NASDAQ:PETD
 PETROLEUM DEVELOPMENT
CORPORATION
 Investor Meetings
 June 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 proved reserves, probable reserves and
possible reserves.  SEC regulations define “proved reserves” as those quantities of oil or gas which, by analysis of geosciences
and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known
reservoirs under existing economic conditions, operating methods and government regulations; “probable reserves” as
unproved reserves which, together with proved reserves, are as likely as not to be recovered; and “possible reserves” as
unproved reserves which are less certain to be recovered 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
 Table of Contents
 •  PDC Summary
 •  PDC 2010 Budget & OperationalGuidance
 •  Recent Operational / TransactionalUpdate
 •  PDC First Quarter 2010 Results
 •  Appendix
 3





See Slide 2 regarding Forward Looking Statements
 PDC SUMMARY
 4





See Slide 2 regarding Forward Looking Statements
 Reasons to Invest in PDC
 •  Long term track record of operational excellence
 •  Diversified operating basins with low risk predictable growth (over2,200 projects in inventory)
 •  Emerging opportunity in the Marcellus Shale
 •  Strong balance sheet with capital available for value addedacquisitions, joint ventures, exploration and partnershiprepurchases
 •  Trade at discount to peers on operational and financial metrics
 •  Strong hedge positions that protect cash flow
 •  Company transitioning from a Partnership company to a moretraditional E&P company
 5





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 06/09 to 06/10
 •  Petroleum Development Corporation is anindependent oil and natural gas companywith operations primarily in the RockyMountain region, Appalachian Basin andMichigan Basin
 •  PDC was founded in 1969 in Bridgeport, WVand is now headquartered in Denver, CO
 Enterprise Value
 Capitalization
 Corporate Profile
 6
 03/31/2009
03/31/2010Share Price (06/09 and 06/10)
$18.11
$21.15Diluted Share Outstanding(MM)
14.8
19.3Market Capitalization ($MM)
$268
$408Net debt total
382
233Minority Interest
1
-Enterprise Value
$650
$64152-Week High ($/share)(3)
$74.08
$26.2152-Week Low ($/share) (3)
$9.70
$12.88 Corporate Summary
 03/31/2009
03/31/2010Net Debt Total
$382
$233Common Equity
507
515Minority Interest (1)
1
-Total Capitalization ($MM)
$890
$749Debt Ratios:Debt/EBITDAX (LTM) (2)
1.56x
1.33xSenior Debt/EBITDAX (LTM) (2)
0.52x
1.02xEBITDAX/ Interest Net (LTM)(2)
12.2x
5.4xDebt/Book Cap
45%
33%





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: 31.2 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: 3.2 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
 7





See Slide 2 regarding Forward Looking Statements
 PDC 2010 BUDGET &
OPERATIONAL GUIDANCE
 8





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
 Capital Budget
 10
 (1)  Subject to bi-annual approval by PDC Mountaineer Board of Directors.2010 CAPEX to be funded by PDC MountaineerJ.V partner.PDChas no capitalinvestmentcommitment for 2010.
 PDC has announced that it will be updating its 2010 budgets, and production estimates at its 7/15/10 Analyst Day.
 ($ in millions)





See Slide 2 regarding Forward Looking Statements
 11
 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
 12
 Quarterly Net Production
 2010 Production Guidance
 E





See Slide 2 regarding Forward Looking Statements
 Piceance Basin at December 31, 2009
 •  Gross operated wells288
 •  Undeveloped acreage 5,300
 •  Undeveloped, gross,10-acre locations433
 •  362 total net PDC
 •  Number of net remaining locations
 - PUD251
 - Probable97
 - Possible 14
 13





See Slide 2 regarding Forward Looking Statements
 Wattenberg Field at December 31, 2009
 
 •  Gross Operated wells1,410
 •  Undeveloped acreage19,400
 •  Undeveloped, gross, locations 1,533
 •  831 total net PDC
 - PUD373
 - Probable316
 - Possible142
 14





