NASDAQ:PETD

PETROLEUM DEVELOPMENT
CORPORATION

Analyst Day

March 12, 2010

See Slide 2 regarding Forward Looking Statements

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 2009 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. 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.

Disclaimer

2

See Slide 2 regarding Forward Looking Statements

3

Welcome

•Peter G. Schreck

Vice President - Finance and Treasurer

•Introductions

–Richard W. McCullough

Chairman and Chief Executive Officer

–Barton R. Brookman

Senior Vice President - Exploration and Production

–Gysle R. Shellum

Chief Financial Officer

–Lance A. Lauck

Senior Vice President - Business Development

See Slide 2 regarding Forward Looking Statements

See Slide 2 regarding Forward Looking Statements

Rick McCullough

Chairman & Chief Executive Officer

4

See Slide 2 regarding Forward Looking Statements

(1) Appalachian Basin (Marcellus and Shallow Devonian) JV

(2) EBITDAX and Cash Flow estimates as per analyst consensus

(3) From 3/1 to 2/28

•Petroleum Development Corporation is an
independent oil and natural gas company
with operations primarily in the Rocky
Mountain region, Appalachian Basin and
Michigan Basin

•PDC was founded in 1969 in Bridgeport, WV
and is now headquartered in Denver, CO

Enterprise Value

Capitalization

Corporate Profile

5

	2008	2009
Share Price (3/09 and 3/10)	$9.70	$22.61
Diluted Share Outstanding (MM)	14.8	19.2
Market Capitalization ($MM)	$144	$435
Net debt total @ year-end	344	249
Minority Interest @ year-end	-	48
Enterprise Value	$488	$731
52-Week High ($/share) (3)	$78.35	$24.65
52-Week Low ($/share) (3)	$11.73	$9.70

Corporate Summary

	2008	2009
Net Debt Total @ year-end	$344	$249
Common Equity	512	491
Minority Interest (1)	1	48
Total Capitalization ($MM)	$856	$787
Debt Ratios:
Debt/EBITDAX (LTM) (2)	1.70x	1.54x
Senior Debt/EBITDAX (LTM) (2)	0.85x	1.10x
EBITDAX/ Interest Net (LTM) (2)	8.4x	4.9x
Debt/Book Cap	44%	34%

PDC increased its market capitalization
by 202% since last year’s analyst
meeting

See Slide 2 regarding Forward Looking Statements

6

2009 PLANS:
PROVIDED AT MARCH 2009 ANALYST DAY
MEETING

Implementing an internal strategic reassessment process

•Measuring activities based on their contribution to shareholder value

•Entire company involved

•Will drive future decision making

Review of all major elements of cost

Basin by basin operational enhancement review

•Costs; logistics; marketing

2009 Theme - cost control and operational enhancements

2009 Capex will be reduced with intensified focus on:

•Capital cost improvements

•Production engineering / production optimization

•LOE improvements

See Slide 2 regarding Forward Looking Statements

7

2009 PLANS:
PROVIDED AT JULY 2009 ANALYST DAY
MEETING

Scale and Cost Control

•Control / reduce CAPEX/OPEX through strategic negotiations

•Gain scale / mediate cost sensitivity in basins which are highly
sensitive to commodity pricing (particularly Wattenberg)

Alternative Capital Sources

•Pursue joint ventures in emerging Shale plays

•Position the Company financially to capitalize on strategic alternatives
which could drive shareholder value creation

Financial Focus

•Implement long-term hedging strategy to mitigate risk and solidify
value preservation

Diversify and Increase Projects

•Continue to monitor/assess acquisition and divestiture opportunities,
and enhance A&D capabilities

See Slide 2 regarding Forward Looking Statements

Goal

8

REVIEW OF 2009 GOALS:
HOW DID WE DO?

Results

1	Liquidity target at year-end of >$155 MM
2	Cash flow per share target of >$7.20/share
3	Scale and cost control:
*	~15% - 20% reduction in oil and gas production and well operations cost/Mcfe
*	12% reduction in G&A expenses per Mcfe
4	Alternative capital sources:
*	Pursue joint ventures
*	Balance sheet strength and liquidity at year-end
5	Financial focus:
*	Opportunistic hedging implementation; at March 2009 hedge position of 70% for 2010 and 30% for 2011
*	Minimize loss of bank borrowing base size
6	Diversify and increase projects:
*	Position Company to pursue project diversification

1	Liquidity of $257 MM
2	Cash flow per share of $10.35 with greater shares outstanding than forecasted
3	Scale and cost control:
*	From $2.05/Mcfe to $1.50/Mcfe, down ~$27%
*	29% increase from $0.97/Mcfe to $1.25/Mcfe due to non-recurring expenses; 2010 reduction of ~7.5%
4	Alternative capital sources:
*	Closed ~$160 MM PDC Mountaineer JV on 10/1/09
*	~$100MM of liquidity improvement, and improvement in balance sheet leverage and coverage measures
5	Financial focus:
*	Hedging contributed over $100MM to revenue in 2009; solid hedge position (60% - 80%) for 2010-2013 significantly insulates results from commodity price volatility
*	$305 MM - despite low price environment and JV asset contribution maintained levels
6	Diversify and increase projects:
*	Net headcount flat at 326 full-time employees, yet created business development department; added SVP and support staff

See Slide 2 regarding Forward Looking Statements

What to Expect for 2010?

