Petroleum Development Corporation
December 2007 Update
Steven R. Williams, Chairman & CEO
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.
The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company uses in this presentation the terms “probable” and “possible” reserves, which SEC guidelines prohibit in filings of U.S. registrants. Probable reserves are unproved reserves that are more likely than not to be recoverable. Possible reserves are unproved reserves that are less likely to be recoverable than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. In addition, the Company’s 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.
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 (12/06/07) | |
| o | $795 million | |
| · | Estimated 2007 Year-end Proved Reserves | |
| o | 650+ Bcfe* | |
| · | 3-P Reserves @ Year-end | |
| o | 1+ TCFE** | |
| · | Annual Production | |
| o | 28 Bcfe (2007E) | |
| · | Diluted Average Shares Outstanding (2007) | |
| o | Down 7.5% from 2006 | |
Rocky Mountains
| · | 2006 Proved Reserves: 265.5 Bcfe |
| · | 2006 Production: 14.1 Bcfe |
| · | 2007E Production: 24 Bcfe |
Michigan Basin
| · | 2006 Proved Reserves: 21.2 Bcfe |
| · | Production: 1.4 Bcfe |
· | 2007E Production: 1.8 Bcfe |
Barnett Shale
| · | Exploratory project |
| · | December 2007 drilling |
Appalachian Basin
| · | 2006 Proved Reserves: 36.0 Bcfe |
| · | 2006 Production: 1.5 Bcfe |
| · | 2007E Production: 2.6 Bcfe |
* Reserves are based on internal Company estimates. ** Reserves included in probable and possible categories do not meet the SEC definitions of proved reserves and may be subject to greater risk of recovery than reserves meeting SEC requirements. |
See slide 2 regarding forward looking statements
Key value Driverss
| · | Proven Track Record | |
| o | 5-year 850 return to shareholders | |
| 66% year-over-year production growth | ||
| 55% year-over-year reserve growth | ||
| · | Visible Build-In Growth | |
More than 1 Tcfe of 3P reserves provides significant near-term growth potential Large multi-year, low risk drilling inventory Recently added 47 Bcfe of proved reserves in Southwestern Pennsylvania (15.8 Bcfe producing) | ||
| · | Strong Financial Position Strong balance sheet Debt-to-cap 26% (end of 3rd Qtr) |
See slide 2 regarding forward looking statements
Third Quarter Highlights
| · | Record three-month production of 7.72 Bcfe | |
| o | Record nine month production of 19.5 Bcfe | |
| o | On track with 28 Bcfe guidance for 2007 | |
| · | Adjusted Cash Flow from Operations* up substantially despite impact of lower realized prices in Rockies | |
| · | $31.6 million | |
| · | Drilled 95 gross new wells including 4 in the Appalachian Basin | |
| o | 80.8 net wells | |
| * | Adjusted cash flow from operations is defined as cash flow from operations before changes in assets and liabilities. EBITDA is defined as Net Income + Interest, net + Income Taxes + Depreciation, depletion, amortization. These are non-GAAP measures. See slide 27for further information. |
See slide 2 regarding forward looking statements
Summary Financial Results ($ in millions, except for per share data)
Third Quarter | Nine Months Ended Sep 30 | |||
| 2006 | 2007 | 2006 | 2007 | |
Revenues | $70.8 | $76.3 | $218.3 | $210.1 |
Total Expenses | $58.2 | $66.4 | $175.9 | $192.4 |
Income from Operations* | $340.6 | $9.9 | $370.4 | $43.3 |
Net Income* | $210.9 | $4.5 | $229.8 | $25.0 |
Diluted Earnings Per Share* | $13.33 | $0.30 | $14.32 | $1.68 |
* | Includes $328 million in 2006 and $25.6 million in 2007 (9 months only) for gain on sale of leaseholds related to the Marathon lease sale. |
See slide 2 regarding forward looking statements
Investments Adding Value ($ in millions, except for Mcfe data)
Results of investments in people & production
Third Quarter | Nine Months Ended Sep 30 | |||
Expense Category | 2006 | 2007 | 2006 | 2007 |
Oil & gas production & well ops. | $8.6 | $12.6 | $22.4 | $33.3 |
Per Mcfe | $1.99 | $1.64 | $1.84 | $1.71 |
General & administrative expense | $5.3 | $7.5 | $14.2 | $21.8 |
Per Mcfe | $1.24 | $0.97 | $1.17 | $1.12 |
DD&A | $8.3 | $20.4 | $22.5 | $50.9 |
Per Mcfe | $1.92 | $2.64 | $1.85 | $2.61 |
See slide 2 regarding forward looking statements
Diverse Energy Market Exposure
{Graphic}
Continuing Our Success
