Petroleum Development Corporation
2009 Analyst Day
March 19, 2009
NASDAQ:PETD
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 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 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 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.
Welcome
| • | Peter Schreck ,Vice President – Finance and Treasurer |
| – | Richard W. McCullough, Chairman and CEO |
| – | Gysle R. Shellum, Chief Financial Officer |
| – | Barton R. Brookman, Senior Vice President, Exploration and Production |
See Slide 2 regarding Forward Looking Statements
Rick McCullough
Chairman & Chief Executive Officer
PDC History Snapshot
| • | Market cap of $166.7 million at 3/16/09 |
| • | Operate in the Rockies, Appalachia and Michigan |
| • | A leading producer in the Rocky Mountain region |
| • | Reported record results in 2008 and exited the year with strong balance sheet metrics and liquidity |
| • | Outstanding financial, technical and operating teams built in the past five years |
See Slide 2 regarding Forward Looking Statements
2008 Fundamentals
| | 2008 | 2007 | 2006 |
| Production (Bcfe) | 38.7 | 28.0 | 17.0 |
| Proved Reserves (Bcfe) | 753 | 686 | 323 |
Realized Gas Prices (Mcfe)(1) | $8.66 | $6.52 | $6.91 |
Adj. EBITDA ($ millions)(2) | $192.5 | $104.2 | $80.3 |
Adj. Cash Flow from Operations ($ millions)(2) | $106.0-131.0 | $95.6 | $29.8 |
Adjusted Cash Flow from Operations, per diluted share (2) | $13.48 | $6.44 | $2.00 |
Stock Price(3) | $79.09 - $11.50 | $61.91 - $35.73 | $47.44 - $32.12 |
| (1) | Equivalent prices including oil sales, natural gas liquids and realized derivative gains and losses. Excludes non-realized derivative gains & losses |
| (2) | See slides 66 and 67 for GAAP reconciliation of Adjusted EBITDA and Adjusted Cash Flow, respectively. Gain on leasehold sales excluded. |
| (3) | Hi-low range, per year. |
See Slide 2 regarding Forward Looking Statements
2009 Will Be Challenging
| • | 2008 – superior growth year |
| • | 2009 will be a challenging year |
| – | Valuable hedges - $153.5 MM MTM at 12/31/08 |
| – | CAPEX reduced 50-60%, to $120 MM |
| – | Current strong liquidity position; will monitor it closely |
| – | Bank borrowing base redetermination in April |
| – | Substantial cost reduction/operational enhancement efforts underway |
See Slide 2 regarding Forward Looking Statements
Cost Control and Operational Enhancements
| • | Implementing an internal strategic reassessment process |
| – | Measuring activities based on their contribution to shareholder value |
| – | Entire company involved |
| – | Will drive future decision making |
| • | Review of all major elements of cost |
| • | Basin by basin operational enhancement review |
| – | Costs; logistics; marketing |
See Slide 2 regarding Forward Looking Statements
Bart Brookman
Senior V.P. Exploration & Production
2008 Operations Review
See Slide 2 regarding Forward Looking Statements
Core Operating Regions {graphic}
2008 Proved Reserves – 753 Bcfe
Appalachian Basin 15%
Rocky Mountains 82%
Michigan Basin 3%
2008 Production – 38.7 Bcfe
Appalachian Basin 10%
Rocky Mountains 86%
Michigan Basin 4%
Rocky Mountains
2007 Proved Reserves: 559 Bcfe
2007 Production: 23.5 Bcfe
2008 Proved Reserves: 620 Bcfe
2008 Production: 33.2 Bcfe
Michigan Basin
2007 Proved Reserves: 24 Bcfe
2007 Production: 1.7 Bcfe
2008 Proved Reserves: 20 Bcfe
2008 Production: 1.6 Bcfe
Appalachian Basin
2007 Proved Reserves: 103 Bcfe
2007 Production: 2.7 Bcfe