•Allocation of drilling capital to all of PDC’s major core
basins

•Potential expansion of drilling in Wattenberg Field and
Piceance Basin

•Potential repurchase of Limited Partner’s interest in
Partnerships

•Pursuit of small asset acquisitions

•Continue focus on increase in shareholder value

9

See Slide 2 regarding Forward Looking Statements

2010 Metric Targets

Metric	Target Range
Adjusted Cash Flow per Share	$7.25 - $8.45
Capital Efficiency	225% - 300%
TTM Operating and G&A Expense per Mcfe	$2.40 - $3.30
Reserve Replacement	200% - 300%
Production Volumes	33,900 - 39,300

10

See Slide 2 regarding Forward Looking Statements

11

For Debt/Market Cap:

* Price, market capitalization as of 3/4/2010.

(1) Per EnerCom, at 12/31/09.

See Slide 2 regarding Forward Looking Statements

Bart Brookman

SVP - Exploration and Production

12

See Slide 2 regarding Forward Looking Statements

2010 Operational Themes

•CAPEX investment will be reestablished in all major
operating basins; returns forecasted to exceed minimum
return thresholds

•Continued focus on achieving operational efficiencies
and reserve enhancements

•Continued focus on production and PDP optimization

•Determination of a prospective Midstream strategy for
each operating area

•Investment and development of Marcellus acreage
through PDC Mountaineer JV

•Approved exploration projects should provide opportunity
to enhance long-term reserve / production potential

13

See Slide 2 regarding Forward Looking Statements

Core Operating Regions

See Slide 2 regarding Forward Looking Statements

2009 Proved Reserves: 641 Bcfe

2009 Production:            37.8 Bcfe  

2010E Production:          31.0 Bcfe

Rocky Mountains

2009 Proved Reserves: 15 Bcfe

2009 Production:            1.4 Bcfe

2010E Production:          1.3 Bcfe

Michigan Basin

2009 Proved Reserves*:   61 Bcfe

2009 Production:               4.1 Bcfe

2010E Production:             3.4 Bcfe

Appalachian Basin

2009 Proved Reserves

717 Bcfe

Appalachian Basin (9%)*

2009 Production

43.3 Bcfe

Michigan
Basin (3%)

Appalachian Basin (9%)

Rocky
Mountains (87%)

*Appalachian Basin includes 100% of PDC Mountaineer, LLC Reserves at Year-End 2009

14

See Slide 2 regarding Forward Looking Statements

Operating Highlights

2009 Drilling Activity

Gross Wells Drilled 100

Net Wells Drilled 79

Net Development71

Net Exploratory8

Planned 2010 Drilling Activity

Gross Wells 252

Net Wells 204

15

•2009 Production increased
12% to 43.3 Bcfe

•2009 Proved Reserves
decreased 5% to 717 Bcfe

Annual Drilling Activity

2010E

See Slide 2 regarding Forward Looking Statements

Net Production

•PartnershipBuybacks

•Aceite
Acquisition

•Castle
Acquisition

•End of
Partnership
Drilling

•65%
CAPEX
Reduction

•Marcellus
Joint
Venture

•Significant
Increase in
Drilling
Activity

•Piceance
Divestiture

•EXCO
Acquisition

•Unioil
Acquisition

**2004-09 CAGR of 27%**

16

See Slide 2 regarding Forward Looking Statements

17

Quarterly Net Production

2010 Production Guidance

E

See Slide 2 regarding Forward Looking Statements

Production by Area
(Bcfe)

18

Area	2008	2009	% Increase/ (Decrease)	2010E	% Increase/ (Decrease)
Wattenberg	15.4	16.3	6%	14.1	-13%
Piceance	12.5	15.8	26%	11.9	-25%
NECO	5.0	5.3	6%	4.6	-11%
Appalachia	3.9	4.1	5%	3.4	-17%
Other (ND, TX, WY, MI)	1.9	1.8	5%	1.7	-11%
TOTAL	38.7	43.3	12%	35.7	-18%

Bcfe = One billion cubic feet of natural gas equivalent.

See Slide 2 regarding Forward Looking Statements

Well Summary

19

Operating Area	YE2009 Gross Wells	2009 Gross Wells Drilled	2009 Net Wells Drilled	2010 Gross Wells Planned
Wattenberg	1,484	82	65	180
Piceance	306	1	1	21
NECO	717	8	4.5	25
Appalachia	2,251	8	8	26
Michigan	215	0	0	0
Other	17	1	0.5	4
Total	4,990	100	79	252

See Slide 2 regarding Forward Looking Statements

Total Proved Reserves
by Area at Year-End 2009

717 Bcfe

See Slide 2 regarding Forward Looking Statements

Reserve Summary
at Year-End 2009

753 Bcfe

Revisions &
Pricing
Adjustments

Drops /
Scheduling
Adjustments

Production

Adds /
Extensions

Revisions, LOE
Improvements,
Operations

See Slide 2 regarding Forward Looking Statements

22

Proved Reserves
at Year-End 2009

•Proved reserves declined 5% from 2008 levels

•PDP declined 6% from 2008, however, 58% of production was replaced despite a
significant reduction in CAPEX for 2009

•New SEC valuation methodology for commodity pricing and 5-year PUD booking
rules impacted 2009 year-end reserves

•New SEC methodology for resource bookings, cost improvements, and operational
results provided growth in certain areas

•Conservative booking of Marcellus reserves

(1) Independent reserve engineer’s estimates.