| · | Colorado Acquisitions - production and development opportunities | |
| o | Active development program | |
| o | On existing and acquired properties |
| o | 375 planned wells for 2007 |
| · | Operations enhancements | |
| o | Piceance Basin Compression | |
| o | Garden Gulch road completed |
| o | Codell recompletions and Niobrara refracs |
| · | Acquired acreage and preparing to commence drilling in Barnett shale in December 2007 |
| · | Pennsylvania acquisition - production and development opportunities |
See slide 2 regarding forward looking statements
Increasing Production
| · | Record 7.7 Bcfe 3Q07 |
| · | On track to meet 28 Bcfe annual guidance |
| · | YTD Production by area | |
| o | Rocky Mountains = 83.6% | |
| § | 75.7% Natural Gas |
| § | 24.3% Oil |
| o | Appalachian Basin = 9.8% |
| o | Michigan = 6.6% |
See slide 2 regarding forward looking statements
Increasing Estimated Proved Reserves
| · | Anticipate greater than 650+ Bcfe proved reserves for YE 2007 | |
| o | Additions through both the drill bit and acquisitions | |
| · | Active areas primarily in Colorado - Piceance, Wattenberg and NECO |
| · | Southwestern Pennsylvania acquisition |
| * | Reserves are based on internal Company estimates. |
See slide 2 regarding forward looking statements
Drilling Activity
{Graphic}
See slide 2 regarding forward looking statements
2007 Actual vs. Production Forecast
| · | Estimated 2007 Production of 28 Bcfe | |
| o | Nine month production of 19.5 Bcfe | |
| · | Estimated 2007 Exit Rate approximately 100 MMcfd |
| · | Back-log of wells awaiting turn-in in Grand Valley, Wattenberg and NECO areas |
| · | Challenge to meet production goal | |
| o | Fourth qtr curtailment | |
See slide 2 regarding forward looking statements
Enhancements to 2007 Operational Plan
| · | Acquired 47 Bcfe of proved reserves in Southwestern Pennsylvania |
| · | Increased net Grand Valley wells |
| · | Increased CAPEX in Codell refracs and Niobrara recompletions | |
| o | Originally modeled Codell only completions; actual wells are multi-zone completions (J-sand, Codell and Niobrara, as appropriate) | |
| o | Drilling fewer net Wattenberg wells | |
| · | Reduced activity level in ND and reallocated capital | |
See slide 2 regarding forward looking statements
Development Plans
| · | Grand Valley offset locations |
| · | Wattenberg field locations (5th spot, rule 318A and 40 acre locations) |
| · | Locations identified by seismic and offsets to producing wells in NE Colorado |
| · | 31.2 Bcfe in Southwestern Pennsylvania |
| · | Over 400 Bcfe of Probable and Possible Reserves for Future Development |
* See slide 3 regarding reserve estimate limitations.
See slide 2 regarding forward looking statements
Grand Valley Field Piceance Basin, Colorado
2007 Plan
September 2007 net daily production 31 Mmcfe/d (2006 exit rate was 15.4 Mmcfe/d)
Approximately 355 net locations on 10-acre spacing
148 net PUD locations
207 remaining unproved locations
Drill 41 net wells
50 Bcfe added by drilling
$93 Million D&C cost
See slide 2 regarding forward looking statements
Grand Valley Achievements
Reduced drilling time
Valley wells drilled in 11 days (2007) vs 18 days (2005)
Mesa top directional wells in 15 days (2007)
Improved Completion Design
Slick Water Fracs – cleaner, non-gelled fuild results in improved EURS
20% increase of per-well EURs from 1.25 to 1.5 Bcfe
Increased IP rate from 820 to 1,100 Mcfe
See slide 2 regarding forward looking statements
Wattenberg Field DJ Basin, Colorado
September 2007 net daily production 36 Mmcfe/d (2006 net exit rate 18.6 Mmcfe/d)
3P reserves include over 900 net undeveloped locations:
40 acre PUD locations
Rule 318AE locations
5th spot locations
Future opportunity of 800 Codell and/or Niobrara refracs
See slide 2 regarding forward looking statements
Wattenberg Field DJ Basin, Colorado
2007 Plan
Drill 108 net wells
Add estimated 34 Bcfe drilling revenues
Shifted focus from single zone to multi-zone completions (J-sands, Codel,
& Niobrara)
164 re-completions and refracs
Some booked and some reserve additions
$86 Million D&C cost
See slide 2 regarding forward looking statements
NECO Field Area, Eastern DJ Basin, Colorado
September 2007 net daily production 12 Mmcfe/d (2006 net exit rate 8.5 Mmcfe/d)
29,160 acres available for drilling