See Slide 2 regarding Forward Looking Statements
 PDC Undeveloped Northern
Wattenberg Acreage Area
 EOG Niobrara Horizontal Well plus 39
Drilling Permits Approved & Pending
 PDC Undeveloped Acreage in
Northern Wattenberg Area. Approximately 19,400 acres.
 PDC NECO Area: Niobrara
Biogenic Gas Production
 Pawnee
National
Grasslands
 Pawnee National
Grasslands
 Base Map Source
USGS
 15





See Slide 2 regarding Forward Looking Statements
 Wattenberg Field:
Niobrara Formation Overview
 •  Covers the bulk of the Rocky Mountain region and has been beingdeveloped in the DJ Basin for 30+ years on a veritcal basis withmixed results
 •  Economics improved in the late 90’s with modern hydraulicfracturing technology for vertical development
 •  PDC developed and enhanced a geologic model whichincorporates recent horizontal drilling and production results byEOG Resources and Noble
 •  In Q2 2010 PDC purchased the 5,500 net acre “Krieger Prospect”as an anticipated horizontal project for approximately $1,000 peracre
 •  Spacing request, hearing and permit submittal should occur by theend of July 2010
 •  Expect to spud and achieve first production Q4 2010
 •  Anticipate drilling 4-6 horizontal wells in 2011 and will continue toevaluate farm-in opportunities
 16





See Slide 2 regarding Forward Looking Statements
 PDC Krieger Horizontal
Niobrara Drilling Prospect
 17
 Mapped on maximum Deep Rt in Niobrara B Zone.
 CI = 10 ohm up to 50 ohm.Blue is lowest Rt, red highest Rt.
 All above 50 ohm undifferentiated & shown in red.
 PDC leases in yellow.
 • Mapped on a greater
than 50 ohm Rt fairway
trending northeast from
Wattenberg Field.
 • Existing 3D Seismic helps
confirm wellbore planning.
 • Approximately 5,500
acres net to PDC.
 • Anticipate 12+ horizontal
well locations based on
640 acre spacing.
 • Drill initial well in 4th
Quarter 2010.
 • Vertical Niobrara tests in
the area provide evidence
of oil in the Niobrara
system.
 • Offset full State section
sold for $2,100 per acre in
May 2010 lease sale.





See Slide 2 regarding Forward Looking Statements
 18
 •  $158 MM Appalachian JV formed with Lime Rock Partners(“LRP”) effective 10/1/09; PDC contributed Marcellusacreage and Shallow Devonian production and acreage.
 •  Provided PDC an alternative capital source as LRP fundedPDC $45 MM upon closing, and a commitment to invest thefirst $68.5 MM of capital investment.LRP will become a50% partner once it satisfies it’s capital investmentobligation.
 •  Provides opportunity to accelerate development of the JVassets.
 •  PDC’s ability to raise capital through the JV structure,provides financial flexibility and opportunities to increasedevelopment capital spending and /or pursue acquisitions.
 •  The JV is governed and managed by a Board of Directorscomprised of equal representation by PDC and LRP.PDCwill manage the operations of the JV.
 +
 =
 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
 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
NRIAs 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% 19





See Slide 2 regarding Forward Looking Statements
 Income Statement and
Cash Flow Analysis
 20
 1)  Other income: income from gas marketing activities, well ops and pipeline income
 •  Despite 17.6% reduction inproduction in 2010 versus 2009,the Company budgeted 2010 netincomeversus a loss in 2009 andbudgeted strong year over yearadjusted cash flow fromoperations.
 •  Year-over-year change in netincome and cash flow fromoperations were primarily due toimproved:
 •  Price realizations
 •  Capital efficiency
 •  G&A expense - non-recurrence of 2009 one timeitems.
 ($ in MM except per share data)
2009

Actual
2010

Low
2010

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





See Slide 2 regarding Forward Looking Statements
 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 3/31/2010
 (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 historicalcommodity 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 gasand $10.00/bbl for oil results in less than a 5% variation in cash flow from operations
 21
 As of April 30, 2010

2010
2011
2012
2013Weighted Average Hedge Price (Mcfe) (1)With Floors
$7.44
$6.83
$6.39
$6.37With Ceilings
$8.22
$7.64
$7.96
$8.20% of Forecasted Production(1)
77%
73%
59%
58%Weighted Avg Forward Price(2)
$5.94
$6.76
$7.11
$7.30Weighted Avg Price of Forecasted
Production(3)
$7.10
$6.81
$6.68
$6.77