  Summary Reserve Data  

Proved Reserves (Bcfe)(1)

  Area

2008 YE

2009 YE

% Growth

% Developed

% Natural Gas

Rockies

620

641

3%

35%

83%

Appalachia

113

61

(46%)

90%

100%

Michigan

20

15

(25%)

100%

98%

Total

753

717

(5%)

41%

85%

See Slide 2 regarding Forward Looking Statements

Proved Reserves
by Area at Year-End 2009 (Bcfe)

23

Area	2008	2009	2008	2009	2008	2009	2008	2009
Wattenberg	79	89	1	1	119	140	199	230
Piceance	107	103	6	0	260	275	373	378
NECO	40	31	3	0	5	0	48	31
Appalachia	53	42	21	13	39	6	113	61
Other	20	16	0	1	0	0	20	17
TOTAL	299	281	31	15	423	421	753	717*
% Total Proved	40%	39%	4%	2%	56%	59%	100%	100%

Bcfe = One billion cubic feet of natural gas equivalent.

* Using year-end spot pricing methodology, as was used at year-end 2008, total reported reserves would have been 811 Bcfe.

See Slide 2 regarding Forward Looking Statements

3P Reserves(1)
by Area at Year-End 2009 (Bcfe)

24

					Proved + Probable + Possible
Area	2008	2009	2008	2009	2008	2009
Wattenberg	199	230	236	305	241	332
Piceance	373	378	486	449	538	465
NECO	48	31	57	31	74	31
Appalachia	113	61	126	113	136	145
Other	20	17	20	17	20	17
TOTAL	753	717	925	915	1,009	990

Bcfe = One billion cubic feet of natural gas equivalent.

(1) 3P estimates are non-SEC.

See Slide 2 regarding Forward Looking Statements

25

Lifting Cost Improvements

	Twelve Months Ended December 31, 2008	TwelveMonths Ended December 31, 2009	2009 Improvement %
Direct Well Expenses	$0.84	$0.59	30%
Indirect Well Expenses	$0.23	$0.24	-4%
Lifting Cost ($ per Mcfe)	$1.07	$0.83	22%

See Slide 2 regarding Forward Looking Statements

Acreage Inventory

Area	Lease Gross Acres	PDC Net Acres	Net Developed Acres	Net Undeveloped Acres	State
Wattenberg	72,200	64,900	45,500	19,400	Colorado
Piceance	8,000	8,000	2,700	5,300	Colorado
NECO	127,100	105,100	19,600	85,500	Colorado/Kansas
Appalachia	120,900	117,600	106,800	10,800	WV / PA
Marcellus Shale*	57,500	57,500	2,400	55,100	WV / PA
Michigan	26,800	23,300	14,800	8,500	Michigan
New York	18,700	15,900	0	15,900	New York
North Dakota	66,800	30,200	4,600	25,600	North Dakota
Wyoming	19,500	19,300	100	19,200	Wyoming
Texas Barnett	8,900	6,000	400	5,600	Texas
Total	468,900	390,300	194,500	195,800

26

* A subset of Appalachian Basin Shallow Devonian - Net and gross acres included in Appalachia totals.

See Slide 2 regarding Forward Looking Statements

Net Capital Budget

27

(1) Subject to bi-annual approval by PDC Mountaineer Board of Directors.2010 CAPEX funded by PDC Mountaineer
partner, PDC has no capital investment obligation.

See Slide 2 regarding Forward Looking Statements

28

Marcellus

•16 Verticals

•10 Horizontals

Shallow Devonian

•50 Recompletes

•29 Workovers

NECO

•25 New Drills

•50 Workovers

Wattenberg

•180 New Drills

-138 Operated New Drills

-42 Non-Op New Drills

•12 Refracs/Recompletes

Piceance

•21 New Drills

-11 Mesa

-10 Valley

See Slide 2 regarding Forward Looking Statements

PDC has over 2,200 identified
projects in Inventory

See Slide 2 regarding Forward Looking Statements

Development CAPEX Summary

29

1.December Price Strip.

2.Adjusted For Net 2010-11 Capital Carryout of ($5MM).

Anticipated IRR for 184.8 CAPEX is 32%.

See Slide 2 regarding Forward Looking Statements

Operations Forecast Comparison

	2009	2010E	% Change
Total Net Production (Bcfe)(1)	43.3	35.7	-18%
Gross Exit Rate (MMcfe/d)	187	185	-1%
Net Exit Rate (MMcfe/d)	107	106	-1%
Net Development Capital (MM$)	$79	$127	61%
Gross Number of Drilling Projects	100	252	152%
Gross Number of Other Projects	38	62	63%

30

(1) 12% production decrease excluding impact of PDC Mountaineer JV.

See Slide 2 regarding Forward Looking Statements

31

Wattenberg Field

See Slide 2 regarding Forward Looking Statements

Wattenberg Field

•Gross operated wells1,410

•Undeveloped acreage19,400

•Undeveloped, gross, locations1,533

•831 total net PDC

-PUD373

-Probable315

-Possible141

-Subeconomic Resources
2

•Other considerations:

•On March 5thacquired 47 wells producing 1MMcfe/d
from Suncor through preferential right.

•Technical improvements on fracs continue to enhance
project production performance.

•DCP recently announced major pipeline expansion.

32

See Slide 2 regarding Forward Looking Statements

Key Economic Parameters:
Wattenberg Field - Codell/Niobrara

•Reserves per Well*

0.287 Bcfe

•IP Rate*

113 Mcf/d, 24 Bbl/d

•Gross Cost per Well

$575K D&C

•Average PUD Working Interest

77%

•Net Revenue Interest

61%

•Operation Cost/Well/Month

$791

•Well Life*

34 Years

33

*NE Codell/Niobrara type curve.

