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 |
| · | 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 $2.5 million |
| § | Cash item - Lower prices |
| § | Non-cash items - Increased DD&A and unrealized derivative losses |
EBITDA
| · | Includes impact of lower gas prices and non-cash unrealized derivative losses |
| · | Affected by unrealized derivative losses (gains): |
· | EBITDA = Net Income + Interest Expense + Income Taxes + Depreciation, depletion, amortization (DD&A) |
EBITDA Reconciliation
($ 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 | Delayed financial reports |
| · | Anticipate high levels through 2007 |
| o | New auditors (Pricewaterhouse Coopers) |
| 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
| 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
| · | June 07 net daily production 18 MMcfed |
| · | 5,120 Acres available for drilling on 10 acre Spacing |
| · | Approximately 355 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
| · | 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
| o | 46.6 Bcfe added by drilling |
2007 Field Total
| · | 6.9 Bcfe net production for 2007 |
| · | 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 |
| 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) |
| · | D&C cost of $490K per well plus $180K for re-frac |
| · | Development cost of $ 2.79/Mcfe or $16.75/Boe |
Niobrara
| · | Additional completion costs of $130K per well |
| · | Development cost of $1.08/Mcfe or $6.50/Boe |
Wattenberg Field
DJ Basin, Colorado
2007 Drilling
| o | 67 Partnership (PDC 37% WI) |
| o | Niobrara completions offset reduced wells in capital cost and reserves |
| · | 164 re-completions and re-fracs |
| · | 33.9 Bcfe added by drilling |
2007 Field Total
| · | 11.2 Bcfe net production for 2007 |
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) |
| · | 200 potential locations |
NECO Field Area
Eastern DJ Basin, Colorado
| · | 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 |
| · | 4.5 Bcfe net production for 2007 |
| · | 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 |
| · | 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
