PDC Energy 8K Regulation FD Disclosure | PDCE 15 Jul 10

Analyst Day - Colorado

July 15, 2010

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 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.

7/15/2010

Welcome

Introductions

• Peter G. Schreck, Vice President - Finance and Treasurer

Presenters

• 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

7/15/2010

Analyst Day Agenda

I. Introduction of New Name and Logo (Rick)

II. Overview of PDC Energy and Status of the New Direction (Rick)

III. Operational Update (Bart)

IV. 2010 Guidance Update (Gysle)

V. New Business Developments (Lance)

VI. Three Year Plan (Lance)

VII. Peer Analysis (Lance)

VIII. Wrap-Up (Rick)

7/15/2010

Rick McCullough

Chairman and Chief Executive Officer

7/15/2010

What the PDC Energy Logo Represents

The copper circle

symbolizes the earth,

the source of PDC’s assets.

The flame is reversed out

of the copper background,

representing natural gas.

The black drop

within the white flame

stands for petroleum.

The PDC Energy logo consists of three elements—a circle, a flame and a drop. Combined, these elements
represent the oil and gas industry. The circle symbolizes the earth and its natural resources. The flame represents
natural gas. The drop stands for oil. Copper is the dominant color. It was chosen for its earthy quality, and to
differentiate PDC Energy from competitors.

7/15/2010

What’s New at PDC Energy

7/15/2010

• The New PDC Team

– Senior Executive Team: Rick, Gysle, Bart, Dan, Lance

– Other Key Officers: Scott Reasoner, Jim Schaff, Peter Schreck, Scott Meyers

• The New PDC

– Repurchasing Limited Partners interests in PDC partnerships

– Increasing oil component of asset base (target 65/35 mix in five years)

– Growth Focus

• Organic - Focus on core competencies

• A&D - Acquire and exploit around core competencies

• Exploration - Expand and enhance asset base

– Achieve the cost reductions in each core basin to place PDC in the low cost
quadrant of operators

– Maintain conservative balance sheet leverage metrics; target BB rating to optimize
and balance cost of capital with strategic growth objectives

– Continue effective hedging execution and establish midstream competencies

I. NYC Analyst Day - March 2009 - outlined “SHAREHOLDER VALUE” focus;
began cost control and operational enhancement initiatives

II. July 2009 - laid out a new direction; transition to traditional E&P company
and began reconfiguration of asset inventory

III. March 2010 - set forth five new corporate metrics and related targets, and
outlined what to expect in 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 PDC’s Partnerships

• Pursuit of small asset acquisitions

• Continue focus on increase in shareholder value

Transition of PDC Energy
2008 - 2010

7/15/2010

Continued Progress in 2010

2010 Goal/Metric	2010 Result
1. Allocation of drilling capital to all core areas	1. Incorporated into 2010 capital budget
2. Expansion of drilling in Wattenberg Field and Piceance Basin	2. Kreiger Acquisition, Suncor pref. rights, larger capital allocation to Wattenberg Field in 2010 capital budget
3. Potential repurchase of limited partners interests in PDC partnerships	3. Filed SEC Prospectus Supplement for repurchase of Limited Partners’ interest in four PDC partnerships
4. Small asset acquisitions	4. Wolfberry acquisition
5. Continued focus on the new PDC	5. Created three-year growth projections

7/15/2010

What We Plan to Address Today

• Update on core development activity and new exploratory projects

– Piceance economics and plans

– Wolfberry and horizontal Niobrara plans

– New Ohio exploration project and Bakken update

• Revised 2010 Guidance

– Production, exit rates, capital and operating budgets, debt and cash flows

• High level projections for 2011-13

– Organic production growth, repurchase of Limited Partners’ interests in PDC
partnerships, and exploration

– Reserve additions by major project

– Capital spending and external capital requirements

• Share price analysis

7/15/2010

Industrial and Power Demand Growing

7/15/2010

Industrial and Power Demand Growing

7/15/2010

Piceance Flows versus Capacity

7/15/2010

Source: Bentek Energy LLC

Rockies Fill Watch

7/15/2010

Source: Bentek Energy LLC

Impact of Oil on Profitability

PDC plans to expand into oilier plays to increase profitability and diversify reserve base.

•Transition portfolio towards 65% gas and 35% oil

•Future cash flow and earnings growth driver

•New drill oil wells’ IRR projected to be 40%-75%

PDC is well positioned with large project inventory in oil-rich plays.