See Slide 2 regarding Forward Looking Statements

34

	2009	2010E	% Change
Total Net Production (Bcfe)	16.3	14.1	-13%
Net Exit Rate (MMcfe/d)	41.2	42.2	2%
Developmental Capital (MM$)	48.7	$87.6	80%
Drilling Projects, Gross (Net)	82 (65)	180 (143)	120% (120%)
Other Projects, Gross (Net)	10 (9)	12 (11.5)	20% (28%)

2010 Planned Development:
Wattenberg Field

See Slide 2 regarding Forward Looking Statements

35

Piceance Basin

See Slide 2 regarding Forward Looking Statements

Piceance Basin

•Gross operated wells288

•Undeveloped acreage 5,300

•Undeveloped, gross, 10 acre locations433

•362 total net PDC

•Number of net remaining locations

-PUD243

-Probable63

-Possible 14

-Subeconomic Resources
42

•Other considerations:

•Anticipate dramatic improvements in 2010 lifting cost
due to water disposal projects.

•Reserve upside due to mega fracs under technical
review.

•Deep test of Niobrara/Mancos underway.

36

See Slide 2 regarding Forward Looking Statements

Key Economic Parameters:
Piceance Basin

•Reserves per Well*

1.483 Bcfe

•IP Rate*

1082 Mcfe/d

•Gross Cost per Well

$1.8 MM

•Average PUD Working Interest

84%

•Net Revenue Interest

71%

•Operation Cost/Well/Month

$3,500

•Well Life*

43 Years

*Mesa type curve.

See Slide 2 regarding Forward Looking Statements

38

	2009	2010E	% Change
Total Net Production (Bcfe)	15.8	11.9	-25%
Net Exit Rate (MMcfe/d)	34.1	34.5	1%
Developmental Capital (MM$)	20.7	$34.8	68%
Drilling Projects, Gross (Net)	1 (1)	21 (21)	2,100%

2010 Planned Development:
Piceance Basin

See Slide 2 regarding Forward Looking Statements

39

NECO Area

See Slide 2 regarding Forward Looking Statements

40

NECO Area

•Gross operated wells at year end489

•Undeveloped acreage85,500

•Undeveloped locations 319

•Number of remaining net locations 297

•PUD0

•Probable0

•Possible0

•Subeconomic Resources
297

•Other considerations:

•Recent exploration oil test in Lansing Kansas City
formation a success.

•2nd test planned in 1st half 2010.

See Slide 2 regarding Forward Looking Statements

Key Economic Parameters:
NECO Area

•Reserves per Well*

0.188 Bcfe

•IP Rate*

86 Mcf/d

•Gross Cost per Well

$189K

•Average PUD Working Interest

91%

•Net Revenue Interest

76%

•Operation Cost Well/Month

$782

•Well Life*

25 Years

41

*Shallow Niobrara type curve.

See Slide 2 regarding Forward Looking Statements

42

	2009	2010E	% Change
Total Net Production (Bcfe)	5.3	4.7	-11%
Net Exit Rate (MMcfe/d)	12.9	12.6	-5%
Developmental Capital (MM$)	2.6	$4.4	69%
Drilling Projects, Gross (Net)	8 (4.5)	25 (24.5)	225% (444%)

2010 Planned Development:
NECO Area

See Slide 2 regarding Forward Looking Statements

PDC Mountaineer Joint Venture

43

PDC Mountaineer, LLC

•Appalachian JV Effective Oct 1, 2009

•Strategic Joint Venture with Lime Rock Partners
Formed to Develop our Marcellus and Shallow
Devonian Acreage

•Allows for a More Aggressive Development of the Asset

•Provides PDC with Cash

•Gives PDC More Financial Flexibility in Developing
Other Assets and in the A&D Markets

•Operations Funded by Lime Rock until 50/50 parity is
Reached

•PDC ownership % Goes Down as More Capital is
Contributed by Lime Rock

•Managed by a joint board of PDC and Lime Rock

+

=

Marcellus & Devonian Shallow

(1)2010 CAPEX to befunded by PDC Mountaineer partner, PDC has no capital investment obligation.

See Slide 2 regarding Forward Looking Statements

44

Appalachian Operating Area

See Slide 2 regarding Forward Looking Statements

45

PDC Mountaineer JV Shallow Devonian

•Gross operated wells at year end 2,125

•Undeveloped acreage10,800

•Undeveloped locations569

•Number ofremaining locations

•PUD32

•Probable 82

•Possible37

•Subeconomic Resources
418

See Slide 2 regarding Forward Looking Statements

Key Economic Parameters:
Appalachian Basin Upper Devonian

•Reserves per Well*

0.184 Bcfe

•IP Rate*

115 Mcf/d

•Gross Cost Per Well

$367K

•Average PUD Working Interest

100%

•Net Revenue Interest

87%

•Operation Cost Well/Month

$302 + compression

•Well Life*

49 Years

46

See Slide 2 regarding Forward Looking Statements

Pennsylvania Acreage Map

15,219 Net Marcellus Rights

42,354 Net Marcellus Rights

West Virginia Acreage Map

Appalachian Basin Acreage -

Marcellus Shale

	HBP NET ACRES	UNDEVELOPED NET ACRES	TOTAL NET ACRES	AVERAGE NRI
As of 2-22-2010	PA: 9,981 WV: 38,395	PA: 5,238 WV: 3,959	PA: 15,219 WV: 42,354	82.80% 86.70%

