EX-99 2 slideshowtext.htm SLIDE SHOW TEXT slideshowtext.htm

Petroleum Development Corporation
July Corporate Presentation
Steven R. Williams, Chairman & CEO
Richard W. McCullough, CFO & Treasurer
NASDAQ GSM:PETD

Forward Looking Statements
This information contains predictions, estimates and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved.  Important factors that could cause actual results to differ materially from those included in the forward-looking statements include the timing and extent of changes in commodity prices for oil and gas, the need to develop and replace reserves, environmental risks, drilling and operating risks, risks related to exploration and development, uncertainties about the estimates of reserves, competition, government regulation and the ability of the Company to meet its stated business goals.

Contact Information:
Investor Relations
Petroleum Development Corporation
120 Genesis Boulevard, PO Box 26
Bridgeport, West Virginia 26330
Phone: 304.842.3597, Fax: 304.842.0913
www.petd.com

Company Snapshot
·  Market Cap (06/30/07)
Ø  Approx. $760 Million
·  Proved Reserves (12/31/06)
Ø  323 Bcfe
·  Production (2006)
Ø  16.9 Bcfe
·  Production Profile (1Q07)
Ø  78% N. Gas / 22% Oil
·  EBITDA (2006)
Ø  $423.6 Million
·  Total Shareholder Equity (12/31/06)
Ø  $360.1 Million

First Quarter Highlights
·  
Received Nasdaq notification on July 5, 2007
o  
In compliance with all Nasdaq Marketplace Rules
o  
Will continue listing
·  
Record production of 5.33 Bcfe
o  
On track with 28 Bcfe guidance for 2007
·  
Adjusted Cash Flow up despite impacts of prices*
·  
G&A costs reflect accounting and systems improvements and staff enhancements

* Adjusted Cash Flow is net income adjusted for non-cash gains and charges for DD&A, deferred taxes and unrealized derivative losses.  See slide 10 for further information.

Impact of Price Changes
·  
Average 1Q07 price of $6.38 per Mcfe was $1.32 lower than 1Q 2006
·  
Reduced cash flow and earnings
·  
Realized derivative gain in 1Q07 of about $600k
o  
Unrealized derivative losses for future period derivatives of $6.2 million (non-cash)
·  
Prices and derivatives also reduced Gas Marketing revenue and expenses
 

Summary Financial Results
($ in millions, except for per share data)

 
First Quarter
 
2006
2007
Revenues
$82.8
$57.9
Total Expenses
$64.5
$54.3
Income from Operations
$18.3
$3.6
Net Income
$11.6
$2.5
Diluted Earnings Per Share
$0.72
$0.17

Revenue
·  
Increased production at record levels
·  
Factors reducing revenue
o  
Direct impact of lower prices
o  
Unrealized derivative losses
o  
Price effect on gas marketing revenue and derivatives

Net Income
·  
Net Income of $2.5 million
·  
Reduced by prices
o  
Primary Drivers
§  
Cash item - Lower prices
§  
Non-cash items - Increased DD&A and unrealized derivative losses

EBITDA
·  
Includes impact of lower gas prices and non-cash unrealized derivative losses
·  
Affected by unrealized derivative losses (gains):
o  
2006 $7.6 million gain
o  
2005 $3.2 million loss
o  
2004 $0.5 million loss
·  
EBITDA = Net Income + Interest Expense + Income Taxes + Depreciation, depletion, amortization (DD&A)


EBITDA Reconciliation
($ in thousands)
 
2002
2003
2004
2005
2006
 
1Q06
1Q07
Net Income
$8,881
$20,413
$33,228
$41,452
$237,772
 
$11,645
$2,501
Interest
1,505
816
238
217
2,443
 
352
831
Income Taxes
3,186
11,934
20,250
24,676
149,637
 
6,710
1,436
DD&A
12,602
15,313
18,156
21,116
33,735
 
6,587
13,074
EBITDA
$26,174
$48,476
$71,872
$87,461
$423,587
 
$25,294
$17,842
 
Management believes EBITDA is relevant because it is a measure of cash available to fund the Company’s capital expenditures and service its debt and is a widely used industry metric which allows comparability of our results with our peers.