Wattenberg Niobrara HZ
Wolfberry

Full Cycle Cash Margin ($/mcfe): $8.10 $9.59 $8.60

Drilling F&D Cost ($/mcfe): $2.00 $2.64 $2.15

% Oil: 56% 91% 69%

Capital Efficiency: 260% 470% 290%

7/15/2010

Bart Brookman

Senior Vice President - Exploration and Production

7/15/2010

Opening Summary

• PDC’s core operating basins have returned to profitability and will be strong
growth drivers

– Piceance Basin economics continuing to improve

– Wattenberg Field oil/NGL component driving solid returns

• Shift of asset mix and new drilling opportunities

– Wolfberry drilling to begin in late 2010

– Horizontal Niobrara drilling in Weld County, Colorado in late 2010

– Continued Marcellus drilling

• Exploration efforts are beginning to generate opportunities

• Maintain balanced portfolio of drilling/recompletion opportunities across
multiple basins

• Expand inventory of oil based projects diversifying project inventory

• Focus on assets which fit existing technical competencies

7/15/2010

Core Operating Regions

Rocky Mountains

2010E Production:
2.5
Bcfe

Appalachian Basin (PDCM)

2010E Production:
0.8
Bcfe**

2010E Production*

36.4 Bcfe

Michigan
Basin (2%)

Appalachian Basin (7%)

Rocky
Mountains (90%)

Expected to Close August 2010

2010E Production:
0.5
Bcfe**

West Texas (1%)

West Texas

7/15/2010

*Excludes production from repurchase of Limited Partners’ interest in PDC partnerships.

**Based upon transaction close date of 8/1/2010.

Piceance Basin

Grand Valley Field - Garfield County, CO

Project Overview
Gross Operated Wells	288
Undeveloped Acreage	5,300
Gross Undeveloped Locations	433
Net Undeveloped Locations	362
• PUD	243
• Probable	63
• Possible	14
• Subeconomic Resources*	42

*Subeconomic at year-end 2009 SEC pricing, economic at mid-year 2010 SEC pricing.

7/15/2010

Piceance Basin

Grand Valley Field - Garfield County, CO

Key Economic Parameters
Reserves Per Well	1.48 Bcfe
IP Rate	1082 Mcfe/d
Gross Cost Per Well	$1.9 MM
Average PUD Working Interest	84%
Average PUD Net Revenue Interest	71%

At 5/28/10, three-year average NYMEX gas price is $5.49; NYMEX oil is $80.57.

7/15/2010

Piceance Basin Improvement Projects

Improvement Projects

• Drilling time reduction

– H&P flex rig early results reflect two day
reduction from spud to spud

– Improvements continue and further
reductions are expected

• Salt water disposal

– Received COGCC permit for well conversion
and disposal

– Expect disposal to be operational by early
Q4

– Expected cost reduction of up to $5/Bbl

• Mega-Frac

• Early technical assessments underway

• Pilot program expected to occur in Q3 2010

• Frac cost to increase by ~$116 MM

• Reserves to increase by ~230 MMcfe

• Water disposal well required to reduce water
flow back costs

Grand Valley Field - Garfield County, CO

7/15/2010

At 5/28/10, three-year average NYMEX gas price is $5.49; NYMEX oil is $80.57.

Piceance Mesa Type Curve

Oil Yield: 1 bbl/MMcf

Water Yield 24 bbl/MMcf

Mesa Type Parameters at 5/28/2010 NYMEX Strip

Gas Initial Rate (Qi): 1082 Mcf/d

b = 1.8

Di: 62.3%

Df: 6%

100% WI, 85% NRI

Oil Differential (NYMEX): -$18/bbl

Gas Differential Fraction: (NYMEX):

80% 2010 to 85% in 2014

BTU Factor: 1.08

CAPEX: $1.9MM D&C

Operating Cost: $2296/mo

+ SWD Disposal ($9.87/bbl H2O)

EUR: 1.5 MBO, 1.469 BCF

19% IRR

7/15/2010

At 5/28/10, three-year average NYMEX gas price is $5.49; NYMEX oil is $80.57.

Wattenberg Field

DJ Basin - Weld County, CO

Project Overview
Gross Operated Wells	1,410
Developed Acreage	45,600
Undeveloped Acreage	24,900
Total Acreage	70,500
Gross Undeveloped Locations*	1,533
Net Undeveloped Locations*	831
• PUD	373
• Probable	315
• Possible	141
• Subeconomic Resources	2

*Vertical wells only.

7/15/2010

Wattenberg Field

DJ Basin - Weld County, CO

Key Economic Parameters
Reserves Per Well	0.29 Bcfe (0.52 Bcfe Refrac)
IP Rate	113 Mcf/d, 24 Bbl/d
Gross Cost Per Well	$0.6MM D&C (+ $0.2 MM Refrac)
Average PUD Working Interest	77%
Average PUD Net Revenue Interest	61%

7/15/2010

At 5/28/10, three-year average NYMEX gas price is $5.49; NYMEX oil is $80.57.

Wattenberg Production Comparisons

2009 Drilling Program - Actual vs. Predicted

Average Booked EUR: 0.264 Bcfe

Average Engineered EUR: 0.290 Bcfe

Average Actual EUR: 0.320 Bcfe

7/15/2010

Wattenberg Codell/Niobrara Type Curve

NE Type Parameters at 5/28/2010 NYMEX Strip

Oil Initial Rate (Qi): 24 bbl/d

b = 1.4

Di: 65%

Df: 8%

Gas Initial Rate (Qi): 113 Mcf/d

b = 1.5

Di: 55%

Df: 8%

100% WI, 80% NRI

Oil Differential (NYMEX): -$6.30/bbl

Gas Differential Fraction,

BTU Adjusted: (NYMEX): 120%

(17% of gas revenue in NGL)

CAPEX: $600M D&C (+$200M RF)

