Petroleum Development Corporation
2007 Third Quarter Results
November 9, 2007
Thomas E. Riley, President
Richard W. McCullough, Chief Financial Officer
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.
Continued on Slide 3
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
Forward Looking Statements (Continued)
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.
Richard W. McCullough, Chief Financial Officer
Company Snapshot
| · | Market Cap (10/31/07) |
| o | $677 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 |
| · | Late 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 statement
Third Quarter Highlights
| · | Record three-month production of 7.72 Bcfe or almost 32 Bcfe annualized |
| 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* |
| · | $31.6 million or approximately $120 million annualized |
| · | Drilled 95 gross new wells including 4 in the Appalachian Basin |
| o | 80.8 net wells |
| o | 264 gross (220.4 net) wells for 9 months |
| * | Adjusted cash flow from operations is defined as cash flow from operations before changes in assets and liabilities. EBITDA is defined as Net Income + Interest, net + Income Taxes + Depreciation, depletion, amortization. These are non-GAAP measures. See slide 25 for further information. |
See slide 2 regarding forward looking statement
Summary Financial Results ($ 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 $25.6 million in 2007 (9 months only) for gain on sale of leaseholds related to the Marathon lease sale. |
See slide 2 regarding forward looking statement
Investments Adding Value ($ 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 statement
Revenue
| · | Increased production at record levels |
| · | Other factors impacting revenue |
| o | Lower oil & natural gas prices ($1.33 per Mcfe) |
| · | Oil & gas sales up over $13 million |
| · | RNG revenues down over $10 million, no real impact in margins |
See slide 2 regarding forward looking statement
Net Income
| · | 3Q07 Net Income of $4.5 million |
| · | Primary Drivers |
| o | Increased Production |
| o | Lower prices |
| o | Increased DD&A |
| o | $5.3 million exploration expenses |
| · | Unit expense rate per Mcfe change from 2Q07 |
| o | Oil & gas production & well ops down 10% |
| o | G&A down 9% |
| o | DD&A down 2% |
See slide 2 regarding forward looking statement
Adjusted Cash Flow from Operations
| · | Continuing to grow significantly despite lower prices |
| · | Adjusted cash flow from operations is defined as cash flow from operations before changes in assets and liabilities |
See slide 28 for GAAP Reconciliation
See slide 2 regarding forward looking statement
EBITDA
| · | Important non-GAAP measure of pre-tax cash income |
| · | Substantial growth (2002-2006 CAGR of 38% after adjustment of 2006 leasehold sale) |
| · | EBITDA = Net Income + Interest, net + Income Taxes + Depreciation, depletion, amortization |
See slide 28 for GAAP Reconciliation
See slide 2 regarding forward looking statement
Diverse Energy Market Exposure
{Graphic}
Thomas E. Riley, President
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 late 2007 |
| · | Pennsylvania acquisition - production and development opportunities |
See slide 2 regarding forward looking statement
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 statement
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 statement
Drilling Activity
{Graphic}
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 statement
Enhancements to 2007 Operational Plan
| · | Acquired 47 Bcfe of proved reserves in Southwestern Pennsylvania |
| · | Increased net Grand Valley wells |
| · | Drilling fewer net Wattenberg wells |
| o | Originally modeled Codell only completions; actual wells are multi-zone completions (J-sand, Codell and Niobrara, as appropriate) |
| o | Increased CAPEX in Codell refracs and Niobrara recompletions |
| · | Reduced activity level in ND and reallocated capital |
See slide 2 regarding forward looking statement
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 statement
Southwestern Pennsylvania Acquisition
| · | PETD closed the acquisition of Castle Gas Company assets |
| o | $53 million purchase price |
| § | $1.12 per Mcfe |
| o | Acquired majority interest in 760 natural gas wells located in southwestern Pennsylvania |
| § | Current daily production of 3,000 Mcfe/d |
| o | Highly predictable, low risk drilling |
| § | 47 Bcfe of proved reserves |
See slide 2 regarding forward looking statement
Key Value Drivers
| · | Proven Track Record |
| o | 5-year 850% return to shareholders |
| o | 66% year-over-year production growth |
| o | 55% year-over-year reserve growth |
| · | Visible Built-in-Growth |
| o | More than 1 Tcfe of 3P reserves provides significant near-term growth potential |
| o | Large multi-year, low risk drilling inventory |
| o | Recently added 47 Bcfe of proved reserves in Southwestern Pennsylvania (15.8 Bcfe producing) |
| · | Strong Financial Position |
| o | Strong balance sheet |
| o | Debt-to-cap 26% |
See slide 2 regarding forward looking statement
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 statement
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 statement
Petroleum Development Corporation
2007 Third Quarter Results
November 9, 2007
Thomas E. Riley, President
Richard W. McCullough, Chief Financial Officer
NASDAQ GSM: PETD