See Slide 2 regarding Forward Looking Statements
 Quarterly Realized Hedge Price  (as of 4/30/2010)
 22
 •  Weighted average for full-year 2010 is $6.81/Mcfe
 •  Excludes Michigan Divestiture & Permian acquisitions





See Slide 2 regarding Forward Looking Statements
 RECENT OPERATIONAL /
TRANSACTIONAL UPDATE
 23





See Slide 2 regarding Forward Looking Statements
 PDC Wolfberry Acquisition in
West Texas Key Highlights
 24
 •  Acquired producing assets from private seller in WolfberryTrend for $45 mm plus PDC’s producing Michigan Gas assetsvalued by the seller at $30 million
 •  Includes 72 wells on approximately 8,300 net acres
 •  Should add approximately 900 boe/d over the next 12 monthsand strong multi-year production growth is projected
 •  Proved plus probable (2P) reserve add of approximately 8.5million BOE (70% oil)
 •  Effective date of transaction is May 1, 2010 with projectedclosing date of July 30, 2010
 •  Acquisition driven by US onshore basin study findings
 •  Must identify asset team to execute development plan andgrow the position





See Slide 2 regarding Forward Looking Statements
 PDC Wolfberry Acquisition  Wolfberry Acreage Overview with Surrounding Activity
 25
 Key Development Areas
 •  Roy Parks area
 •  Mabee areas
 •  Ratliff area
 •  Other Permian
 Development Potential
 •  120 Wolfberry locations
 •  Anticipate 1 rig program starting 4Q2010
 •  Multiple re-completiontargets
 •  Production optimization
 Key Offset Operators
 •  Concho
 •  Devon
 •  Cabot
 •  Endeavor





See Slide 2 regarding Forward Looking Statements
 Partnership Purchases:
Three-Year Plan
 •  Limited Partners’ non-operated interest is typically 60-80% ofcertain PDC operated wells (Rockies principally)
 •  28 Limited Partnerships have net reserves of approximately 125Bcfe and net production of approximately 25 MMcfe/d owned bythe Limited Partners
 •  PDC strategy to purchase Limited Partners’ interest over nextthree 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 reservesand over 75% of total cash flows owned by the Limited Partners
 –  Elimination of Limited Partnerships through repurchases wouldfinalize PDC’s transition to a traditionally capitalized E&P company
 26





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 perhorizontal well near PDC acreage
 -  Over 150 Marcellus permits issued in WV counties surroundingPDC position
 •  Partnership Purchases - Three Year Plan
 -  Non-operated interests in certain existing PDC operatedWattenberg 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
 27





See Slide 2 regarding Forward Looking Statements
 28
 Peer Group: BBG, BRY, COG, CRZO, GDP, PVA, ROSE





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 potentialcatalyst for strong production and cash flow growth
 •  Evaluating potential acquisition, joint venture, and explorationopportunities 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
 29





See Slide 2 regarding Forward Looking Statements
 PDC FIRST QUARTER
2010 RESULTS
 30





See Slide 2 regarding Forward Looking Statements
 First Quarter 2010 Highlights
 31
 •  Net income of $23.7 million, or $1.23 per diluted share
 •  Gas and oil revenues up 52% over same period 2009 on Q12010 realized prices of $9.20 per Mcfe over Q1 2009 realizedprices of $7.08 per Mcfe
 •  Adjusted cash flow of $49.3 million, or $2.56 per diluted share
 •  Q1 2010 adjusted cash flow up approximately $10 million oversame period 2009 on 20% lower volumes
 •  Production of 9.1 Bcfe, 7% above Q1 guidance of 8.5 Bcfe
 •  Drilled 38.6 net wells vs. 24.9 net wells in Q1 2009
 •  Liquidity improved to $254 million