Operating Cost: $791/mo

EUR: 23 MBO (36 MBO RF), 150 MMCF (305 MMCF RF)

37% IRR (43% IRR with Refrac)

7/15/2010

Niobrara Resource Potential/Overview
of Opportunity

PDC Advantage - Niobrara Development

• Highly experienced Wattenberg team

– Bart Brookman, Senior Vice President E&P, 22 years Wattenberg experience

– Scott Reasoner, Vice President Western Operations, 26 years Wattenberg experience

– Tony Sharp, Asset Director, 20 years Wattenberg experience

– Jason Miller, District Operations Manager, 15 years Wattenberg experience

– Jeff Salen, Drilling Manager,15 years Wattenberg experience

• Extensive vertical Niobrara drilling/completion knowledge and experience

• Projects in close proximity to pipeline infrastructure

• Extensive long term drilling/service company relationships

• Large inventory of low risk/high return projects

• Significant Niobrara acreage and opportunity relative to market cap

PDC’s Emerging Niobrara Opportunity

• Developed and finalized geologic model in 2009

• PDC’s model compares favorably with results of other operators

• Evaluated and pursued multiple acreage positions

• Acquired 5,600 net acres of prospective acreage in June 2010 (Krieger prospect)

• Preparing to drill first horizontal well in Krieger prospect

• Technical assessment of core Wattenberg acreage underway with early identification of 6 to 7
prospective acreage blocks for horizontal drilling

7/15/2010

Niobrara Resource Potential/Overview
of Opportunity

Basin Level Resource Potential - Niobrara (unrisked)

• Vertical/horizontal drilling opportunities exist among all 70,500 acres of
leasehold

– 120 Bcfe in place (20 MMBoe) per section

– 13 Tcf gas equivalent in place

– Approximately 650 Bcfe of recoverable reserves (5% recovery factor)

Initial Reserve/Horizontal Drilling Potential

• Identification of 50 to 100 horizontal drilling locations

• Blanket reservoir provides excellent control and support for booking offset
reserves

• 3P reserve opportunity of 75 - 250 Bcfe of recoverable reserves

… continued

7/15/2010

Horizontal Niobrara Drilling Opportunities

• 70,500 net acres leased in
DJ Basin horizontal Niobrara
drilling play

• 64,900 net acres leased in
the core Wattenberg Area

• Initial identification of multiple
potential horizontal Niobrara
drilling locations on core
Wattenberg leases

• 5,600 net leased acres in the
Krieger prospect

• Identification of 22 potential
horizontal Niobrara drilling
locations on Krieger prospect
leases

Wattenberg Field Area

Core technical focus area

Krieger Prospect

7/15/2010

Niobrara Acreage Concentration

Source: Johnson Rice & Co., 6/30/10.

7/15/2010

Development Plan/Economics - Niobrara
Formation

• Vertical development
Codell/Niobrara wells

– 2010 ~ 185 completions

– 2011 ~ 140 completions

– 2011 ~ 70 recompletions*

• Horizontal development

– 2010 - 1 to 2 wells

• Krieger Area

– 2011 - 4 to 8 wells

• Core Wattenberg and
Krieger Areas

• Activity level will be
based on 2010 results

– Potential of 70%
improvement in capital
efficiency over verticals

Wattenberg Field Area, Weld County, CO

Assumptions

80% NRI lease

April 2010 Strip Prices

Codell/Niobrara GOR = 5,900 SCF/BBL

Niobrara GOR = 2,900 SCF/BBL

* Assumes successful repurchase of Limited Partner’s interest in 2004 PDC partnerships.

	Codell/Niobrara Vertical New Drill	Niobrara Vertical Recompletion	Niobrara Horizontal New Drill
Well Cost ($MM)	600	240	3,500
IP (BOe/d)	43	20	289
Gross EUR (MBOe)	48	14	300
ROR (%)	37	60	71
PV10 ($MM)	470	208	4,724
F&D ($/Mcfe)	2.08	2.86	1.94

7/15/2010

PDC Mountaineer JV
Marcellus Status

• Recently reached total depth on third horizontal well

– Averaged 28 day drill time

• Well #1: 24 days

• Well #2: 44 days

• Well #3: 16 days

• First horizontal completion executed in late June - 15 stages

– Selling gas at rates in line with 3 Bcf type curve (flowback rate)

– Less than 10% load recovery

– Flowing up 5-1/2” casing

• Second horizontal completion expected in July 2010

• Third horizontal completion scheduled for Q3 2010

• Two 3D seismic shoots completed - 18 square miles

– Clean resolution of Marcellus, no geohazards identified

– Third 3D seismic shoot scheduled for Q3 2010

• Microseismic conducted on first horizontal completion

– Outstanding individual stage placement within Marcellus

– Clean orientation established

• Second microseismic operation scheduled for mid-July

7/15/2010

PDC Mountaineer JV
Marcellus Production Update

7/15/2010

PDC Mountaineer JV
Marcellus Horizontal Type Curve

EUR: 3.0 BCFE

PDC Mountaineer JV
WV Marcellus Position

7/15/2010

43,408 Net Acres

Note: Net acreage represents total JV acreage.