2008 Proved Reserves: 113 Bcfe
2008 Production: 3.9 Bcfe
See Slide 2 regarding Forward Looking Statement
Operating Highlights {graphic}
Historical Drilling
| | Net Wells | Gross Wells |
| 2002 | 14 | 70 |
| 2003 | 30 | 111 |
| 2004 | 45 | 158 |
| 2005 | 111 | 242 |
| 2006 | 138 | 231 |
| 2007 | 278 | 349 |
| 2008 | 333 | 379 |
| 2009E | 139-150 | 155-166 |
2008 Production increased 38% to 38.7 Bcfe
2008 Proved reserves increased 10% to 753 Bcfe
2008 Drilling Activity
Gross Wells Drilled - 379
Net Wells Drilled - 333
Development - - 357
Exploratory – 22
Planned 2009 Drilling Activity
Gross Wells – 105-155
Net Wells – 89-139
See Slide 2 regarding Forward Looking Statement
Net Production {graphic}
See Slide 2 regarding Forward Looking Statement
Production By Basin – Bcfe
| Area | 2007 | 2008 | % Increase/ (Decrease) | 2009E | % Increase/ (Decrease) |
| Eastern (App/MI) | 4.4 | 5.5 | 25% | 6.0 | 9% |
| Wattenberg | 11.1 | 15.4 | 39% | 15.4 | 0% |
| Piceance | 8.2 | 12.5 | 52% | 15.4-16.4* | 23%-31% |
| NECO | 3.6 | 5.0 | 39% | 5.3-5.8 | 6%-16% |
| Other | 0.6 | 0.3 | -50% | 0.4 | 33% |
| TOTAL | 28.0 | 38.7 | 38% | 42.5-44 | 10%-14% |
*Production assumes further drilling in the Piceance in 2009. No Piceance rigs are operating currently. If 2009 prices do not justify restarting the Piceance drilling program, the Company may deploy Piceance budgeted capital expenditures to other basins.
Bcfe = One billion cubic feet of natural gas equivalent.
See Slide 2 regarding Forward Looking Statement
2008 Well Summary
Operating Area | YE2008 Gross Wells | 2008 Gross Wells Drilled | 2008 Net Wells Drilled | 2009 Gross Wells Drilled |
| Grand Valley | 285 | 62 | 54 | 0 |
| Wattenberg | 1,390 | 149 | 123 | 93 |
| NECO | 717 | 98 | 88 | 0 - 50 |
| Appalachia | 2,090 | 62 | 62 | 12 |
| Michigan | 210 | 2 | 2 | 0 |
| Other | 20 | 6 | 4 | 0 |
| Total | 4,712 | 379 | 333 | 105 - 155 |
See Slide 2 regarding Forward Looking Statement
YE2008 Reserves Total Proved By Basin {graphic}
753 Bcfe
Piceance, 373, 50%
NECO, 47, 6%
Appalachia, 113, 15%
Michigan, 20, 3%
Wattenberg, 199, 26%
Other, 1, 0%
See Slide 2 regarding Forward Looking Statement
YE2008 Proved Reserves
| • | Proved reserves improved 10% from 2007 levels |
| • | PDPs improved 6% from 2007 levels |
| • | Downward revisions of approximately 75 Bcfe due to reduced commodity pricing and increased costs |
| • | Upward operational revisions were 41 Bcfe |
| • | Extensions/additions were 139 Bcfe |
| • | Reclassified PDNPs (Recompletions and Refracs) in Wattenberg to PUDs |
| Summary Reserve Data |
| Area | 2007 YE | 2008 YE | % Growth | % Developed | % Natural Gas |
| Rockies | 559 | 620 | 11% | 38% | 86% |
| Appalachia | 103 | 113 | 10% | 65% | 100% |
| Michigan | 24 | 20 | (17)% | 100% | 99% |
| Total | 686 | 753 | 10% | 44% | 88% |
| (1) | Independent reserve engineer’s estimates |
See Slide 2 regarding Forward Looking Statement
YE2008 Proved Reserves By Basin – Bcfe
| | PDP | PDNP | PUD | Total Proved |
| Area | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 |
| Eastern (App/MI) | 83 | 73 | 22 | 21 | 22 | 39 | 127 | 133 |
| Wattenberg | 71 | 79 | 48 | 1 | 78 | 118 | 196 | 199 |
| Piceance | 84 | 107 | 8 | 6 | 202 | 260 | 294 | 373 |
| NECO | 43 | 40 | 8 | 3 | 16 | 5 | 67 | 47 |
| Other | 2 | 1 | 0 | 0 | 0 | 0 | 2 | 1 |
| TOTAL | 283 | 299 | 85 | 31 | 318 | 423 | 686 | 753 |
| % Total Proved | 41% | 40% | 12% | 4% | 46% | 56% | 100% | 100% |
Bcfe = One billion cubic feet of natural gas equivalent.