Adjusted Cash Flow
·  
Increased despite lower prices
·  
Adjusted Cash Flow = Net Income + Deferred Income Taxes + DD&A + impact of unrealized derivative gains or losses
 
 
Adjusted Cash Flow Reconciliation
($ in thousands)
 
2002
2003
2004
2005
2006
  
1Q06
1Q07
Net Income
$8,881
$20,413
$33,228
$41,452
$237,772
 
$11,645
$2,501
Deferred Income Taxes
2,189
8,462
9,887
3,351
86,431
 
996
(3,379)
DD&A
12,602
15,313
18,156
21,116
33,735
 
6,587
13,074
Unrealized Derivative Losses (Gains)
517
(1,110)
535
3,226
(7,620)
 
(2,894)
6,636
Adjusted Cash Flow
$24,189
$43,078
$61,806
$69,145
$350,318
 
$16,334
$18,832

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

Acquisitions Summary
·  
During December 2006 and January 2007, closed $209 Million in acquisitions ($18 Million non-1031)
o  
3P reserves acquired total an estimated 153 Bcfe (84% proved)
o  
Acquisitions primarily in existing operating areas
§  
Wattenberg Field, DJ Basin Colorado
§  
Appalachian and Michigan Basins
·  
Additional properties acquired in February 2007
o  
Estimated 26.6 Bcfe proved and probable reserves
o  
$11.8 million purchase price

G&A Expense
·  
Levels higher than anticipated
o  
Improving processes and systems
o  
SOX compliance work
o  
Delayed financial reports
·  
Anticipate high levels through 2007
o  
New auditors (Pricewaterhouse Coopers)
o  
New IT system start-up
o  
Continuing partnership restatements and SOX work

DD&A
·  
Higher oil & gas production
·  
Higher reserve additions relative to historical lower cost reserves
·  
Cost of recent acreage acquisitions at current market rates
·  
Higher 3rd party drilling and development costs

Increasing Production
{Graphic}

Increasing Estimated Proved Reserves
{Graphic}

Drilling Activity
{Graphic}

2007 Production Forecast Update
·  
Estimated 2007
o  
Production of 28 Bcfe
o  
Exit Rate of 100 MMcfd
o  
YE Proved Reserves>500 Bcfe
 
Mid year production increase a result of:
·  
Start up of Garden Gulch compression facility (Grand Valley) in late June
o  
Gross capacity increased from 17 to 50 MMcfd
o  
Reduced line pressure in Grand Valley
·  
Positive impact of reducing back-log of wells in Grand Valley, Wattenberg and NECO areas.
o  
Approximately 20 gross wells in each area awaiting turn-in
 
 
2007 Production Forecast Update

2007 Forecast by Area (MMcfe)
 
Forecast
Area
1Q
Actual
Actual/
Forecast
1Q
2Q
3Q
4Q
2007
Rocky Mountain
4,351
98%
4,435
5,041
6,794
7,405
23,675
Appalachian
640
102%
625
640
680
689
2,634
Michigan
461
111%
415
424
456
459
1,754
Company Total
5,452
100%
5,475
6,104
7,931
8,553
28,063

Rocky Mountain Forecast by Area (MMcfe)
 
Forecast
 Area
1Q
Actual
Actual /
Forecast
1Q
2Q
3Q
4Q
2007
Wattenberg
2,196
95%
2,314
2,586
3,149
3,361
11,410
Grand Valley
1,245
117%
1,064
1,245
2,086
2,094
6,490
NECO
733
88%
834
954
1,203
1,492
4,483
North Dakota
177
79%
224
256
355
458
1,293
Rocky Mountain Total
4,351
98%
4,435
5,041
6,794
7,405
23,675

Major Operating Area Highlights
·  
Wattenberg Area production shortfall due to weather related issues, production not “lost” but delayed
·  
Grand Valley production positively impacted by facility improvements and greater # of wells inline
·  
NECO Area production difference due to fewer wells inline than anticipated

Core Operating Areas
{Graphic}

General Changes to 2007 Operational Plan
·  
Reduced activity level in ND.
·  
Increased planned wells net to the Company in Grand Valley.
o  
Increase in capital partially offset by reduction in ND
·  
Reduced planned wells in Wattenberg net to the Company.
o  
Addition of Niobrara zone completion results in capital and reserve values equivalent to prior model levels.
·  
Details and update of 2007 operational plan, anticipated results and well economics to be provided when 2nd Quarter 10-Q is filed.
 