PDC Mountaineer JV
PA Marcellus Position

7/15/2010

15,219 Net Acres

Note: Net acreage represents total JV acreage.

PDC’s Marcellus Concentration

7/15/2010

Marcellus Shale Acreage per 1,000 Shares

PDC Mountaineer JV
Marcellus Midstream Update

• PDCM’s JV Board approved a ten year commitment to firm takeaway
capacity escalating to 26 MMcf/d in the first two years

• Commitments will be with an existing pipeline; no construction delays
anticipated

• Firm takeaway satisfies capacity commitment of 2010 and 2011 volume
projections

• 2010 and 2011 drilling and completions timeline should provide quick to
market sales

• Current gas quality is 1,050 Btu/cf

• Processing requirements not anticipated for WV development

• 2013 and beyond midstream strategy being pursued

7/15/2010

PDC Mountaineer JV
Marcellus: 2010 Second Half Plans

• Redeploy horizontal rig September 1st

– Drill four to seven wells

– Executing long-term drilling rig contract through 2011

• Four additional completions

– Limited pumping service availability

• Execute short term midstream solution

• Continue vertical well delineation and seismic data acquisition and analysis

• Leasing program

– Focus on core and bolt-on areas

– Acreage costs and leasing activity increasing

7/15/2010

Wolfberry Acquisition
- Acreage Overview

• Key Development Areas

– Roy Parks

– Mabee

– Ratliff

– Other Permian

• Development Potential

– 120 Wolfberry locations

• Anticipate 1 rig program
starting Q4 2010

– Multiple re-completion
targets

– Product optimization

• Key Offset Operators

– Concho

– Devon

– Cabot

– Endeavor (Midland, TX private operator)

7/15/2010

Wolfberry Acquisition
- 2010 Activity Summary

• Finalizing organization

– District Manager

– Senior Engineer

– Geologist

– Land Man

• Finalizing due diligence

• Reviewing completion options

• Preparing for August operations commencement

• Eight wells expected to return to production - Q3 and Q4 ~$1.25MM

• Expect two Q4 recompletes ~$1.5MM

• Expect two late Q4 new drills in the Wolfberry or deeper ~$3.5MM

• Closing anticipated for July 30, 2010

7/15/2010

Ohio Tecumseh Project

• Current leasehold of 50,000 acres

• 75% PDC WI

• 62% average PDC NRI

• Additional leasing efforts underway

• First proof of concept well
scheduled for Q3 2010

Tecumseh Project

Fairway

Producing well

Area of Leasehold

7/15/2010

Ohio Tecumseh Project History

• Project was developed primarily in the early 1990’s

• Late Cambrian sands (Rose Run) and early Ordovician carbonates (Beekmantown)

– TD 3,500’ - 4,500’

•��Seismic dependent play

• Improved seismic technology should improve success rate

• Statewide produced >375 Bcf/eq (most since 1993)

• USGS estimates 750 Bcf/eq undiscovered and recoverable

• Partner has been involved in the play since the 1990’s and provides 40,000+ acres
with excellent prospects, seismic, technical knowledge, services, and infrastructure

• PDC provides geotechnical skills, operating team, and capital

• 60-70% natural gas; 30-40% oil

7/15/2010

Ohio Tecumseh Erosional Remnants
- Analogs

• Targets are Erosional Remnants (as shown)
encased in a shale

• The remnant can provide for an economic well
and produce a very clear signature if it
possesses the correct properties

7/15/2010

Ohio Tecumseh Economic
Summary/Plans

• Un-risked full development IRR > 100%

• Fully risked full development IRR > 50%

• Average EUR/well approximately 0.25 Bcfe

• Recoverable reserve potential 50 Bcfe

2010 Plans

• Spud first two wells in August 2010

• Drill six proof of concept wells in second half 2010

• Finalize leasing program of up to 50,000 additional acres

• Continue to obtain updated seismic data - currently possess 75 miles

• Finalize first 3D shoot plans

7/15/2010

Horizontal Bakken Play

PDC Horizontal Bakken Wells

Competitor Horizontal Bakken Activity

• PDC has 50% WI in
approximately 19,000 gross acres
leased

• There are a minimum of eight
horizontal Bakken drilling permits
issued or pending in the
immediate area

• PDC Jepsen #21-29HB. IP 225
BOPD, 150 MCF/D, May 2009.
Approx. 9,000’, 1,280 acre spaced
long lateral

• PDC Jepsen #34-14H. Approx.
4,500’, 640 acre spaced, short
lateral; Frac date 6/21/2010

• PDC becomes operator effective
Q3 2010

PDC Jepsen #21-29HB

PDC Jepsen #34-14H

Approx. 600 BOPD IP

7/15/2010

Burke County, North Dakota

Mid-Year Capital Expenditure Update

Wattenberg

• Outstanding production performance, record drilling efficiencies

• Adding a 3rd rig in Q4

• Acquired Suncor preferential rights

• Acquired acreage for Niobrara horizontal drilling

• Drilling a horizontal Niobrara test on newly acquired acreage

• Increasing refracs and behind pipe projects

• Anticipate fewer non-op new drills

Permian

• Recently announced acquisition for $45MM cash + Michigan assets ($30MM)