47

See Slide 2 regarding Forward Looking Statements

Gas Shale Success Factors	Barnett	Fayetteville	Haynesville	Marcellus	PDC Marcellus Wells
Depth	5,400’ -9,600’	1,200’ - 7,500’	10,000’- 13,000’	2,500’ - 8,500’	7,100’ - 7,650’
Thickness	200’ - 500’	50’ - 200’	200’ - 300’	50’ - 300’	103’ - 240’
TOC (Total Organic Carbon)	2% - 7%	2% - 5%	≈ 4%	2% - 14%	1% - 12%
Maturity (%Ro)	1.1% - 1.7%	1.2% - 3.0%	2.2% - 3.0%	0.4% - 3.5%	1.5% - 2.5%+
Avg. Log Porosity	7%	4% - 12%	10%	5.5% - 7.5%	2% - 16%
Water Saturation	25% - 35%	15% - 50%	15% - 20%	2% - 35%	5% - 33%
Pressure (psi/ft)	0.52	0.435	0.9	0.4 -0.7	0.55-0.60

Shale Gas Play Comparisons

48

See Slide 2 regarding Forward Looking Statements

West Virginia Vertical

Marcellus Results

(1) Approx. Recovery Factor based on 20-40 acre drainage

•7 Vertical Marcellus wells in Harrison, Taylor, and
Barbour counties

–IP :200 - 480 Mcf/day

–Reserves:0.2 - 0.55 Bcfe

–30 - 60 Bcf/section

–10%-20% approx. recovery factors(1)

–Pressure:0.55 -0.60 psi/ft

–Thickness:103’ - 240’

–5 single-stage frac’d wells and 2 dual-stage frac’d
wells

49

See Slide 2 regarding Forward Looking Statements

(1)Economics run using 12/31/209 NYMEX strip prices effective 1/1/2010

PDC Horizontal Marcellus

Type Well Economics

Vertical

Horizontal

50

Gross EUR (Bcfe) = .435

See Slide 2 regarding Forward Looking Statements

Key Economic Parameters:
Appalachian Basin Marcellus Shale

•Vertical / Horizontal

•Reserves per Well*

–0.435 / 3.0 Bcfe

•IP Rate*

–400 / 2,800Mcf/d

•Gross Cost per Well

–$850K / $3,483K

–100% / 100%

•Net Revenue Interest

–85% / 85%

•Operation Cost Well/Month

–$1000 / $1500 + compression

•Well Life*

–40 / 60 Years

51

See Slide 2 regarding Forward Looking Statements

18

Marcellus Shale 3-D Seismic Shoot

•6,680 acres

•Potential for 30
horizontal locations

3D Seismic

52

See Slide 2 regarding Forward Looking Statements

Vertical vs. Horizontal Results

53

Company	Zone	Vertical IP (MCF/D)	Horizontal IP (MCF/D)	Fold Increase
Newfield	Woodford	238	3816	16
Williams	Caney	33	330	10
XTO	Barnett	600	2500	4
SEECO	Fayetteville	200	1700	8
*Cabot	Marcellus	690	6250	9
PDC	Marcellus	400	Modeled 2800	7

*30 - 60 day production averages; 4 horizontal; 13 vertical wells(4/29/09)

Note: There can be no assurance PDC’s horizontal wells will reflect similar multiples of vertical wells.

53

See Slide 2 regarding Forward Looking Statements

54

	2009 PDC	2010E JV (PDC)	PDC % Change
Total Net Production (Bcfe)	4.1	5.8(3.4)	-20%
Net Exit Rate (MMcfe/d)	11	24(13)	24%
Dev. & Explor. CAPEX (MM$)	$16.2	$58.01(0)	-100%
Drilling Projects, Gross (Net)	9 (8.8)	26 (15)	41%
Other Projects, Gross (Net)	22 (21.6)	50 (29)	26%

2010 Planned Development:
Appalachian Basin

1.Funded by PDC Mountaineer Partner.

See Slide 2 regarding Forward Looking Statements

2010 Operations Guidance

•Production of 35.7 Bcfe

•CAPEX of $150MM

•PDC Mountaineer CAPEX of $64.5MM to be funded
by JV partner

•252 developmental wells

•First horizontal Marcellus well to spud in early March

•Production expected to increase in Q4 to YE2009
levels

•Financial flexibility to expand core developmental
drilling, re-purchase partnerships, or acquire
properties

55

See Slide 2 regarding Forward Looking Statements

Takeaways

•PDC has built an exceptional technical/geoscience team over the past
several years

–Positioned for increased activity

–Focused on technical innovation

–Continuation of ongoing exploration efforts

•Current assets provide company flexibility to grow organically

–Large inventory of projects

–Value add projects exist in all operating basins

•Marcellus provides large production / reserve upside

–Plan to accelerate development in 2010

–1st horizontal production anticipated in the first half of 2010

–Midstream strategy to be announced mid 2010

•Company is well positioned for reserve growth over next several years

–Continued proved enhancements in existing properties

–Pricing improvements

–Marcellus development

–Acquisitions

56

See Slide 2 regarding Forward Looking Statements

Gysle Shellum

Chief Financial Officer

57

See Slide 2 regarding Forward Looking Statements

Summary Financial Results

	Year Ended December 31,
($ in millions except per share data)	2009	2008
Income (loss) from operations	($90.0)	$195.7
Net Income (loss) attributable to shareholders	($79.3)	$113.3
Diluted earnings (loss) per share attributable to shareholders	($4.82)	$7.63

	Year Ended December 31,
($ in millions except per share data)	2009	2008
Adjusted net income (loss) (1)	($2.9)	$39.7
Adjusted earnings (loss) per share (1)	($0.18)	$2.67

58

(1) Excludes unrealized derivative gains & losses.

See Slide 2 regarding Forward Looking Statements

Summary Financial Results

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

(2) See appendix for GAAP reconciliation of Adjusted Cash Flow and Adjusted EBITDA, respectively.

