward Looking Statements

Investments Adding Value ($ in million, except for Mcfe Data)

·   Results of investments in people & production

	Third Quarter		Nine Months Ended Sep 30
Expense Category	2006	2007	2006	2007
Oil & gas production & well ops.	$8.6	$12.6	$22.4	$33.3
Per Mcfe	$1.99	$1.64	$1.84	$1.71
General & administrative expense	$5.3	$7.5	$14.2	$21.8
Per Mcfe	$1.24	$0.97	$1.17	$1.12
DD&A	$8.3	$20.4	$22.5	$50.9
Per Mcfe	$1.92	$2.64	$1.85	$2.61

See Slide 2 regarding Forward Looking Statements

Diverse Energy Market Exposure

Percentage of Production by Market (Based on Mcfe)

·   Oil:                                21.6%

·   Northern Border:        0.5%

·   Mid-continent:           14.3%

·   Colorado Liquids:      3.0%

·   Nymex:                         12.4%

·   Michigan:                    5.9%

·   Colorado:                    42.3%

See Slide 2 regarding Forward Looking Statements

Continuing Our Success

·   Colorado Acquisitions - production and development opportunities

·   Active development program

o   On existing and acquired properties

o   Approximately 355 wells drilled in 2007

·   Operations enhancements

o   Piceance Basin Compression

o   Garden Gulch road completed

o   Codell recompletions and Niobrara refracs

·   Acquired acreage and began drilling in Barnett shale in December 2007

·   Pennsylvania acquisition - production and development opportunities

See Slide 2 regarding Forward Looking Statements

Increasing Production

·   Record 7.7 Bcfe 3Q07

·   On track to meet 28 Bcfe annual guidance

·   YTD Production by area

o   Rocky Mountains = 83.6%

§   75.7% Natural Gas

§   24.3% Oil

o   Appalachian Basin = 9.8%

o   Michigan = 6.6%

See Slide 2 regarding Forward Looking Statements

Increasing Estimated Proved Reserves

·   Anticipate greater than 650+ Bcfe proved reserves for YE 2007

o   Additions through both the drill bit and acquisitions

·   Active areas primarily in Colorado - Piceance, Wattenberg and NECO

·   Southwestern Pennsylvania acquisition

* Reserves are based on internal Company estimates

See Slide 2 regarding Forward Looking Statements

Drilling Activity

{Graphic}

2007 Actual vs. Production Forecast

·   Estimated 2007 Production of 28 Bcfe

o   Nine month production of 19.5 Bcfe

·   Estimated 2007 Exit Rate approximately 100 MMcfd

·   Challenges to meeting production goal

o   Back-log of wells awaiting turn-in in Grand Valley, Wattenberg and NECO areas

o   Fourth quarter curtailment

See Slide 2 regarding Forward Looking Statements

Enhancements to 2007 Operational Plan

·   Acquired 47 Bcfe of proved reserves in Southwestern Pennsylvania

·   Increased net Grand Valley wells

·   Increased CAPEX in Codell refracs and Niobrara recompletions

o   Originally modeled Codell only completions; actual wells are multi-zone completions (J-sand, Codell and Niobrara, as appropriate)

o   Drilling fewer net Wattenberg wells

·   Reduced activity level in ND and reallocated capital

See Slide 2 regarding Forward Looking Statements

Development Plans

·   Over 400 Bcfe of Probable and Possible Reserves for Future Development

o   Grand Valley offset locations

o   Wattenberg field locations (5th spot, rule 318A and 40 acre locations)

o   Locations identified by seismic and offsets to producing wells in NE Colorado

o   31.2 Bcfe in Southwestern Pennsylvania

·   Distribution of 2P and 3P Reserves

o   Piceance Basin:              57%

o   NE Colorado:                  19%

o   North Dakota:                 5%

o   Wattenberg Field:         19%

See Slide 2 regarding Forward Looking Statements

Grand Valley Field, Piceance Basin, Colorado

2007 Plan

·   September 2007 net daily production 31 Mmcfe/d (2006 exit rate was 15.4 Mmcfe/d)