• Scheduled to close July 30, 2010

• 2 Wolfberry new drills

• Recompletions of behind pipe reserves

Piceance

• Continue to improve drilling effectiveness

• 4 additional spuds

• Tubing repair work to enhance production

NECO

• High 3rd party line pressure

• Reduced budgeted drilling projects from 25 to 15

Partnership Repurchases

• Filed proxy with SEC to repurchase Limited Partners’ interest in four 2004 PDC partnerships

• Complete repurchase requires approval from majority of Limited Partners

Changes from Original 2010 Guidance

7/15/2010

2010 Planned Development Projects

Marcellus

• 3 Verticals

• 7-10 Horizontals

NECO

• 15 New Drills

Wattenberg

• 185 New Drills

-165 Operated New Drills

-20 Non-Op New Drills

• 58 Refracs/Recompletes

Piceance

• 25 New Drills

West Texas

• 2 New Drills

• 4 Recompletions, other
reactivations

Shallow Devonian

• 10 Recompletions

PDC Mountaineer

PDC

7/15/2010

Mid-Year Capital Expenditure Update

$ MM

7/15/2010

2010 Development Capital Update

Anticipated IRR of 30% on $169 MM of 2010 development capital.

7/15/2010

Operations Forecast Comparison

	2009	2010E	% Increase/ (Decrease)
Total Net Production (Bcfe)(1)	43.3	36.4	(16%)
Gross Exit Rate (MMcfe/d)	187	186	(1%)
Net Exit Rate (MMcfe/d)	107	107	0%
Net Exit Rate (MBbl/d)	3.1	4.3	39%
Net Exit Rate (MMcf/d)	88.1	80.8	(8%)
Net Development Capital ($MM)	$79	$141	78%
Gross Number of Drilling Projects	100	238	137%
Gross Number of Other Projects	38	72	89%

(1) 10% production decrease excluding impact of PDC Mountaineer JV.

7/15/2010

Gysle Shellum

Chief Financial Officer

7/15/2010

2010E Guidance Update

• Reserves, production and capital expenditures per the revised internal
operating plan

• Improved Wattenberg Field volumes due to pref. right acquisition and better
overall performance, partially offset by lower Marcellus production due to
timing delays

• Based on a price range for unhedged natural gas and oil with a midpoint of
$4.84/Mcfe and $77/Bbl, respectively; initial guidance utilized a price range
with a midpoint of $6.00/Mcfe and $77/Bbl.; differentials (NYMEX Gas/Oil)
determined on a field by field basis

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

• Non-cash DD&A adjusted for swap of Permian/Michigan; the expected 2010
range remains unchanged

• Liquidity lower than initial guidance due to acquisitions and increased organic
capital spending

7/15/2010

2010E Michigan/Permian Basin
Transaction

• Acquisition of Texas Permian Basin Wolfberry Trend assets provides an
additional production growth basin

• Michigan and Permian Basin 2010 production volumes were projected to be
essentially equal

• Permian Basin larger oil production mix provides additional cash flow

7/15/2010

2010E FY EPS Updated Guidance

$ MM

Note: Low range provided on 3/12/2010 has remained unchanged.

2010E Metrics Update

Lifting Costs(2)

Capital Spending

• 2010E average sales price increase over 2009 due to larger oil production component and slightly better gas prices.

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

2) 2010E lease operating expense increased an estimated 8% due to higher costs of services and production mix changes.

(Bcfe)

Natural Gas and Oil Hedges

As of May 28, 2010	2010	2011	2012	2013
Weighted Average Hedge Price (Mcfe) (1)
With Floors	$7.50	$6.98	$6.49	$6.37
With Ceilings	$8.12	$7.44	$7.83	$8.20
% of Forecasted Production(1)	78%	74%	60%	58%
Weighted Avg Forward Price(2)	$5.74	$6.56	$6.94	$7.17
Weighted Avg Price of Forecasted Production(3)	$7.12	$6.87	$6.67	$6.71

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

• 2009 realized gain 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

(1) Based on 12/31/09 PDP curve updated for Q1 turn-ins

(2) Based on forward pricing curves as of 5/28/2010

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

7/15/2010

2010E Debt & Liquidity Guidance

$ MM

Analyst Estimates

7/15/2010

2010E Earnings Guidance
			Production (Bcfe)	Earnings (Loss) per Share
Company	Analyst	Date	Street Estimate	Street Estimate
C.K. Cooper	Joel Musante	6/8/2010	37.1	$0.38
Canaccord	Irene Haas	6/29/2010	35.8	$1.49
Credit Suisse	Mark Lear	6/22/2010	36.2	$0.10
Global Hunter	Phil McPherson	5/12/2010	37.3	$1.41
Johnson Rice	Welles Fitzpatrick	6/9/2010	38.0	$0.62
J.P. Morgan	Joe Allman	5/20/2010	35.5	($0.20)
Pritchard Capital	Ray Deacon	5/25/2010	37.3	0.25
Scotia Capital	William Lee	6/1/2010	36.5	0.70
SunTrust	John Gerdes	5/12/2010	37.6	1.10
Wells Fargo Securities	David Tameron	7/8/2010	39.1	0.66