(3) Includes non-recurring items related to the Q4 joint venture, EVP separation agreement, and corporate office relocation costs.

59

	Year Ended
	December 31,
($ in millions except per share data)	2009	2008
O&G Revenues	$179.1	$321.9
O&G Production & Well Operations Costs	$64.7	$79.4
O&G Operating Margin(1)	$114.4	$242.5
Adjusted cash flow from operations(2)	$170.2	$199.9
Adjusted cash flow from operations (per share) (2)	$10.35	$13.46
Adjusted EBITDA(2)	$159.7	$189.4
DD&A	$131.0	$104.6
G&A(3)	$54.0	$37.7

See Slide 2 regarding Forward Looking Statements

60

Adjusted Cash Flow from Operations

2008

2007

2009

•Adjusted cash flow from
operations represents cash flow
from operations before normal
working capital changes

•Incorporates impact of hedging
gains

•CAPEX reduced 66% in 2009

See Slide 2 regarding Forward Looking Statements

Financial Summary Results

61

1)Other income: income from gas marketing activities, well ops and pipeline income

	2009 Actual	2009 Guidance
		Low	High
($ in Millions except per share data)
Total O&G Revenue	$286	$259	$286
Other Income(1)	14	12	12
Total Revenue	300	272	299
O&G Production & Well Ops Cost	65	70	73
G&A	54	42	45
Adjusted EBITDAX	181	160	181
Exploration Expense	23	14	14
DD&A	131	121	121
Net Interest Expense	37	33	33
Taxes	(7)	(3)	5
Adjusted Net Income / (Loss)	($3)	($5)	$8
Stock-based Compensation	6	6	6
DD&A	131	121	121
Exploratory / Dry Hole Cost	1	5	5
Other	35	(20)	(19)
Adjusted Cash Flows from Operations	$170	$107	$121
CFFO/Share	$10.35	$7.23	$8.18
EPS	($0.18)	($0.33)	$0.57

See Slide 2 regarding Forward Looking Statements

62

•$305 million revolver matures
in May 2012

•Maturity schedule reflects:

–Mitigation of liquidity risk

–Diversification of funding
sources

•As of December 31, 2009:

–$80 MM drawn balance

–$18.7 MM undrawn L.O.C

–$31.9 MM cash balance

–$238.2 MM available liquidity

•Borrowing base redetermination
will occur in May 2010

Debt Maturity Schedule

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

$80

$203

$305

See Slide 2 regarding Forward Looking Statements

(as of December 31, 2009)

See Slide 2 regarding Forward Looking Statements

Energy Market Exposure

Percentage of Mcfe Sold by Market
(as of December 31, 2009)

See Slide 2 regarding Forward Looking Statements

63

See Slide 2 regarding Forward Looking Statements

2009 Summary - Oil and Gas Hedges

(1)Based on 12/31/09 PDP curve (i.e., may represent 50% or less of actual production for the future year)

(2)Based on forward pricing curves as of 3/1/2010

(3)Blended price for forecasted production at hedged and at forward prices

Continued focus on hedging enabled the Company to protect its cash flow, capital
programs, and organic drilling economics from commodity price fluctuations

•Realized gains of $108MM

•Substantial hedge positions through 2013 via swaps (2010-2011) and collars (2012-2013) at solid
historical commodity price levels should continue to provide on-going protection

•Price sensitivity of 2010’s budget has been significantly mitigated.Variation of $1.00/Mcfe for natural
gas and $10.00/bbl for oil results in less than a 5% variation in cash flow from operations

64

As of March 1, 2010	2010	2011	2012	2013
Weighted Average Hedge Price (Mcfe) (1)
With Floors	$7.60	$6.87	$6.39	$6.39
With Ceilings	$8.43	$7.76	$7.97	$8.21
% of Forecasted Production(1)	89%	74%	66%	65%
Weighted Avg Forward Price(2)	$6.22	$6.78	$7.04	$7.17
Weighted Avg Price of Forecasted Production(3)	$7.45	$6.85	$6.61	$6.66

See Slide 2 regarding Forward Looking Statements

“E&P’s may have waited too long to hedge.”

Credit Suisse analyst’s quotes from Platt’s Gas Daily, February 24,
2010:

•“With 2011 gas future curve now below $6/MMBtu and service costs
on the rise, the hedging window for US gas producers may be
closing.”

•“Providers appeared to have been holding out for hedging
opportunities closer to $7/MMBtu and, as a result, have only hedged
20% of their North American gas volumes for 2011 - at an average
floor price of $6.52/MMBtu.”

•“Simply put, more dollars and more volumes need to be protected
heading into 2011.”

•“… they may have waited too long… last week the 2011 gas curve
fell below $6/MMBtu for the first time.”

•“A margin squeeze could be in store… could continue to narrow.”

65

See Slide 2 regarding Forward Looking Statements

66

Average Annual Costs Related
to Oil and Gas Drilling

	Year Ended December 31,
(per Mcfe)	2009	2008
Average lifting costs (1)	$0.83	$1.07
DD&A (O&G properties only)	$2.83	$2.51

(1)Lifting costs represent natural gas and oil lease operating expenses, exclusive of production taxes, on a per unit basis.

See Slide 2 regarding Forward Looking Statements

67

2009 Metrics

Natural Gas Equivalent(1)

Natural Gas Equivalent(1)

Oil & Gas Production and Well
Operations Costs(2)

(Bcfe)

($/Mcfe)

($MM)

Capital Spending

• Increased production by 12% and reduced L.O.E $/Mcfe by just under 30%.

• Improved L.O.E $/Mcfe should be sustainable beyond 2009 and should improve incremental capital investment
returns.

