Petroleum Development Corporation

2008 Earnings Teleconference

March 3, 2009

Richard W. McCullough, Chairman & CEO

Gysle R. Shellum, Chief Financial Officer

Barton R. Brookman, SVP Exploration & Production

NASDAQ:PETD

Disclaimer

The following information contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on Management’s current expectations and beliefs, as well as a number of assumptions concerning future events.

These statements are based on certain assumptions and analyses made by Management in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances.  However, whether actual results and developments will conform with Management’s expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by Petroleum Development Corporation; actions by competitors; changes in laws or regulations; and other factors, many of which are beyond the control of Petroleum Development Corporation.

You are cautioned not to put undue reliance on such forward-looking statements because actual results may vary materially from those expressed or implied, as more fully discussed in our safe harbor statements found in our SEC filings, including, without limitation, the discussion under the heading “Risk Factors” in the company’s annual report on Form 10-K and in subsequent Form 10-Qs. All forward-looking statements are based on information available to Management on this date and Petroleum Development Corporation assumes no obligation to, and expressly disclaims any obligation to, update or revise any forward looking statements, whether as a result of new information, future events or otherwise.

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 reserves and 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.

This material also contains certain non-GAAP financial measures as defined under the Securities and Exchange Commission rules.

Rick McCullough

Chairman & Chief Executive Officer

Fundamentals

	2008	2007	2006
Production (Bcfe)	38.7	28.0	17.0
Proved Reserves (Bcfe)	753	686	323
Realized Gas Prices (Mcfe)(1)	$8.66	$6.52	$6.91
Adj. EBITDA ($ millions)(2)	$192.5	$104.2	$80.3
Adj. Cash Flow32.12 from Operations ($ millions)(2)	$200.1	$95.6	$29.8
Adjusted Cash Flow from Operations, per diluted share (2)	$13.48	$6.44	$2.00
Stock Price(3)	$79.09 - $11.50	$61.91 - $35.73	$47.44 - $32.12

(1)   Equivalent prices including oil sales, natural gas liquids and realized derivative gains and losses.  Excludes non-realized derivative gains & losses

(2)   See slides 29 and 30 for GAAP reconciliation of Adjusted EBITDA and Adjusted Cash Flow, respectively.  Gain on leasehold sales excluded.

(3)   Hi-low range, per year.

See Slide 2 regarding Forward Looking Statement

2009 Will Be Challenging

•   2008 – solid growth year

–   Production/Revenues

–   EBITDA/CASH FLOW

–   EPS/CFPS

•   2009 will be challenging

–   Valuable hedges - $153.5 million at 12/31/08

–   CAPEX reduced 50-60%, to $120 - $140 million

–   Current strong liquidity position; will monitor it closely

–   Substantial cost reduction/operational enhancement efforts underway

See Slide 2 regarding Forward Looking Statement

Bart Brookman

Senior V.P. Exploration & Production

Core Operating Regions I{Graphic}

2008 Proved Reserves – 753 Bcfe

Appalachian Basin 15%

Rocky Mountains 82%

Michigan Basin 3%

2008 Production – 38.7 Bcfe

Appalachian Basin 10%

Rocky Mountains 86%

Michigan Basin 4%

Rocky Mountains

2007 Proved Reserves: 559 Bcfe

2007 Production: 23.5 Bcfe

2008 Proved Reserves: 620 Bcfe

2008 Production: 33.2 Bcfe

Michigan Basin

2007 Proved Reserves: 24 Bcfe

2007 Production: 1.7 Bcfe

2008 Proved Reserves: 20 Bcfe

2008 Production: 1.6 Bcfe

Appalachian Basin

2007 Proved Reserves: 103 Bcfe

2007 Production: 2.7 Bcfe

2008 Proved Reserves: 113 Bcfe

2008 Production: 3.9 Bcfe

See Slide 2 regarding Forward Looking Statement

Operating Highlights {graphic}

Historical Drilling

	New Wells	Gross Wells
2002	13	70
2003	30	111
2004	45	158
2005	111	242
2006	138	231
2007	278	349
2008	333	379
2009E	139-150	155-166