·   Approximately 355 net locations on 10-acre spacing

o   148 net PUD locations

o   207 remaining unproved locations

·   Drill 41 net wells

o   50 Bcfe added by drilling

o   $93 Million D&C cost

See Slide 2 regarding Forward Looking Statements

Grand Valley Achievements

·   Reduced drilling time

o   Valley wells drilled in 11 days (2007) vs 18 days (2005)

o   Mesa top directional wells drilled in 15 days (2007)

·   Improved Completion Design

o   Slick Water Fracs– cleaner, non-gelled fluid results in improved EURS

o   20% increase of per-well EURs from 1.25 to 1.5 Bcfe

o   Increase IP rate from 820 to 1,100 Mcfd

See Slide 2 regarding Forward Looking Statements

Wattenberg Field, DJ Basin, Colorado

·   September 2007 net daily production 36 Mmcfe/d (2006 net exit rate 18.6 Mmcfe/d)

·   3P reserves include over 900 net undeveloped locations (primarily downspace locations)

·   Future opportunity of 800 Codell and/or Niobrara refracs

·   2007

o   Drill 108 net wells

o   Add estimated 34 Bcfe drilling reserves

o   164 re-completions and re-fracs

o   $86 Million D&C cost

See Slide 2 regarding Forward Looking Statements

NECO Field Area, Eastern DJ Basin, Colorado

·   29,160 acres available for drilling

·   8 defined structures (3D and 2D seismic)

·   100 PUD locations

·   200 potential locations

·   2007 Plan

o   Drill 141 wells, PDC 100%WI

o   31 Bcfe added by drilling

o   $33 Million D&C cost

o   Acquiring 50 square miles of additional 3D seismic

§   Potential addition of 100-200 locations

See Slide 2 regarding Forward Looking Statements

Appalachian and Michigan Operation Areas

	Appalachian	Michigan
Operated Wells	2116	206
2006  YE Proved Reserves	36.0 Bcfe	21.2 Bcfe
2007 Acquisition Proved Reserves *	30.1 Bcfe	4.6 Bcfe
% of 2006 YE Proved	84%	22%
2007E Production*	2.6 Bcfe	1.8 Bcfe
Increase from 2006*	86%	20%
July 2007 Net Daily Production	6.2 Mmcfe/d	4.5 Mmcfe/d

Reserves are based on internal Company estimates

See Slide 2 regarding Forward Looking Statements

Southwestern Pennsylvania, Castle Acquisition

·   PETD closed the acquisition of Castle Gas Company assets in October 2007

o   $53 million purchase price

§   $1.12 per Mcfe

o   Acquired majority interest in 760 natural gas wells located in southwestern Pennsylvania

o    Current daily production of 3,000 Mcfe/d

·   Highly predictable, low risk drilling

o   47 Bcfe of proved reserves

See Slide 2 regarding Forward Looking Statements

2008 Proposed Development – Appalachian Projects (Excludes Castle Acquisition Projects)

Appalachian Basin
	2007	2008	% Change
Total Net Production (BCFE)	2.6	3.1	17%
Net Exit Rate (MMCFE/D)	8.2	9.1	11%
Gross Exit Rate (MMCFE/D)	12.6	13.6	7%
Total Net Capital (MM$)	$4.35	$8.9*	105%
Number of Drilling Projects	8	23	187%
Number of Reworks/Refracs	31	30	0%

* Preliminary pending final determination of 2008 Capital Budget

See Slide 2 regarding Forward Looking Statements

2008 Proposed Development – Appalachian Projects (Excludes Castle Acquisition Projects)

{Graphic}

2007-2008 Appalachian Production History & Forecast (Excludes Castle Acquisition Production)