		CONSENSUS:	37.0	$0.65

	PETD Guidance of 7/15/2010:		36.4	($0.32) - $0.47

As of July 15, 2010

Lance Lauck

Senior Vice President - Business Development

7/15/2010

New Business Developments

7/15/2010

Acquisition Strategy

7/15/2010

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)

– 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 $4 million / well net to PDC

Asset Type

• PDP 25% to 50% with significant future growth potential through drilling

• Focused on conventional gas and oil plays

• Add at least one additional shale resource play

Asset Mix

• Prefer oilier plays; however, operational fit and economics will be the determining
factors

Wolfberry Acquisition in the Permian Basin

Key Highlights

7/15/2010

• Acquiring producing assets from private seller in Wolfberry Trend for $45MM
plus PDC’s producing Michigan Gas assets valued by the seller at $30MM

• Includes 72 wells on approximately 8,300 net acres

• Should add approximately 900 Boe/d over the next 12 months and strong
multi-year production growth is projected

• Proved plus probable (2P) reserve add of approximately 8.5MM Boe (70% oil)

• Effective date of transaction is May 1, 2010 with projected closing date of July
30, 2010

• Acquisition driven by US onshore basin study findings

Wolfberry Acquisition

7/15/2010

Acreage Overview with Surrounding Activity

Key Development Areas

• Roy Parks

• Mabee

• Ratliff

• Other Permian

Development Potential

• 120 Wolfberry locations

• 1 rig program starting Q4 2010 anticipated

• Multiple re-completion targets

• Production optimization

Key Offset Operators

• Concho

• Devon

• EXL

• Cabot

• Endeavor Energy Resources (private)

Acreage

BTA Oil Producers, LLC

Chevron USA, INC

COG Operating

Endeavor Energy Resources, LP

EOG Resources, Inc.

Munson, David M., Inc.

Pioneer Natural Resources, USA, Inc.

Other

Top Wolfberry Operators

Wolfberry Acquisition Comparison

Wolfberry Oil Acquisition for Michigan Gas Trade plus $45 mm Cash

7/15/2010

Metric	Michigan	Wolfberry
Full-Cycle Cash Margin ($/mcfe)	$2.40	$8.50
% Oil	1%	69%
Inventory of Wells	2	120
Production Growth	6% decline	70% 3-yr CAGR

Michigan PDP Decline

Wolfberry Development Growth

1-Rig Program

Partnership Purchases

Three-Year Plan to Acquire

7/15/2010

• Limited Partners’ non-operated interest is typically 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

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

Partnership Purchases

Current Status

• Awaiting SEC comments regarding partnership proxy statements

Asset Description

• Non-operated interest in existing PDC wells in Piceance Basin and Wattenberg Field

Partnership Overview

• Offer Price: $36.4 million for 4-2004 partnerships

• Estimated Current Production: 3.6 Mmcfe/d ($10,110 /mcfe/d)

• Estimated 3P Reserves: 29.6 Bcfe ($1.23 /mcfe)

Timeline

• SEC Filing: Proxies filed in first-half of July 2010

• SEC Review Period: 1-2 months

• Submit for LP Vote: 1-2 weeks after completion of SEC review period

• Solicitation Period: Up to 2 months

• Closing: 4Q 2010

2010 Program: 2004 A, B, C, D

7/15/2010

Inventory of Remaining Partnerships

Remaining Partnerships after 2010 Purchase Program

7/15/2010

• 24 Limited Partnerships will remain after 2010 purchase transaction

• Limited Partners’ remaining net reserves of approximately 95 Bcfe

• Limited Partner’s remaining net production of 21.4 mmcfed

• Limited Partners’ interests in 13 of the 24 remaining Partnerships
represent 80% of the reserves and production

• Planning to complete purchases of Limited Partners’ interest in
Partnerships by year-end 2012

Three Year Plan

7/15/2010

PDC Business Model & Key Objectives

Acquire and Exploit Strategy with Exploration Component

– Acquire assets that build project inventory and drive production growth

• Build out / high grade asset portfolio towards more oil / ngl weighted projects

– Exploit existing inventory by capitalizing on operational capabilities

• “Continuous Improvement” to lower costs and increased margins - strive for top quartile metrics in major fields

– Explore in areas where PDC has a focused competitive advantage

• Add new exploration plays capable of driving production and reserve growth. Target 10-15% of capital
expenditures

Key Objectives

– Focus in large resource basins in U.S. Onshore

• PDC currently in Appalachia (gas), U.S. Rockies (gas and oil/ngls) and Permian (oil/ngls)

– Maintain conservative balance sheet leverage metrics; target BB rating to optimize
and balance cost of capital with strategic growth objectives

– Expand the Company’s technical and commercial capabilities

7/15/2010

Three-Year Production Outlook:
Projected Range of 15 to 20% Annual Growth

• Risked Organic Growth: 15% CAGR

Areas Rigs

– Permian / Wolfberry 1

• Risked Additional Growth: +5% CAGR

– Partnership buybacks 75% Success

– Exploration primarily of existing inventory

• Horizontal Niobrara excluded

• Excludes acquisitions, land purchases
and drill to earn projects

7/15/2010

Bcfe/yr

Three-Years Ended 2013

*Depending on further enhancements.