See Slide 2 regarding Forward Looking Statements
 2010 Q1 Operations Highlights
 •  Quarterly production exceeded budget by 7%
 •  Integrated $10MM Wattenberg acquisition
 –  Suncor preferential right
 •  Marcellus
 –  Drilled first horizontal well with completion pending
 –  Drilling second horizontal well
 •  Wattenberg
 –  Major gas system operator is installing pipe and compression thatwill reduce line pressure and may further enhance production
 –  Completion practices continue to improve
 –  Second rig reached efficiency very quickly
 •  Piceance
 –  Fit for purpose rig achieving new level of drilling pace
 –  Anticipating permit of water disposal well in next 30 days
 32





See Slide 2 regarding Forward Looking Statements
 Lifting Costs
 33
 Area
Full Year
2008 Actual
Full Year
2009 Actual
Q1 2010

ActualDirect Costs ($/Mcfe)
$0.84
$0.59
$0.75Indirect Costs ($/Mcfe)
$0.23
$0.24
$0.29Total Lifting Cost ($/Mcfe)
$1.07
$0.83
$1.04Production (MMcfe/d)
106
119
101 •  Q1 2010 per unit costs increased as a result of:
 •  Winter operations
 •  Decreased production
 •  EH&S expenses
 •  Location and road maintenance
 •  Water hauling and disposal





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.
 34
 Three Months EndedMarch 31,($ in millions)
2010
2009O&G revenues
$60.4
$39.7O&G production & well operations costs
$15.7
$16.4O&G operating margin(1)
$44.7
$23.3Adjusted cash flow from operations(2)
$49.3
$39.7Adjusted EBITDA(2)
$53.7
$46.2DD&A
$28.4
$34.4G&A
$10.7
$12.1





See Slide 2 regarding Forward Looking Statements
 Summary Financial Results
 Three Months Ended
March 31,(in millions except per share data)
2010
2009Income (loss) from operations
$45.7
($1.6)Net Income (loss) attributable toshareholders
$23.7
($5.7)Diluted earnings (loss) per share attributableto shareholders
$1.23
($0.38) Three Months Ended
March 31,2010
2009Adjusted net income attributable toshareholders(1)
$10.9
$4.1Adjusted earnings per share attributable toshareholders(1)
$0.57
$0.27 35
 (1)  See appendix for GAAP reconciliation of Adjusted Net Income.





See Slide 2 regarding Forward Looking Statements
 APPENDIX
 36





See Slide 2 regarding Forward Looking Statements
 Acreage Inventory
 Area
Lease Gross
Acres
PDC Net Acres
Net Developed
Acres
Net Undeveloped
Acres
StateGrand Valley
8,000
8,000
2,700
5,300
ColoradoWattenberg
72,200
64,900
45,500
19,400
ColoradoNECO
127,100
105,100
19,600
85,500
Colorado/KansasMichigan
26,800
23,300
14,800
8,500
MichiganNew York
18,700
15,900
0
15,900
New YorkNorth Dakota
66,800
30,200
4,600
25,600
North DakotaAppalachian Basin
120,900
117,600
106,800
10,800
WV / PAWyoming
19,500
19,300
100
19,200
WyomingTexas Barnett
8,900
6,000
400
5,600
TexasTotal
468,900
390,300
194,500
195,800PDC TOTAL NET
390,300 37





See Slide 2 regarding Forward Looking Statements
 Proved Reserves/Bcfe
by Area at Year-End 2009
 38
 Area
2008
2009
2008
2009
2008
2009
2008
2009Wattenberg
79
89
1
1
119
140
199
230Piceance
107
103
6
0
260
275
373
378NECO
40
31
3
0
5
0
48
31Appalachia
53
42
21
13
39
6
113
61Other
20
16
0
1
0
0
20
17TOTAL
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) /Bcfe
by Area at Year-End 2009
 39
 Proved + ProbableArea
2008
2009
2008
2009
2008
2009Wattenberg
199
230
236
305
241
332Piceance
373
378
486
449
538
465NECO
48
31
57
31
74
31Appalachia
113
61
126
113
136
145Other
20
17
20
17
20
17TOTAL
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
 Production/Bcfe by Area
 40
 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
 41
 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 investmentreturns.
 (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 liquidityand improvement in leverage and coverage measures
 •  ~$50MM equity raise, and ~$160MM PDC and Lime Rock Partners joint venture to develop MarcellusShale and Shallow Devonian assets, reflected the company’s ability to access alternative capitalmarkets, and improve liquidity, leverage and coverage measures
 * Liquidity excludes $18.7 million L.C.
 42
 $305
 $203
 x
 x
 x
 $80