See Slide 2 regarding Forward Looking Statement
YE2008 3P Reserves By Basin – Bcfe
| | Total Proved | Proved + Probable | Proved + Probable + Possible |
Area | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 |
| Eastern (App/MI) | 127 | 133 | 127 | 146 | 127 | 156 |
| Wattenberg | 196 | 199 | 282 | 236 | 298 | 241 |
| Piceance | 294 | 373 | 444 | 485 | 499 | 538 |
| NECO | 67 | 47 | 94 | 57 | 119 | 74 |
| Other | 2 | 1 | 2 | 1 | 2 | 1 |
| TOTAL | 686 | 753 | 948 | 925 | 1,044 | 1,009 |
Bcfe = One billion cubic feet of natural gas equivalent.
See Slide 2 regarding Forward Looking Statement
F&D Costs
| | 2008 | 2007 | 2006 | 2005 |
| Acquisition of Properties | (in millions) | | | |
| Proved Properties | $13.0 | $257.3 | $0.8 | $1.6 |
| Unproved Properties | ― | 13.7 | 11.9 | 16.9 |
| Development Costs | 257.9 | 194.0 | 114.5 | 68.6 |
| Exploration Costs | | | | |
| Exploratory Drilling | 15.6 | 13.0 | 18.7 | 12.9 |
| Geological & Geophysical | 2.1 | 6.3 | 2.2 | 0.0 |
| Total Costs Incurred | $288.7 | $484.3 | $148.1 | $100.0 |
| | | | | |
| *Additions to Reserves (Bcfe) | 107.4 | 396.3 | 66.9 | 80.3 |
| F&D Cost ($/Mcfe) | 2.69 | 1.22 | 2.21 | 1.25 |
Additions to reserves = year-end proved reserves + production + dispositions to partnerships - beginning of year reserves
See Slide 2 regarding Forward Looking Statement
Acreage Inventory
| Area | Lease Gross Acres | PDC Net Acres | Net Developed Acres | Net Undeveloped Acres | State |
| Grand Valley | 7,826 | 7,826 | 2,660 | 5,166 | Colorado |
| Wattenberg | 75,919 | 67,418 | 43,458 | 23,960 | Colorado |
| NECO | 141,654 | 112,474 | 19,276 | 93,198 | Colorado/Kansas |
| Michigan | 26,793 | 23,253 | 14,795 | 8,458 | Michigan |
| New York | 19,546 | 16,612 | 0 | 16,612 | New York |
| North Dakota | 75,132 | 51,094 | 4,767 | 46,327 | North Dakota |
| Appalachian Basin | 120,745 | 115,763 | 112,989 | 2,774 | WV / PA |
| Wyoming | 19,479 | 19,253 | 95 | 19,159 | Wyoming |
| Texas Barnett | 12,490 | 9,550 | 400 | 9,150 | Texas |
| Total | 499,584 | 423,244 | 198,440 | 224,804 | |
| | | | PDC TOTAL NET | 423,244 | |
See Slide 2 regarding Forward Looking Statement
2009 CAPEX
| | 2008 | 2009 | %Change |
| Net Development Capital (MM$) | 258 | 90 to 102 | -65% to -60% |
| Exploration, Land, G&G (MM$) | 18 | 5 | -72% |
| Acquisitions | 13 | 0 | -100% |
| Miscellaneous Capital (MM$) | 34 | 13 | -62% |
| Total Net Capital (MM$) | $323 | $108 to $120 | -67% to -63% |
See Slide 2 regarding Forward Looking Statement
Operations Forecast
2008 vs. 2009
| | 2008 | 2009E | % Change |
| Total Net Production (Bcfe) | 39 | 42.5 – 44 | 10% - 14% |
| Gross Exit Rate (MMcfe/d) | 214 | 180 – 184 | -16% to -14% |
| Net Exit Rate (MMcfe/d) | 122 | 109 – 112 | -11 to -8% |
| Net Development Capital (MM$) | $258 | $90 - $102 | -65% to -60% |
| Gross Number of Drilling Projects Gross | 379 | 105 - 155 | -72 to -59% |
| Gross Number of Other Projects | 165 | 40 | -76% |
See Slide 2 regarding Forward Looking Statement
Three Region Focus
Rocky Mountains
| – | Grand Valley Field – Piceance Basin |
| – | Wattenberg Field – DJ Basin |
Appalachian Basin
Michigan Basin
See Slide 2 regarding Forward Looking Statement
Grand valley Field {graphic}
See Slide 2 regarding Forward Looking Statement