(1) Average Sales Price excluding gain/loss on derivatives

(2) Includes direct and indirect well expenses, production taxes, and overhead and other production expenses.

See Slide 2 regarding Forward Looking Statements

2009 Credit Ratios

Total Debt / Capital Base

(%)

(1) EBITDAX: Earnings before Interest, Taxes, Depreciation, Depletion and Amortization , unrealized hedge gains/losses, and Exploration Expense.

EBITDAX (1)/ Interest, net (TTM)

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

•Reduced capital spending and operating costs improvements resulted in substantial available liquidity and
improvement in leverage and coverage measures

•~$50MM equity raise, and ~$160MM PDC and Lime Rock Partners joint venture to develop Marcellus Shale and
Shallow Devonian assets, reflected the company’s ability to access alternative capital markets, and improve
liquidity, leverage and coverage measures

* Liquidity excludes $18.7 million L.C.

68

$305

$203

x

x

x

$80

See Slide 2 regarding Forward Looking Statements

2010 Guidance

69

See Slide 2 regarding Forward Looking Statements

2010 Guidance

70

•Reserves, production and capital expenditures
per the internal operational plan

•Production taxes and direct operating costs
determined on a field basis

•General and administrative costs slightly
improved versus 2009 after adjustment for non
-recurring items

See Slide 2 regarding Forward Looking Statements

71

•DD&A based on a by-field analysis

•2010 commodity pricing based on high and low
pricing scenarios with differentials on a field basis

•Revolver interest rate at pricing grid plus LIBOR
spread

2010 Guidance

See Slide 2 regarding Forward Looking Statements

Income Statement and Cash Flow Analysis

72

1)Other income: income from gas marketing activities, well ops and pipeline income

•Despite 17.6% reduction in
production in 2010 versus 2009, the
Company budgeted 2010 net income
versus a loss in 2009 and budgeted
strong year over year adjusted cash
flow from operations.

•Year-over-year change in net income
and cash flow from operations were
primarily due to improved:

•Price realizations

•Capital efficiency

•G&A expense - non-
recurrence of 2009 one time
items.

($ in MM except per share data)	2009 Actual	2010 Low	2010 High
Bcfe	43.3	35.7	35.7
Total O&G Revenue	$286	$239	$258
Other Income(1)	14	12	12
Total Revenue	$300	$251	$270
O&G Production & Well Ops Cost	65	59	63
G&A Expense	54	43	39
Adjusted EBITDAX	$181	$150	$169
Exploration Expense/Dry Hole Cost	23	9	8
DD&A	131	116	116
Net Interest Expense	37	34	34
Taxes/ (Benefit)	(7)	(4)	4
Adjusted Net Income (loss)	($3)	($6)	$7
Stock-based Compensation	6	7	5
DD&A	131	116	116
Exploratory/Dry Hole Cost	1	2	1
Other	35	28	28
Adjusted Cash Flows From Operations	$170	$148	$158
Weighted # of share outstanding	16,448	19,300	19,300
CFFO/Share	$10.35	$7.67	$8.17
EPS	($0.18)	($0.32)	$0.34

See Slide 2 regarding Forward Looking Statements

73

Costs Metrics

(1) Lifting costs represent natural gas and oil lease operating expenses, exclusive of production taxes, on a per unit basis.

(per Mcfe)	2010E	2009	2008
Average lifting costs(1)	$0.95	$0.83	$1.07
DD&A (O&G properties only)	$2.98	$2.83	$2.51

See Slide 2 regarding Forward Looking Statements

2010 Debt & Liquidity Analysis

74

1)Includes $9MM of PDC share of J.V cash flow in J.V oil & gas properties in 2010

2)Other includes $9MM payment of debt issuance costs in 2009

	31-Dec	Annual
	2009	2010
($ in Millions)
Beginning Debt ($MM) (Credit Facility)	$195	$80
- Adjusted Cash Flow From Ops	(170)	(148) - (158)
+/- Proceeds From Equity Offering & JV	(103)	-
+ Capital Expenditures(1)	143	159
+/- Change in Working Capital	26	-
+/- Net Decrease in Cash	(19)	-
+/- Other / Deferred Tax(2)	9	-
Ending Debt Balance	$80	$91 - $81
Current Borrowing Base	$305	$305
Standby L.O.C	19	19
Available Borrowing Base	206	195 - 205
Cash Available	32	32
Total Liquidity	$238	$227 - $237

See Slide 2 regarding Forward Looking Statements

Weighted Average Cost of Capital
(“WACC”) Analysis

•Year-over-year WACC improvement of 80 basis points due primarily to lower after tax cost of
debt offset by higher equity proportion of capital structure.

75

	12/31/2008	12/31/2009
Cost of Equity	15.2%	14.4%
Equity %	49.0%	61.0%
After Tax Cost of Debt	9.5%	7.0%
Debt %	51.0%	39.0%
WACC	12.3%	11.5%
PDC 12% Notes due 2018 yield	19.7%	10.7%

See Slide 2 regarding Forward Looking Statements

Lance Lauck

SVP - Business Development

76

See Slide 2 regarding Forward Looking Statements

IncreasingValue in 2010 and Beyond

•Additional Organic Drilling - Possibly beginning 2nd half 2010

-Ramp up in Piceance and Wattenberg

-Focus on enhancing Piceance economics

•Marcellus JV - drilling 26 horizontal and vertical wells in 2010

-Large operator in WV achieved reserves of 3.6 Bcfe per
horizontal well near PDC acreage