Production increased 38% to 38.7 Bcfe

Proved reserves increased 10% to 753 Bcfe

2008 Drilling Activity

Total Wells Drilled Gross - 379

Total Wells Drilled Net -  333

Development - 357

Exploratory - 22

Planned 2009 Drilling Activity

Estimated Total Wells Gross - 155-166

Estimated Total Wells Net - 139-150

See Slide 2 regarding Forward Looking Statement

Net Production {graphic}

See Slide 2 regarding Forward Looking Statement

Production By Basin – Bcfe

Area	2007	2008	% Increase/ (Decrease)	2009E	% Increase/ (Decrease)
Eastern (App/MI)	4.4	5.5	25%	6.0	9%
Wattenberg	11.1	15.4	39%	15.4	0%
Piceance	8.2	12.5	52%	15.4-16.4*	23%-31%
NECO	3.6	5.0	39%	5.8	16%
Other	0.6	0.3	-50%	0.4	33%
TOTAL	28.0	38.7	38%	43-44	11%-14%

This increase assumes further drilling in the Piceance in 2009.  Currently no Piceance drilling rigs are operating.  If future 2009 prices do not justify restarting the Piceance drilling program, the Company may deploy such budgeted capital expenditures to another basin.

Bcfe = One billion cubic feet of natural gas equivalent.

See Slide 2 regarding Forward Looking Statement

YE2008 Proved Reserves Summary

•   Overall – Proved reserves improved 10% from 2007 levels

•   PDP improved 6% from 2007 levels

•   Downward revisions due to commodity pricing and increased costs of approximately 75 Bcfe

•   Upward performance revisions of 41 Bcfe

•   Extensions/additions of 139 Bcfe

•   Reclassified PDNP (Recompletions and Refracs) in Wattenberg to PUD

Summary Reserve Data

	Proved Reserves (Bcfe)(1)
Area	2007 YE	2008 YE	% Growth	% Developed	% Natural Gas
Rockies	559	620	11%	38%	86%
Appalachia	103	113	10%	65%	100%
Michigan	24	20	(17)%	100%	99%
Total	686	753	10%	44%	88%

(1)   Independent reserve engineer’s estimates

See Slide 2 regarding Forward Looking Statement

YE2008 Proved Reserves By Basin  – Bcfe

	PDP		PDNP		PUD		Total Proved
Area	2007	2008	2007	2008	2007	2008	2007	2008
Eastern (App/MI)	83	73	22	21	22	39	127	133
Wattenberg	71	79	48	1	78	118	196	199
Piceance	84	107	8	6	202	260	294	373
NECO	43	40	8	3	16	5	67	47
Other	2	1	0	0	0	0	2	1
TOTAL	283	299	85	31	318	423	686	753
% Total Proved	41%	40%	12%	4%	46%	56%	100%	100%

Bcfe = One billion cubic feet of natural gas equivalent.

See Slide 2 regarding Forward Looking Statement

YE2008 3P Reserves By Basin – Bcfe

	Total Proved		Proved + Probable		Proved + Probable + Possible
Area	2007	2008	2007	2008	2007	2008
Eastern (App/MI)	127	133	127	146	127	156
Wattenberg	196	199	282	236	298	241
Piceance	294	373	444	485	499	538
NECO	67	47	94	57	119	74
Other	2	1	2	1	2	1
TOTAL	686	753	948	925	1,044	1,009

Bcfe = One billion cubic feet of natural gas equivalent.