Grand valley Field {graphic}
Gross operated wells at year end - 285
Undeveloped acreage - 5,166
449 undeveloped 10 acre locations
359 PDC, 90 PDC and Partners (18 net PDC)
377 total net PDC
Number of net remaining locations
See Slide 2 regarding Forward Looking Statement
Key Economics Parameters
Grand Valley Field
| • | Reserves per well* - 1.5 Bcfe |
| • | Gross Cost Per Well - $2.5 MM |
| • | Net Revenue Interest - 70% |
| • | Operation Cost/Well/Month - $3,400 |
*Mesa type curve
See Slide 2 regarding Forward Looking Statement
2009 Proposed Development Grand Valley Field
| | 2008 | 2009 | % Change |
| Total Net Production (Bcfe) | 12.5 | 16.1 | 29% |
| Net Exit Rate (MMcfe/d) | 42.8 | 38.3 | -11% |
| Total Net Capital (MM$) | $110.7 | $33.7 | -70% |
| Drilling Projects, Gross (Net) | 62 (54) | 0 (0) | -100% |
See Slide 2 regarding Forward Looking Statement
Wattenberg Field {graphic}
See Slide 2 regarding Forward Looking Statement
Wattenberg Field {graphic}
Gross Operated wells at year end - 1,321
Undeveloped acreage - 23,960
Undeveloped locations - 1,566
754 PDC, 393 PDC and Partners (145 Net PDC)
899 total net PDC
Number of net remaining locations - 899
See Slide 2 regarding Forward Looking Statement
Key Economics Parameters
Wattenberg Field – Codell/Niobrara
| • | Reserves per well* - 0.275 Bcfe |
| • | IP rate* - 140 Mcfd, 17 Bbl/d |
| • | Gross Cost Per Well - $625K |
| • | Net Revenue Interest - 67% |
| • | Operation Cost/Well/Month - $900 |
*67W Codell/Niobrara type curve
See Slide 2 regarding Forward Looking Statement
2009 Proposed Development Wattenberg Field
| | 2008 | 2009 | % Change |
| Total Net Production (Bcfe) | 15.4 | 15.4 | 0% |
| Net Exit Rate (MMcfe/d) | 47.1 | 43.2 | -8% |
| Total Net Capital (MM$) | $107.2 | $53.1 | -50% |
| Drilling Projects, Gross (Net) | 149 (123) | 93 (72) | -38% (-41%) |
| Other Projects, Gross (Net) | 106 (102) | 0 (0) | -100% |
See Slide 2 regarding Forward Looking Statement
NECO Area {graphic}
See Slide 2 regarding Forward Looking Statement
NECO Area {graphic}
Gross operated wells at year end - 500
Undeveloped acreage - 93,198
Undeveloped locations - 289
No Partnerships
Number of Remaining Net Locations - 271
See Slide 2 regarding Forward Looking Statement
Key Economics Parameters
NECO Area
| • | Reserves per well* - 0.188 Bcfe |
| • | Gross Cost Per Well - $240K |
| • | Net Revenue Interest - 77% |
| • | Operation Cost Well/Month - $920 |
*Shallow Niobrara type curve
See Slide 2 regarding Forward Looking Statement
2009 Proposed Development NECO Area
| | 2008 | 2009E | % Change |
| Total Net Production (Bcfe) | 5.0 | 5.3 to 5.8 | 6% to 16% |
| Net Exit Rate (MMcfe/d) | 14.9 | 14.2 to 17.2 | -5% to 15% |
| Total Net Capital (MM$) | $18.1 | $0 to $12.0 | -100% to -34% |
| Drilling Projects, Gross | 98 | 0 to 50 | -100% to -49% |
See Slide 2 regarding Forward Looking Statement
Appalachian Operating Area {graphic}
See Slide 2 regarding Forward Looking Statement
Appalachian Operating Area {graphic}
Gross operated wells at year end - 2,114
Undeveloped acreage - 2,774
Undeveloped locations (No Partnerships) - 547
Number of remaining locations
See Slide 2 regarding Forward Looking Statement
Key Economics Parameters
Appalachian Basin