-Over 150 Marcellus permits issued in WV counties surrounding
PDC position

•Partnership Purchases - Three Year Plan

-Non-operated interests in certain existing PDC operated
Wattenberg and Piceance Assets

•Acquisitions - Asset and Small Corporate

-Anticipate substantial A&D deal flow in 2010

•Exploration - Moderate Risk Resource Plays

-Niobrara Wattenberg; Mancos Shale Piceance; Bakken; Others

77

See Slide 2 regarding Forward Looking Statements

Partnership Purchases:
Three-Year Plan

•Limited Partners’ non-operated interest is typically at 60-80% of
certain PDC operated wells (Rockies principally)

•28 Limited Partnerships have net reserves of approximately 125
Bcfe and net production of approximately 25 MMcfe/d owned by the
Limited Partners

•PDC strategy to purchase Limited Partners’ interest over next three
years

–Production and reserve adds in existing operated core acreage

–Reduction/optimization of internal G&A costs

–9 SEC compliant partnerships represent over 60% of net reserves and over
75% of total cash flows owned by the Limited Partners

–Elimination of Limited Partnerships through repurchases would finalize PDC’s
transition to a traditionally capitalized E&P company

78

See Slide 2 regarding Forward Looking Statements

ACQUISITION POSITIONING

•Staff of five employees fully dedicated to acquisitions

•Liquidity increased to ~$250 million

•Focus on core areas and new areas with similar characteristics

•Completing basin study to target new value-adding areas

•Pursuing a pro-active approach

•Capable of deal sizes of $200 - $400 million

•Acquisitions metrics consistent with corporate goals

•Acquisitions to be executed in conjunction with five-year
business plan

•Support of PDC Board of Directors

79

See Slide 2 regarding Forward Looking Statements

ACQUISITION STRATEGY

Focus Areas:

•Core Area Acquisitions - Rockies and Appalachia / Marcellus

–Current production with growth upside - close to existing PDC operations

•New Basin Acquisitions - Align with PDC Strengths

–Basin study results (Permian, Mid Continent, ETX/NLA)

–Scale and repeatability

–Primary production; not focused on EOR, GOM, Gulf Coast or International

•Joint Ventures - Drill to Earn

–Conventional assets or new shale plays

–Win-Win approach

–100+ drilling opportunities, target up to $3 million / well net D&C costs

Asset Type:

•PDP 25% to 50%, a significant future growth through drilling

•Focused on conventional gas and oil plays

•Add at least one additional shale resource play

Asset Mix:

•Prefer oilier plays, however, economics will be the determiner

80

See Slide 2 regarding Forward Looking Statements

ACQUISITION APPROACH

Pro-Actively Contact Companies

•Public E&P companies

•Private E&P companies

•Private equity sponsors

Marketed Deals

•Investment banks

•A&D advisors

81

See Slide 2 regarding Forward Looking Statements

SOURCE OF ACQUISITIONS

•Companies selling conventional assets

–Transforming portfolios to pure shale / resource growth

•Follow-on divestitures

–Post corporate mergers or large asset acquisitions

•Super major / large cap portfolio cleanup

•Companies with high debt levels

–Large acreage positions / limited capital to develop

•Companies allocating capital to other areas

82

See Slide 2 regarding Forward Looking Statements

•Strong Focus on creating Shareholder value

•Strong core asset base with improved drilling economics

•Marcellus Shale JV with Lime Rock Partners provides potential
catalyst for strong production and cash flow growth

•Evaluating potential acquisition, joint venture, and exploration
opportunities which could provide value-added growth

•Strong balance sheet with liquidity of ~$250 million

•Experienced and highly effective management team

•PDC is undervalued and poised for growth

Summary

83

See Slide 2 regarding Forward Looking Statements

A P P E N D I X

84

See Slide 2 regarding Forward Looking Statements

Adjusted Net Income Reconciliation

85

(1) Includes natural gas marketing activities.

	Year Ended
	December 31,
($ in millions)	2009	2008
Net Income (loss) attributable to shareholders	($79.3)	$113.3
Unrealized loss (gain) on derivatives, net (1)	116.6	(117.5)
Provision for underpayment of gas sales	2.7	4.0
Tax effect of above adjustment	(43.0)	39.9
Adjusted Net Income (loss) attributable to shareholders	($2.9)	$39.7
Weighted average diluted shares outstanding	16,448	14,848
Adjusted diluted earnings (loss) per share	($0.18)	$2.67

See Slide 2 regarding Forward Looking Statements

Adjusted Cash Flow Reconciliation

86

	Year Ended
	December 31,
($ in millions)	2009	2008
Net Cash provided by operating activities	$143.9	$139.1
Changes in assets and liabilities related to operations	26.3	60.8
Adjusted cash flow from operations	$170.2	$199.9
Weighted average diluted shares outstanding	16,448	14,848
Adjusted cash flow per share	$10.35	$13.46

See Slide 2 regarding Forward Looking Statements

Adjusted EBITDA Reconciliation

(1) Includes natural gas marketing activities.

87

	Year Ended
	December 31,
($ in millions)	2009	2008
Net Income (loss) attributable to shareholders	($79.3)	$113.3
Unrealized loss (gain) on derivatives, net (1)	116.6	(117.5)
Interest, net	37.0	27.5
Income taxes expense (benefit)	(45.6)	61.5
Depreciation, depletion & amortization	131.0	104.6
Adjusted EBITDA	$159.7	$189.4
Weighted average diluted shares outstanding	16,448	14,848
Adjusted EBITDA per share	$9.71	$12.76

NASDAQ:PETD

PETROLEUM DEVELOPMENT
CORPORATION

Analyst Day

March 12, 2010