See Slide 2 regarding Forward Looking Statement

F&D Costs

	2008	2007	2006	2005
Acquisition of Properties	(in millions)
Proved Properties	$13.0	$257.3	$0.8	$1.6
Unproved Properties	―	13.7	11.9	16.9
Development Costs	257.9	194.0	114.5	68.6
Exploration Costs
Exploratory Drilling	15.6	13.0	18.7	12.9
Geological & Geophysical	2.1	6.3	2.2	0.0
Total Costs Incurred	$288.7	$484.3	$148.1	$100.0
*Additions to Reserves (Bcfe)	107.4	396.3	66.9	80.3
F&D Cost ($/Mcfe)	2.69	1.22	2.21	1.25

Additions to reserves = year-end proved reserves + production + dispositions to partnerships - beginning of year reserves

See Slide 2 regarding Forward Looking Statement

2009 Operations Guidance

•   43–44 Bcfe total production expected

•   Capex of $120–$140 MM planned

•   155–166 wells currently planned

•   Significant Capex slowdown company wide

•   Strong efforts in drilling costs/LOE reduction underway

•   Capex expected to be in line with anticipated cash flow

•   Flexibility to adjust Capex to respond to the market

See Slide 2 regarding Forward Looking Statement

2009 Operations Outlook

•   Four Marcellus vertical tests drilled in West Virginia

–   Two wells recently turned in-line

–   One well on flowback

–   One well waiting on completion

–   Nine total vertical tests planned in 2009

•   Compression/curtailment issues in Piceance corrected early 2009

•   One rig currently running in Wattenberg

•   Intermittent drilling planned for NECO, Appalachia through 2009

•   One exploration Bakken test waiting on completion in North Dakota

See Slide 2 regarding Forward Looking Statement

Gysle Shellum

Chief Financial Officer

Quarterly Highlights

•   33% production increase Q4 2008 over Q4 2007, and

11% production increase Q4 2008 over Q3 2008

•   Unrealized hedging gains of $102.5 MM for Q4 2008

•   Key financial metrics (comparison to Fourth Quarter 2007):

–   Revenues up 105%

–   Average realized prices per Mcfe were $5.00 in Q4 2008

(including realized hedging gains)

•   Adjusted Cash Flow from Operations(1) increased 51% to $41.4 MM in Q4 2008 from $27.4 MM in Q4 2007

(1) See slide 30 for GAAP reconciliation of Adjusted Cash Flow from Operations.

See Slide 2 regarding Forward Looking Statement

Summary Financial Results

($ in millions, except for per share data)

	Three Months Ended December 31,		Year Ended December 31,
	2008	2007	2008	2007*
Income from Operations	$74.2	$17.5	$202.3	$60.8
Net Income	$41.1	$8.2	$113.3	$33.2
Diluted Earnings Per Share	$2.78	$0.55	$7.63	$2.24

*2007 data includes $33 million for gain on sale of leaseholds related to the Marathon lease sale.

See Slide 2 regarding Forward Looking Statement

Summary Financial Results

($ in millions, except for per share data)

	Three Months Ended December 31,		Year Ended December 31,
	2008	2007	2008	2007
O&G Revenues	$56.3	$57.5	$321.9	$175.2
O&G Production & Well Operating Costs	$17.1	$16.0	$78.2	$49.3
O&G Operating Margins(1)	$39.2	$41.5	$243.7	$125.9
Adjusted Net Income(2)	$5.6	$11.6	$44.6	$37.5
Adjusted Cash Flow from Operations(2)	$41.4	$27.4	$200.1	$95.6
Adjusted Cash Flow from Operations (per share) (2)	$2.80	$1.98	$13.48	$6.44
DD&A	$32.7	$20.0	$104.6	$70.8
G&A	$10.6	$9.1	$37.7	$31.0

(1)   O&G operating margins is defined as O&G sales less O&G production and well operations costs.

(2)   See slides 30 and 31 for GAAP reconciliation of Adjusted Cash Flow and Adjusted Net Income, respectively.