| • | Reserves per well* - 0.185 Bcfe |
| • | Gross Cost Per Well - $300K |
| • | Working Interest - 100% |
| • | Net Revenue Interest - 85% |
| • | Operation Cost Well/Month - $345 |
*Harrison County Devonian Shale Type Curve
See Slide 2 regarding Forward Looking Statement
2009 Proposed Development Appalachian Basin
| | 2008 | 2009 | % Change |
| Total Net Production (Bcfe) | 3.9 | 4.4 | 13% |
| Net Exit Rate (MMcfe/d) | 11.7 | 11.7 | 0% |
| Total Net Capital (MM$) | $18 | $7.1 | -61% |
| Drilling Projects, Gross (Net) | 62 (62) | 12 (12) | -81% |
| Other Projects, Gross (Net) | 21 (21) | 40 (40) | 90% |
See Slide 2 regarding Forward Looking Statement
Michigan {graphic}
See Slide 2 regarding Forward Looking Statement
Michigan {graphic}
Gross operated wells at year end - 210
Undeveloped acreage - 8,458
Undeveloped locations - 0
See Slide 2 regarding Forward Looking Statement
2009 Proposed Development Michigan Basin
| | 2008 | 2009 | % Change |
| Total Net Production (Bcfe) | 1.6 | 1.5 | -6% |
| Net Exit Rate (MMcfe/d) | 4.4 | 4.1 | -7% |
| Total Net Capital (MM$) | $0.2 | $0 | -100% |
| Drilling Projects, Gross (Net) | 0 (0) | 0 (0) | 0% |
See Slide 2 regarding Forward Looking Statement
Other Operating Areas
| – | 51,094 acres Burke County |
| – | Exploration drilling in 2009 |
| – | 9,550 acres Erath County |
| – | No planned activity 2009 |
See Slide 2 regarding Forward Looking Statement
2009 Operations Guidance
| • | 42.5–44 Bcfe total production |
| • | Capex of $108 - $120 MM |
| • | Significant Capex slowdown |
| • | Focus on drilling costs/LOE reductions |
| • | Capex expected to be in line with anticipted cash flow |
| • | Flexibility to adjust Capex to respond to market conditions |
See Slide 2 regarding Forward Looking Statement
Marcellus Shale Highlights
| • | Two vertical wells completed and on line |
| – | Initial rates from 376 Mcfd to 232 Mcfd |
| • | One vertical well completed and on flow back |
| • | One vertical well waiting on completion |
| • | Typical shale analysis being conducted |
| – | Two cores currently being evaluated |
| – | Shale indicators have provided positive feedback |
See Slide 2 regarding Forward Looking Statement
Future Plans
Marcellus Shale
| • | Drill five additional vertical tests |
| – | Evaluate greater geographic area |
| – | Continue to establish shale quality |
| • | Determine proper location for horizontal test |
| • | Establish midstream and downstream strategy for full development |
See Slide 2 regarding Forward Looking Statement
2009 Cost Management
| | Capital | Lease Operating Expense |
| | Projected Cost Reduction Per Well by July 2009 | Projected % Savings by July 2009 | Projected Cost Savings Per Month by July 2009 | Projected % Savings Per Month by July 2009 |
| Piceance | $590,000 | 22 | $176,000 | 15 |
| Wattenberg | 168,000 | 20 | 210,000 | 14 |
| NECO | 51,000 | 21 | 62,000 | 13 |
| East | 37,050 | 9 | 98,000 | 10 |
See Slide 2 regarding Forward Looking Statement
Takeaways
| • | PDC’s inventory is low risk, predictable reserve projects |
| – | 2009 Capex is dramatically reduced |
| • | Lower natural gas prices |
| • | Capital cost increases 2005 – 2008 |
| • | Capital market environment |