 
Grand Valley Field
 Piceance Basin, Colorado
·  
June 07 net daily production 18 MMcfed
·  
5,120 Acres available for drilling on 10 acre Spacing
·  
Approximately 355 locations
o  
148 net PUD locations
o  
207 remaining unproved locations
 
Grand Valley Well Completions

·  
Improved Completion Design
·  
“Slick Water” – “Cleaner” “Better” fluid
·  
Increase of average per well Estimated Ultimate Recover (EUR) from 1.25 Bcfe per well to 1.5 Bcfe per well
·  
Increase in average Initial Production (IP) rate from 820 Mcfd to 1,100 Mcfd

·  
2000 – 2004 Multi-stage, large frac interval
·  
2005 More frac stages, smaller intervals
·  
2006 Improved fluids, improved techniques

Grand Valley Well Completions
{Graphic}

Grand Valley Well Completions
{Graphic}

Grand Valley Field
{Graphic}

Piceance Basin, Colorado
·  
1.5 Bcfe per well
·  
1.2 net Bcfe @80% NRI
·  
D&C cost of $2.2 Million / well
·  
Development cost of $ 1.77 / Mcfe
·  
Wells drilled directionally from multi-well pads

Grand Valley Field
Piceance Basin, Colorado

2007 Drilling
·  
Drill 38 Net wells
o  
46.6 Bcfe added by drilling
o  
$83.6 Million D&C cost

2007 Field Total
·  
6.9 Bcfe net production for 2007
·  
89% increase over 2006
·  
50 MMcfd compression and pipeline expansion project
o  
In service date June 2007

 
Wattenberg Field
DJ Basin, Colorado
·  
2006 net exit rate 18.6 MMcfed
·  
9,000 acres available for drilling
·  
Over 450 locations
o  
154 40 acre PUD locations
o  
Over 300 remaining other locations (Rule 318A and other)
o  
800 Codell and/or Niobrara refracs
·  
Developing acquisition properties

Wattenberg Field
DJ Basin, Colorado

Codell
·  
0.3 Bcfe per well (includes re-frac)
·  
0.24 net Bcfe @80% NRI
·  
D&C cost of $490K per well plus $180K for re-frac
·  
Development cost of $ 2.79/Mcfe or $16.75/Boe

Niobrara
·  
0.15 Bcfe per well
·  
0.12 net Bcfe @80% NRI
·  
Additional completion costs of $130K per well
·  
Development cost of $1.08/Mcfe or $6.50/Boe

Wattenberg Field
DJ Basin, Colorado

2007 Drilling
·  
Drill 150 wells
o  
67 Partnership (PDC 37% WI)
o  
83 PDC (100% WI)
·  
100 Net wells
o  
Niobrara completions offset reduced wells in capital cost and reserves
·  
164 re-completions and re-fracs
·  
33.9 Bcfe added by drilling
·  
$93 Million D&C cost

2007 Field Total
·  
11.2 Bcfe net production for 2007
·  
68% increase over 2006

NECO Field Area
Eastern DJ Basin, Colorado
·  
2006 net exit rate 8.5 MMcfed
·  
29,160 acres available for drilling
·  
8 defined structures (3D and 2D seismic)
·  
100 PUD locations
·  
200 potential locations

NECO Field Area
Eastern DJ Basin, Colorado
·  
0.28 Bcfe per well
·  
0.22 net Bcfe @80% NRI
·  
D&C cost of $234K per well
·  
Development cost of $1.06/Mcfe

 
NECO Field Area
Eastern DJ Basin, Colorado

2007 Plan
·  
Drill 141 wells, PDC 100%WI
·  
31 Bcfe added by drilling
·  
$33 Million D&C cost
·  
4.5 Bcfe net production for 2007
·  
44% increase over 2006
·  
Acquiring 50 square miles of additional 3D seismic
o  
Potential addition of 100-200 locations

Horizontal Bakken and Nesson Projects
Western Williston Basin, North Dakota
·  
Horizontal drilling oil Projects
·  
Exploratory and early developmental
·  
Current economics marginal at $50 per barrel oil
·  
Improving D&C methods may improve economics
 
Appalachian and Michigan Operation Areas
 
 
Appalachian
Michigan
Operated Wells
1365
206
2006 YE Proved Reserves
36.0 Bcfe
21.2 Bcfe
2007 Acquisition Proved Reserves *
30.1 Bcfe
4.6 Bcfe
% of 2006 YE Proved
84%
22%
2007E Production*
2.6 Bcfe
1.8 Bcfe
Increase from 2006*
86%
20%

Continuing Our Success
·  
Low-risk resource plays
·  
Strong development inventory
·  
Proven multi-basin operator
·  
Strong balance sheet
·  
Skilled and experienced management and technical team

Petroleum Development Corporation
July Corporate Presentation
Steven R. Williams, Chairman & CEO
Richard W. McCullough, CFO & Treasurer
NASDAQ GSM:PETD