8 defined structures (3D and 2D seismic)
100 PUD locations
200 potential locations
See slide 2 regarding forward looking statements
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
Acquiring 50 square miles of additional 3D seismic
Potential addition of 100-200 locations
See slide 2 regarding forward looking statements
Appalachian and Michigan Operation Areas
Appalachian | Michigan | |
Operated Wells | 2116 | 206 |
2006 YE Proved Reserves | 36.0 Bcfe | 21.2 Bcfe |
2007 Acquisition Proved Reserves * | 77.1 Bcfe | 4.6 Bcfe |
% of 2006 YE Proved | 84% | 22% |
2007E Production* | 2.6 Bcfe | 1.8 Bcfe |
Increase from 2006* | 86% | 20% |
July 2007 Net Daily Production | 6.2 Mmcfe/d | 4.5 Mmcfe/d |
*Reserves are based on internal Company estimates
See slide 2 regarding forward looking statements
Southwestern Pennsylvania Acquisition
PETD closed the acquisition of Castle Gas Company assets in October 2007
$53 million purchase price $1.12 per Mcfe
Acquired majority interest in 760 natural gas wells located in southwestern
Pennsylvania
Current daily production of 3,000 Mcfe/d
Highly predictable, low risk drilling
47 Bcfe of proved reserves
15.8 Bcfe net Proved Developed Producing
31.2 Bcfe net Proved Undeveloped
See slide 2 regarding forward looking statements
Track Record of Consistent Growth
{Graphic}
See slide 2 regarding forward looking statements
Track Record of Consistent Growth
Supplemental Data
2007 Production Forecast
Forecast | ||||||||
Area | 1Q Actual | 2Q Actual | 3Q Actual | 1Q | 2Q | 3Q | 4Q | 2007 |
Rocky Mountain | 4,290 | 5,322 | 6,683 | 4,435 | 5,041 | 6,794 | 7,405 | 23,675 |
Appalachian | 617 | 687 | 610 | 625 | 640 | 680 | 689 | 2,634 |
Michigan | 426 | 427 | 428 | 415 | 424 | 456 | 459 | 1,754 |
Company Total | 5,333 | 6,436 | 7,721 | 5,475 | 6,104 | 7,931 | 8,553 | 28,063 |
Forecast | ||||||||
Area | 1Q Actual | 2Q Actual | 3Q Actual | 1Q | 2Q | 3Q | 4Q | 2007 |
Wattenberg | 2,209 | 2,623 | 2,963 | 2,314 | 2,586 | 3,149 | 3,361 | 11,410 |
Grand Valley | 1,246 | 1,590 | 2,622 | 1,064 | 1,245 | 2,086 | 2,094 | 6,490 |
NECO | 677 | 942 | 960 | 834 | 954 | 1,203 | 1,492 | 4,483 |
North Dakota | 158 | 165 | 138 | 224 | 256 | 355 | 458 | 1,293 |
Rocky Mountain Total | 4,290 | 5,321 | 6,683 | 4,435 | 5,041 | 6,794 | 7,405 | 23,675 |
Forecasted numbers are from presentation to Analysts on January 22, 2007
Major Operating Area Highlights
| · | Wattenberg Area production shortfall due to weather related issues, production not “lost” but delayed |
| · | Grand Valley production positively impacted by facility improvements and greater # of wells inline |
| · | NECO Area production difference due to fewer wells inline than anticipated |
See slide 2 regarding forward looking statements
EBITDA & Adjusted Cash Flow from Operations Reconciliation ($ in thousands)
EBITDA | 2002 | 2003 | 2004 | 2005 | 2006 | 9/30/2007 | 3Q06 | 3Q07 |
| Net Income | $8,881 | $20,413 | $33,228 | $41,452 | $237,772 | $25,011 | $210,884 | $4,459 |
| Interest, Net | 1,257 | 626 | 53 | (681) | (5,607) | 2,766 | (3,109) | 2,082 |
| Income Taxes | 3,186 | 11,934 | 20,250 | 24,676 | 149,637 | 15,511 | 132,795 | 3,326 |
| Depreciation | 12,602 | 15,313 | 18,156 | 21,116 | 33,735 | 50,857 | 8,300 | 20,354 |
| EBITDA | $25,926 | $48,286 | $71,687 | $86,563 | $415,537 | $94,145 | $348,870 | $30,221 |
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 Operations | 2002 | 2003 | 2004 | 2005 | 2006 | 9/30/2007 | 3Q06 | 3Q07 |
| Net Cash Provided by Operating Activities | $28,173 | $73,608 | $73,301 | $112,372 | $67,390 | ($32,800) | $2,632 | $43,585 |
| Changes in Assets & Liabilities to Operations | (2,875) | (26,691) | (10,786) | (38,815) | (37,554) | 101,003 | (2,497) | (11,987) |
| Adjusted Cash Flow from Operations | $25,298 | $46,917 | $62,515 | $73,557 | $29,836 | $68,203 | $135 | $31,638 |
Management believes Adjusted Cash Flow from Operations is relevant because it is a measure of cash available to fund the Company’s capital expenditures and service its debt. Management also believes Adjusted Cash Flow from Operations is a useful measure for estimating the value of the Company’s operations.
See slide 2 regarding forward looking statements
Petroleum Development Corporation
December 2007 Update
Steven R. Williams, Chairman & CEO
NASDAQ GSM: PETD