{Graphic}

2008 Proposed Development – Appalachian Basin (Excludes Castle Acquisition Projects)

ASSUMPTIONS – APPALACHIAN

·   3% base PDP curtailment, increased to 10% in summer months

·   2008 plan dependent upon 2007 pilot down-spacing program

·   Average D&C cost on new wells of $330,000

·   Average recompletion cost of $51,500

·   Average gross reserves per new drill of 0.18 BCFE

See Slide 2 regarding Forward Looking Statements

2008 Proposed Development – Castle Acquisition (Excludes Castle Acquisition Projects)

                                                                 2008

·   Total Net Production (BCFE):              1.3

·   Net Exit Rate (MMCFE/D):                   4.4

·   Gross Exit Rate (MMCFE/D):               7.0

·   Preliminary Net Capital (MM$):           $12.7

·   Number of Drilling Projects:                 50

See Slide 2 regarding Forward Looking Statements

2008 Proposed Development – Castle Projects (Excludes Castle Acquisition Projects)

{Graphic}

2008 Castle Production Forecast

{Graphic}

Marcellus Shale “Fairway” PDC Areas of Operation

·   PDC operates over 2100 wells within the Marcellus “Fairway” area

·   Leasehold combination of lease, farmout and wellbore ownership

·   Potential of up to 50,000 or more development acres within “Fairway”, pending full determination of leasehold rights

See Slide 2 regarding Forward Looking Statements

Track Record of Consistent Growth

{Graphic}

Supplemental Data

2007 Production Forecast

2007 Forecast by Area (MMcfe)

				Forecast
Area	1Q Actual	2Q Actual	3Q Actual	1Q	2Q	3Q	4Q	2007
Rocky Mountain	4,290	5,322	6,683	4,435	5,041	6,794	7,405	23,675
Appalachian	617	687	610	625	640	680	689	2,634
Michigan	426	427	428	415	424	456	459	1,754
Company Total	5,333	6,436	7,721	5,475	6,104	7,931	8,553	28,063

Rocky Mountain Forecast by Area (MMcfe)

				Forecast
Area	1Q Actual	2Q Actual	3Q Actual	1Q	2Q	3Q	4Q	2007
Wattenberg	2,209	2,623	2,963	2,314	2,586	3,149	3,361	11,410
Grand Valley	1,246	1,590	2,622	1,064	1,245	2,086	2,094	6,490
NECO	677	942	960	834	954	1,203	1,492	4,483
North Dakota	158	165	138	224	256	355	458	1,293
Rocky Mountain Total	4,290	5,321	6,683	4,435	5,041	6,794	7,405	23,675

Forecasted numbers are from presentation to Analysts on January 22, 2007

Major Operating Area Highlights

·   Wattenberg Area production shortfall due to weather related issues, production not “lost” but delayed

·   Grand Valley production positively impacted by facility improvements and greater # of wells inline

·   NECO Area production difference due to fewer wells inline than anticipated

EBITDA  & Adjusted Cash Flow from Operations Reconciliation ($ in thousands)

EBITDA	2002	2003	2004	2005	2006	09/30/07	3Q06	3Q07
Net Income	$8,881	$20,413	$33,228	$41,452	$237,772	$25,011	$210,884	$4,459
Interest	1,257	626	53	(681)	(5,607)	2,766	(3,109)	2,082
Income Taxes	3,186	11,934	20,250	24,676	149,637	15,511	132,795	3,326
Depreciation	12,602	15,313	18,156	21,116	33,735	50,857	8,300	20,354
EBITDA	$25,926	$48,286	$71,687	$86,563	$415,537	$94,145	$348,870	$30,221

Management believes EBITDA is relevant because it is a measure of cash available to fund the Company’s capital expenditures and service its debt and is a widely used industry metric which allows comparability of our results with our peers.

Adjusted Cash Flow Operations	2002	2003	2004	2005	2006	9/30/2007	3Q06	3Q07
Net Cash Used in Operating Activities	$28,173	$73,608	$73,301	$112,372	$67,390	($32,800)	$2,632	$43,585
Changes in Assets & Liabilities to Operations	(2,875)	(26,691)	(10,786)	(38,815)	(37,554)	101,003	(2,497)	(11,947 )
Adjusted Cash Flow  from Operations	$25,298	$46,917	$62,515	$73,557	$29,836	$68,203	$135	$31,638

Management believes Adjusted Cash Flow from Operations is relevant because it is a measure of cash available to fund the Company’s capital expenditures and service its debt.  Management also believes Adjusted Cash Flow from Operations is a useful measure for estimating the value of the Company’s operations.

See Slide 2 regarding Forward Looking Statement

Petroleum Development Corporation

BMO Capital Markets

2008 Appalachian Conference

January 10, 2008

Steven R. Williams, Chairman & CEO