See Slide 2 regarding Forward Looking Statements
 2009 Adjusted Net
Income Reconciliation
 43
 (1) Includes natural gas marketing activities.
 Year EndedDecember 31,($ in millions, except per share data)
2009
2008Net Income (loss) attributable to shareholders
($79.3)
$113.3Unrealized loss (gain) on derivatives, net (1)
116.6
(117.5)Provision for underpayment of gas sales
2.7
4.0Tax effect of above adjustment
(43.0)
39.9Adjusted Net Income (loss) attributable to
shareholders
($2.9)
$39.7Weighted average diluted shares outstanding
16,448
14,848Adjusted diluted earnings (loss) per share
($0.18)
$2.67





See Slide 2 regarding Forward Looking Statements
 2009 Adjusted Cash
Flow Reconciliation
 44
 Year EndedDecember 31,($ in millions, except per share data)
2009
2008Net Cash provided by operating activities
$143.9
$139.1Changes in assets and liabilities related to
operations
26.3
60.8Adjusted cash flow from operations
$170.2
$199.9Weighted average diluted shares outstanding
16,448
14,848Adjusted cash flow per share
$10.35
$13.46





See Slide 2 regarding Forward Looking Statements
 2009 Adjusted
EBITDA Reconciliation
 (1) Includes natural gas marketing activities.
 45
 Year EndedDecember 31,($ in millions, except per share data)
2009
2008Net Income (loss) attributable to shareholders
($79.3)
$113.3Unrealized loss (gain) on derivatives, net (1)
116.6
(117.5)Interest, net
37.0
27.5Income taxes expense (benefit)
(45.6)
61.5Depreciation, depletion & amortization
131.0
104.6Adjusted EBITDA
$159.7
$189.4Weighted average diluted shares outstanding
16,448
14,848Adjusted EBITDA per share
$9.71
$12.76





See Slide 2 regarding Forward Looking Statements
 Q1 2010 Adjusted
Net Income Reconciliation
 46
 (1)  Includes natural gas marketing activities.
 Three Months EndedMarch 31,(in millions, except per share data)
2010
2009Net income (loss) attributable to shareholders
$23.7
($5.7)Unrealized loss (gain) on derivatives, net (1)
(20.5)
13.2Provision for underpayment of gas sales
-
2.6Tax effect of above adjustments
7.7
(6.0)Adjusted net income attributable to shareholders
$10.9
$4.1Weighted average diluted shares outstanding
19.3
14.8Adjusted diluted earnings per share
$0.57
$0.27 * Amounts may not foot due to rounding.





See Slide 2 regarding Forward Looking Statements
 Q1 2010 Adjusted
Cash Flow Reconciliation
 47
 Three Months EndedMarch 31,(in millions, except per share data)
2010
2009Net cash provided by operating activities
$51.3
$35.9Changes in assets and liabilities related to
operations
(2.0)
3.9Adjusted cash flow from operations
$49.3
$39.7 * Amounts may not foot due to rounding.





See Slide 2 regarding Forward Looking Statements
 Q1 2010 Adjusted
EBITDA Reconciliation
 (1)  Includes natural gas marketing activities.
 48
 Three Months EndedMarch 31,(in millions, except per share data)
2010
2009Net income (loss) attributable to shareholders
$23.7
($5.7)Unrealized loss (gain) on derivatives, net(1)
(20.5)
13.2Interest expense, net
7.8
8.4Income tax expense (benefit)
14.3
(4.0)Depreciation, depletion & amortization
28.4
34.4Adjusted EBITDA
$53.7
$46.2Weighted average diluted shares outstanding
19.3
14.8Adjusted EBITDA per share
$2.78
$3.12 * Amounts may not foot due to rounding.





NASDAQ:PETD
 PETROLEUM DEVELOPMENT
CORPORATION
 Investor Meetings
 June 2010