Note: Organic growth based on 3 Bcfe type curve for Marcellus Shale.

36.4 Bcfe

Three-Year Capital Outlook
and Funding Requirements

7/15/2010

Total 2011 - 2013 Key Parameters	Risked Organic	Risked Organic + Additional Growth
Production Growth Range	15%	20%
CAPEX	$ 630 - $700 MM	$ 870 - $970 MM
*Adjusted Cash Flow	$ 560 - $600 MM	$ 640 - $700 MM
Funding Requirement	$70 - $100 MM	$ 230 - $270 MM
Key Drivers	• Commodity Prices • Marcellus Shale Hz Type curve @ 3 Bcfe • Maintain capital efficiency	• Partnership buyback success • Exploration success

*Adjusted Cash Flow = Net Income + Deferred Taxes + DDA (excludes changes in working capital).

• 15% organic growth case results in a funding need of $70 - $100 million over next three years

• 20% organic plus upside growth case results in a funding need of $230 - $270 million over next three years

Three-years ended 2013

2013 Proven Reserve Outlook

Convert probable, possible and potential to proven reserves

Organic: Existing Core, Marcellus Shale, Permian / Wolfberry Growth: Partnerships, Gas Exploration

Future Net Reserve Booking Opportunities

7/15/2010

Year-Ended 2009 Proved Reserves 717 Bcfe

Net Reserves	Location	Commentary
200 Bcfe	Existing 2009 YE Prob/Poss	Offsets, 5 Yr Drill Window (Net of allocation to PDC Mountaineer JV)
150 - 300 Bcfe	Marcellus Shale - net to PDC	Initial 230 Hz wells (only 30% acreage on 80 acre spacing)
30 - 40 Bcfe	Wolfberry Oil	New acquisition (net of Michigan divestiture)
Organic: 380 - 540 Bcfe
50 - 100 Bcfe	Exploration	Current projects in progress - Ohio, others
100 - 125 Bcfe	Acquire Partnerships	Reserves per Ryder Scott
Growth: 150 - 225 Bcfe
Total: 530 - 765 Bcfe
Not in Model: 75 - 250 Bcfe	Horizontal Oil Niobrara	Potential in current Wattenberg and New Acreage

Potential Proven Reserves by year end 2013

717 Bcfe (2009)

- 30 Bcfe proven reserves allocated to PDC Mountaineer

- 200 Bcfe Production (2010-2013 organic + risked growth)

+ 605 Bcfe to 1,015 Bcfe New Bookings (including HZ Niobrara)

~1.1 Tcfe to 1.5 Tcfe range of potential proven reserves

F&D Outlook
2010 to 2013 (4 years incl 2010)

7/15/2010

Total 2010 - 2013 Key Parameters	Risked Organic	Risked Organic + Additional Growth
Production Growth Range	15%	20%
CAPEX (incl 2010 capex)	$905 - $975 MM	$1,145 - $1,245 MM
Reserve Adds	380 - 540 Bcfe	530 - 765 Bcfe
F&D Costs	$2.38 - $1.81 per Mcfe	$2.16 - $1.63 per Mcfe
Key Drivers	• Commodity Prices • Marcellus Shale Hz Type curve @ 3 Bcfe • Maintain capital efficiency	• Partnership buyback success • Exploration success

• F&D from organic only targets range from $1.81 to $2.38 per mcfe

• F&D from organic plus risked upside targets range from $1.63 to $2.16 per mcfe

Cases exclude Niobrara Horizontal oil program.

• F&D calculations include 2010 capex and reserve adds

• 2010 capex of $275 million (capex includes partnership repurchase capital)

PDC Summary

– Pursuing an Acquire, Exploit & Explore Business model focusing on key U.S.
Onshore basins capitalizing on PDC’s skill sets

– Projecting a risked range of production growth of 15 - 20% per year for the three year
period ended 2013 (excludes new acquisitions); for the period 2004 to 2009, PDC
grew at a 27% CAGR

– Identified approximately 600 Bcfe to 1.1 Tcfe of net potential proved reserve adds

– 15% annual production growth case produces a funding need of $70 - $100 MM;
20% annual production growth case produces a funding need of $230 - $270 MM

– Project F&D/Mcfe range of $1.63 to $2.38 consistent with PDC’s historic F&D metric

– Increase margins and efficiencies - strive for top quartile metrics in major fields

Three-Year Plan

7/15/2010

Peer Analysis
3Y Business Plan Outline and Drivers of Company Value
Version 2

Peer Analysis

Why Peer Analysis?

1. Determine how PDC’s operational, financial and transactional metrics
compare to peer E&P companies

2. Analyze reasons why PDC trades at a discount to peers

3. Identify key action steps PDC can pursue to improve performance

Consistent execution of PDC’s new three-year growth plan over multiple quarters
should enable PDC to improve metrics and narrow or eliminate measurement
gap versus peer companies.