| • | PDC has built an exceptional technical/geoscience team over the past several years |
| – | Prepared for increased activity on existing assets |
| – | Apply organizational strength to possible acquisitions |
| • | 2009 Capex will be reduced with intensified focus on: |
| – | Capital cost improvements |
| – | Production engineering / production optimization |
| • | Marcellus shale provides production / reserve opportunity |
| – | Define opportunity in 2009 |
| – | Partial to full implementation in 2010 |
| • | PDC is proactively managing operations as the market fluctuates |
| – | Rockies rig count is dramatically reduced |
| – | Costs are improving very quickly |
| – | PDC is maintaining full operational flexibility |
| – | Every project is evaluated as market fluctuates |
See Slide 2 regarding Forward Looking Statement
Gysle Shellum
Chief Financial Officer
2008 Summary Financial Results
($ in millions, except for per share data)
| | Year Ended December 31, |
| | 2008 | 2007* |
| Income from operations | $202.3 | $60.8 |
| Net income | $113.3 | $33.2 |
| Diluted earnings (per share) | $7.63 | $2.24 |
| Production (Bcfe) | 38.7 | 28.0 |
Realized gas prices (per Mcfe) (1) | $8.66 | $6.52 |
| Unrealized hedging gains | $118.4 | ($4.4) |
| (1) | Equivalent prices including oil sales, natural gas liquids and realized derivative gains and losses. Excludes non-realized derivative gains & losses |
*2007 data includes a $33 million gain on leasehold sales.
See Slide 2 regarding Forward Looking Statement
2008 Summary Financial Results
($ in millions, except for per share data)
| | Year Ended December 31, |
| | 2008 | 2007 |
| O&G Revenues | $321.9 | $175.2 |
| O&G Production & Well Operating Costs | $78.2 | $49.3 |
O&G Operating Margin(1) | $243.7 | $125.9 |
Adjusted Net Income(2) | $44.6 | $37.5 |
Adjusted Cash Flow from Operations(2) | $200.1 | $95.6 |
Adjusted Cash Flow from Operations (per share) (2) | $13.48 | $6.44 |
| DD&A | $104.6 | $70.8 |
| G&A | $37.7 | $31.0 |
| (1) | O&G operating margin is defined as O&G sales less O&G production and well operations costs. |
| (2) | See slides 66 - 68 for GAAP reconciliation of Adjusted EBITDA, Adjusted Cash Flow and Adjusted Net Income, respectively. |
See Slide 2 regarding Forward Looking Statement
Energy Market Exposure {graphic}
Percentage of Mcfe Sold by Market (for Twelve Months Ended December 31, 2008)
Colorado Interstate Gas (CIG), 39%
Crude Oil, 16%
NYMEX, 10%
Mid Continent, 12%
San Juan Basin / Southern California, 16%
Mich-Con, 4%
Colorado Liquids, 2%
Other, 1%
See Slide 2 regarding Forward Looking Statement
Debt Maturity Schedule ($ in millions) {graphic}
| • | $375 million revolver matures November 4, 2010 |
| • | Maturity schedule reflects: |
| – | Mitigation of liquidity risk |
| – | Diversification of funding sources |
| • | As of December 31, 2008: |
| – | $231MM available liquidity |
| • | April 2009 borrowing base redetermination |
See Slide 2 regarding Forward Looking Statement
CAPEX Spending & Production Growth
| | 2008 | 2007 | 2006 |
| CAPEX Total ($MM) | $323 | $239 | $147 |
| CAPEX Developmental ($MM) | $258 | $194 | $115 |
| |
Organic Production Growth(1) | 38% | 32% | 20% |
Total Production Growth(1) | 38% | 65% | 24% |
(1) Internal estimate.