See Slide 2 regarding Forward Looking Statement

Debt Maturity Schedule ($MM) {graphic}

•   $375 million revolver matures November 4, 2010

•   Maturity schedule reflects:

–   Mitigation of liquidity risk

–   Diversification of funding sources

•   As of December 31, 2008:

–   $195 MM drawn balance

–   $51 MM cash balance

–   $180 MM available balance

•   April 2009 borrowing base redetermination

See Slide 2 regarding Forward Looking Statement

Energy Market Exposure {graphic}

Percentage of Mcfe Sold by Market (for Twelve Months Ended December 31, 2008)

Mich-Con, 4%

Colorado Liquids, 2%

Other, 1%

San Juan Basin/Southern California, 16%

Mid Continent, 12%

NYMEX, 10%

Crude Oil, 16%

Colorado Interstate Gas (CIG), 39%

See Slide 2 regarding Forward Looking Statement

Oil and Gas Hedges in Place at December 31, 2008

	2009	2010	2011
Weighted Average Hedge Price (Mcfe):
With Floors	$8.33	$9.70	$6.76
With Ceilings	$10.52	$11.73	$9.85
% of 12/31/08 Production	59%	29%	5%
Weighted Avg Forward Prices(1)	$5.33	$6.49	$6.97
Blended Pricing @ 12/31/08 Production Levels	$7.10	$7.42	$6.96
Blended Pricing @ 15% Increase in Production	$6.86	$7.29	$6.96

All data excludes CIG basis trades ($4.3MM).

(1) Assuming forward prices as of December 31, 2008 for unhedged production.

See Slide 2 regarding Forward Looking Statement

CAPEX Spending & Production Growth

	08	07	06
CAPEX Total ($MM)	$323	$239	$147
CAPEX Developmental ($MM)	$258	$194	$115
Organic Production Growth(1)	38%	32%	20%

·   Internal estimate

·   See Slide 2 regarding Forward Looking Statement

Adjusted Cash Flow from Operations {graphic}

2008, $200.1

2007, $95.6

2006, $29.8

Note: See slide 30 for GAAP reconciliation

•Adjusted cash flow from operations is defined as cash flow from operations before normal working capital.

•Increased despite lower prices in the second half of 2008

See Slide 2 regarding Forward Looking Statement

EBITDA {graphic}

2008, 4306.9

2007, 4131.7

2006, $415.5

•   EBITDA is defined as Net Income + Interest Expense + Income Taxes + Depreciation, Depletion and Amortization

•   30% higher average gas sales price (including realized gain (loss) on derivatives) in 2008 versus 2007

•   Years 2007 and 2006 include a gain on sale of leaseholds of $33MM and $328MM, respectively.

See Slide 2 regarding Forward Looking Statement

Average Annual Costs Related to Oil and Gas Drilling (per Mcfe)

	Three Months Ended December 31,		Year Ended December 31,
	2008	2007	2008	2007
Average lifting costs	$1.09	$0.94	$1.07	$0.90
DD&A (O&G Properties Only)	$2.73	$2.10	$2.51	$2.37

See Slide 2 regarding Forward Looking Statement

2008 Financial Results

A P P E N D I X

Adjusted EBITDA Reconciliation ($ in millions)

	2008	2007	2006
Net income	$113.3	$33.2	$237.8
Gain on sale of leaseholds	-	(33.3)	(328.0)
Unrealized derivative (gain) loss	(118.4)	4.4	(7.3)
Interest, net	27.5	6.6	(5.6)
Income taxes	61.5	21.0	149.6
Depreciation	104.6	70.8	33.8
Other	4.0	1.5	-
Adjusted EBITDA	$192.5	$104.2	$80.3

See Slide 2 regarding Forward Looking Statement

Adjusted Cash Flow Reconciliation ($ in millions)

Net Cash provided by Operating Activities	$139.1	$60.3	$67.4
Changes in Assets & Liabilities Related to Operations	61.0	35.3	(37.6)
Adjusted Cash Flow from Operations	$200.1	$95.6	$29.8

See Slide 2 regarding Forward Looking Statement

Adjusted Net Income Reconciliation ($ in millions)

	2008	2007	2006
Net income	$113.3	$33.2	$237.8
Unrealized derivative (gain) loss	(118.4)	4.4	(7.3)
Tax effect(1)	45.7	(1.6)	2.8
Other	4.0	1.5	-
Adjusted net income	$44.6	$37.5	$233.3

(1)   Tax rate exclusive of discrete items

See Slide 2 regarding Forward Looking Statement

Petroleum Development Corporation

2008 Earnings Teleconference

March 3, 2009

NASDAQ:PETD