7/15/2010

Three-step process

Peer Company Comparisons
Selected by PDC

7/15/2010

Ticker	Share Price	Shares MM		Debt MM	Enterprise Value MM	2010E CFPS	2010E EBITDAX		”	% Gas	% PDP		RLI	3Y Avg PD F&
PETD	$23.78	19	$456	$250	$707	$6.94	$156	3.23	773	85%	41%	37	19.4	$3.08	-3.6%
Peer Median			$603	$434	$1,037	$4.00	$145	3.37	699	86%	50%	39	18.4	$3.15	13.4%

Source: JPM June 11th equity analyst report.

Peer companies include:

Approach Resources, Berry Petroleum, Cabot Oil & Gas, Carrizo Oil & Gas, Goodrich Petroleum, Penn Virginia Corp, Petro Quest Energy

Peer Company Comparisons

PETD trades at or near the lowest value compared to its peer group in every category. As PDC executes on its three-
year business plan it should begin to trade in-line with its peers.

7/15/2010

Median = 5.0X

Median = 7.7X

Peer Comparisons - 2010 Transactions

7/15/2010

• PDC trades at a discount on a proved reserve basis relative to recent transactions

Recent Asset Transaction Reserve Metrics

Median = $2.14/Mcfe

Median = $12,044 / Mcfe

PDC trades below its peer group in most categories analyzed

7/15/2010

Peer Comparisons - Key Takeaways

Metric	PDC	Peer Group
2010 CFM	3.4x	5.0x
EV to EBITDAX 2010E	4.5x	7.7x
EV to Mcfe 2010E	$0.91	$1.83
EV to Mcfe/d	$7,000	$10,051
Transactions - Reserves EV to Mcfe	$0.91	$2.14
Transactions - Production EV to Mcfe/d	$7,000	$12,044

Step One - How PDC Trades Relative to Its Peers

Source: JPM June 11th equity analyst report.

Peer companies include Approach Resources, Berry Petroleum, Cabot Oil & Gas, Carrizo Oil & Gas, Goodrich Petroleum,
Penn Virginia Corp, and PetroQuest Energy

Peer Analysis - Key Takeaways

7/15/2010

Step two - Why PDC believes it is traded at a discount	Step three - Improvements PDC is pursuing
	Developed multi year execution plan capable of delivering 15-20% value-added growth
Portfolio with high concentration of Rockies gas	Pursuing and achieving margin improvement (Piceance) and portfolio transition to more oil (Wolfberry for Michigan)
Minimal proved reserve adds in 2009 due to SEC mandated pricing methodology	Improved Rockies differentials and cost reductions - anticipate reserves lost due to price revision in 2009 will be recovered
High PUD component of total proven reserves	Drilling in all areas due to reduced per well costs and basis improvements - converting PUDs to cash flowing PDPs
Pace of developing and de-risking Marcellus Shale gas play	Formed JV in Marcellus with LRP - anticipate seven producing horizontal wells by year-end 2010
Limited exploration opportunities in portfolio	Adding new exploration plays to drive future growth and reserve adds (Horizontal Niobrara, Ohio)
Uncertainty and lack of clarity with respect to Partnership structure	Initiated three-year Partnership purchase program - filed proxy on first four Partnerships

Steps Two and Three

Peer Comparisons - Key Takeaways

7/15/2010

PETD Historical Market Performance Relative to XNG Index

PDC traded in line with the XNG thru the fall of 2008 then lagged for most of 2009.

While market has begun rewarding PDC in 2010 for improved performance, PDC still needs to achieve additional value-added performance over
multiple quarters to bridge the three-year gap relative to the XNG index.

Note: XNG index includes APC, APA, CHK, DVN, EOG, EP, GAS, NBL, NI, STR, SWN, UPL, WMB, XTO. Data obtained from Fidelity.com.

Six-Month PDC vs. XNG

Three-Year PDC vs. XNG

7/15/2010

Wrap-Up

7/15/2010

Wrap-Up

• Achieved 34% (CAGR) production growth for years 2005 - 2009

• 2008 price collapse necessitated cost reductions and liquidity preservation into
2009

• 2010 - Resumed drilling in all core areas; acquired new assets; accelerated
Marcellus development; initiated horizontal Niobrara development

• 2011 - Return to growth; profitability should come with additional scale,
improved natural gas prices and increased oil mix

7/15/2010

Year	Weighted Forward Price as of May 2010*
2009 Actual	$4.20
2010	$5.74
2011	$6.56

*Excluding derivates.

Wrap-Up

• Outperforming the XNG index

• Valuation gap has improved by approximately 50% y-t-d

• Emerging from recession, focused, well capitalized with great assets
and strong management team

• Will continue to reconfigure asset base, increase oil mix, and drive down
costs through acquire and exploit strategy

• Under promise and over deliver

• PDC Energy’s future is bright

7/15/2010

… continued

Contact Information

Investor Relations

• Peter G. Schreck, Vice President - Finance and Treasurer

pschreck@petd.com

• Marti J. Dowling, Manager Investor Relations

mdowing@petd.com

• Heather R. Davis, Investor Relations Coordinator

hdavis@petd.com

Corporate Headquarters

• PDC Energy

1775 Sherman Street

Suite 3000

Denver, CO 80203

303-860-5800

Website

• www.petd.com

7/15/2010

PDC Energy (PDCE) 8-KRegulation FD Disclosure