See Slide 2 regarding Forward Looking Statement
2009 Guidance
See Slide 2 regarding Forward Looking Statement
2009 Assumptions(1)
| • | Reserves, production and capital expenditures per the internal operational plan |
| • | Production taxes and direct operating costs determined on a field-by-field basis |
| • | DD&A based on field-by-field depreciation analysis |
(1) The Company does not intend to update these estimates during the year.
See Slide 2 regarding Forward Looking Statement
2009 Assumptions(1), cont’d.
| • | Revolver interest rate at pricing grid plus LIBOR spread |
| • | $203 MM Senior Notes interest yield of 12.25% |
| • | 2009 commodity pricing based on high and low NYMEX Gas/Oil cases |
| • | Differentials (NYMEX Gas/Oil) determined on field by field basis, averaged 21% / 12% for gas and oil, respectively |
| • | 50% of exploration expenditures expensed. No production or reserve impacts from exploration activities |
See Slide 2 regarding Forward Looking Statement
Derivative Positions (as of March 16, 2009, in MMBtu)
| • | PDC’s implemented hedge positions provide stable, predictable cash flows(1) |
| | | | Floors | Ceilings | Swaps |
| Index | Begin | End | Quantity (000’s) | $ Price | Quantity (000’s) | $ Price | Quantity (000’s) | $ Price |
| CIG | Jan-09 | Mar-11 | 13,798 | 6.08 | 13,798 | 9.62 | 13,050 | 6.14 |
| CIG - Basis | Apr-10 | Dec-13 | | | | | 23,168 | (1.88) |
| NYMEX – Gas | Jan-09 | Mar-12 | 4,719 | 7.88 | 4,719 | 13.78 | 6,781 | 8.37 |
| PEPL – Gas | Jan-09 | Mar-11 | 3,730 | 6.56 | 3,730 | 11.08 | 2,110 | 8.50 |
NYMEX – Oil (1) | Jan-09 | Dec-10 | | | | | 6,390 | 15.27 |
| (1) | Conversion factor for oil: 1 barrel = 6.0 MMBtu |
See Slide 2 regarding Forward Looking Statement
2009 Earnings Guidance
| | Low | High |
| | | |
| Total E&P Revenue | $233 | $274 |
| | | |
| Production Taxes | 10 | 13 |
| Operating Expenses | 61 | 61 |
| G&A | 34 | 38 |
| EBITDAX | $128 | $162 |
| | | |
| Exploration Expense | 5 | 5 |
| DD&A | 108 | 108 |
| Net Interest Expense | 34 | 33 |
| Taxes | (5) | 4 |
| Net Income | ($14) | $12 |
| Stock-based Compensation | 5 | 5 |
| DD&A | 108 | 108 |
| Exploratory / Dry Hole Cost | 5 | 6 |
| Other | 1 | (4) |
| Cash Flows from Operations | $105 | $127 |
| OP CFPS | $7.06 | $8.54 |
See Slide 2 regarding Forward Looking Statement
Adjusted EBITDA {graphic} $ in millions
2009E - $124-$153
2008 - $311
2007* - $138
| • | EBITDA represents Net Income + Interest Expense + Income Taxes + Depreciation, Depletion and Amortization |
| • | 2008’s EBITDA reflects higher prices of 30% and higher production of 38% vs. 2007 |
| • | 2009’s EBITDA reflects higher production offset by lower prices vs. 2008 |
*2007 includes a gain on sale of leaseholds of $33 MM. 2008 includes an unrealized derivative gain of $118 MM
Note: See slide 68 for GAAP reconciliation.
See Slide 2 regarding Forward Looking Statement
Adjusted Cash Flow from Operations {graphic} $ in Millions
2009E - $106-$133
2008 - $200
2007 - $96
| · | Adjusted cash flow from operations represents cash flow from operations before impact of working capital |
Note: See slide 67 for GAAP reconciliation
See Slide 2 regarding Forward Looking Statement
Costs Related to Oil and Gas Drilling (per Mcfe)
| | 2009E | 2008 | 2007 |
| Average lifting costs | $0.98 | $1.07 | $0.90 |
| DD&A (O&G properties only) | $2.44 | $2.51 | $2.37 |
See Slide 2 regarding Forward Looking Statement
2009 Guidance
Qualitative Comments
| • | Strong financial position |
| – | Conservative relative debt metrics support opportunistic growth strategy |
| – | Strong relative liquidity position |
| • | Existing reserve base provides significant growth potential |
| – | Predictable low-risk production profile |
| • | Realized prices will have greatest impact on results |
See Slide 2 regarding Forward Looking Statement
2008 Financial Results
APPENDIX
Adjusted EBITDA Reconciliation ($ in millions)
| | 2009E | 2008 | 2007 |
| | Low | High | | |
| Net income | ($14.0) | $12.0 | $113.3 | $33.2 |
| Gain on sale of leaseholds | - | - | - | (33.3) |
| Unrealized derivative (gain) loss | - | - | (118.4) | 4.4 |
| Interest, net | 34.0 | 33.0 | 27.5 | 6.6 |
| Income taxes | (5.0) | 4.0 | 61.5 | 21.0 |
| Depreciation | 108.0 | 108.0 | 104.6 | 70.8 |
| Other | 1.0 | (4.0) | 4.0 | 1.5 |
| EBITDA | 124.0 | 153.0 | 192.5 | 104.2 |
See Slide 2 regarding Forward Looking Statement
Adjusted Cash Flow Reconciliation
($ in millions)
| | 2009E | 2008 | 2007 |
Net Cash provided by Operating Activities | $105.0 - $127.0 | $139.1 | $60.3 |
Changes in Assets & Liabilities Related to Operations | $1.0 - $6.0 | 61.0 | 35.3 |
| Adjusted Cash Flow from Operations | $106.0 - $133.0 | $200.1 | $95.6 |
See Slide 2 regarding Forward Looking Statement
Adjusted Net Income Reconciliation
($ in millions)
| | 2009E | 2008 | 2007 |
| Net income | $(14) to $12 | $113.3 | $33.2 |
| Unrealized derivative (gain) loss | - | (118.4) | 4.4 |
Tax effect(1) | - | 45.7 | (1.6) |
| Other | - | 4.0 | 1.5 |
| Adjusted net income | $(14) to $12 | $44.6 | $37.5 |
1`
| (1) | Tax rate exclusive of discrete items. |
See Slide 2 regarding Forward Looking Statement
2007-2009E Financial Metrics {graphic}
Production (Bcfe)
2007 – 305
2008 – 323
2009E – 42.5-44.0
Oil& Gas Revenue ($MM)
2007 – 175
20080 - 322
2009E – 233-274
EBITDAX ($MM)
2007 – 155
2008 – 352
2009E – 128-162
CAPEX ($MM)
2007 – 305
2008 – 323
2009E – 108-120
See Slide 2 regarding Forward Looking Statement
2007-2009E Operating & Credit Metrics {graphic}
Total Operating Costs ($/Mcfe)
2007 – 6.23
2008 – 6.86
2009E – 5.07-5.27
Total Debt / Cap (%)
2007 – 37
2008 – 44
2009E – 46-49
Production Cost ($/Mcfe)
2007 – 1.76
2008 – 2.02
2009E – 1.58-1.65
Total Debt / EBITDAX(1)
2007 – 1.5
2008 – 1.1
2009E – 2.6-3.3
(1) Earnings before interest, taxes, depreciation, depletion and amortization and exploration expense
See Slide 2 regarding Forward Looking Statement
Petroleum Development Corporation
2009 Analyst Day
March 19, 2009
NASDAQ:PETD
