presentationtext.htm

EX-99 2 presentationtext.htm PRESENTATIONTEXT presentationtext.htm

Petroleum Development Corporation

BMO Capital Markets

2009 North American Unconventional Gas Conference

January 13, 2009

NASDAQ GSM: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 quarterly 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 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.

Core Operating Regions

2007 Proved Reserves - 686 Bcfe

·	Rocky Mountains, 81%

·	Michigan Base, 4%

·	Appalachian Base, 15%

2008E Production – 38.4 Bcfe

·	Rocky Mountains, 86%

·	Michigan Base, 4%

·	Appalachian Base, 10%

Rocky Mountains

·	2007 Proved Reserves: 559 Bcfe

·	2007 Production: 23.5 Bcfe

·	2008E Production: 32.9 Bcfe

Michigan Basin

·	2007 Proved Reserves: 24 Bcfe

·	2007 Production: 1.7 Bcfe

·	2008E Production: 1.6 Bcfe

Appalachian Basin

·	2007 Proved Reserves: 103 Bcfe

·	2007 Production: 2.7 Bcfe

·	2008E Production: 3.9 Bcfe

See Slide 2 regarding Forward Looking Statements

Energy Market Exposure

Percentage of Mcfe Sold by Market (for Three Months Ended September 30, 2008)

·	Crude Oil, 17%

·	Nymex, 11%

·	Michigan, 4%,

·	Colorado Interstate Gas, 37%

·	Colorado Liquids, 2%

·	Midcontinent, 15%

·	Northern Border, 1%

·	Southern California 4%

·	San Juan Basin, 9%

·	Crude Oil, 17%

See Slide 2 regarding Forward Looking Statements

Background

•	PDC has grown substantially over the last four years:

–	250% increase in Reserves (through YE 2007)

–	280% increase in Production

–	340% increase in Net Wells Drilled

•	Large inventory of low-risk development prospects

•	Strong record of operating performance

•	Financially stable:

–	$375MM bank line with $178MM in unused capacity

–	Strong hedge position for 2009 and part of 2010

–	Anticipate 2009 drilling within projected cash flows

See Slide 2 regarding Forward Looking Statements

Improving Fundamentals

			2008
	2006	2007	1Q	2Q	3Q
Production (Bcfe)	17	28	8.5	8.8	10.2
Proved Reserves	323	686	N/A	797(1)	N/A
Realized Gas Prices(2)	$6.91	$6.52	$8.16	$9.48	$9.49
Adj. EBITDA ($ thousands)(3)	$80,285	$136,068	$43,561	$55,542	$59,116
Adj. Cash Flow from Operations ($ thousands)(3)	$29,769	$95,626	$40,388	$59,208	$59,108
Adjusted Cash Flow from Operations (/Share) (3)	$2.00	$6.44	$2.72	$4.02	$3.98
Stock Price(4)	$32-$47	$35-$61	$50-$73	$52	$26.07

(1)	The reserves noted are internal mid-year estimates

(2)	Equivalent prices including oil sales, natural gas liquids and realized derivative gains and losses. Excludes non-realized derivative gains & losses

(3)	See Slides 20 & 21 for GAAP reconciliation of Adjusted EBITDA, Adjusted Cash Flow respectively. Gain on leasehold sale in 2006 excluded.

(4)	Monthly closing ranges. Third quarter 2008 amount is the January 6, 2009 closing price.

See Slide 2 regarding Forward Looking Statements

Summary Financial Results

	2007 Annual	2008
	2007 Annual	1Q	2Q	3Q
	$/MCFE	$/MCFE	$/MCFE	$/MCFE
DD&A	2.53	2.49	2.51	2.56
G&A(1)	1.11	1.16	1.05	0.80
Lifting Cost(2)	0.90	1.13	1.13	0.94
Production Taxes	0.44	0.59	0.79	0.68

(1)	1Q 2008 includes $3.2MM and 3Q2008 includes $1.1 MM non-recurring costs associated with executive transition. The 2008 nine month G&A = $0.99/Mcfe and if non-recurring items above are excluded the nine month G&A = $0.83/Mcfe

(2)	Lifting Cost does not include production taxes.

See Slide 2 regarding Forward Looking Statements

Debt Maturity Schedule ($MM) {Graphic}

•	$375 million revolver matures November 4, 2010

•	Maturity schedule reflects:

–	Mitigation of liquidity risk

–	Diversification of funding sources

–	Revolver availability provides strong liquidity position

Bank Line: Available - $375; Drawn - $190(1)

High-Yield Bond: Drawn - $203

(1)	Drawn balance as of December 31, 2008

See Slide 2 regarding Forward Looking Statements

CAPEX Spending & Production Growth

2006 2007 2008 2009E

CAPEX Total ($MM) $146 $264 $305(1) $120-140

CAPEX Developmental ($MM) $124(2) $224 $256(1) $100-120

Organic Production Growth 20%(2) 32%(2) 38% 15%

(1)	Projected as of November 2008 for year-end actuals.

(2)	Internal estimate

See Slide 2 regarding Forward Looking Statements

2009 CAPEX

•	2009 Budget: $120-140MM range; down 50-60% from 2008 levels

–	Cash-flow funded

–	Assumed a $5.75 Mcfe gas price

–	High graded our opportunities

•	Shifting relatively more capital to our Wattenberg and NECO fields:

Basin	2008	2009E
Wattenberg	38%	47%
Piceance	48%	36%
NECO	7%	11%
Appalachian	7%	6%
	100%	100%

See Slide 2 regarding Forward Looking Statements

Hedges in Place

4Q 2008 2009 2010

Weighted Average Hedge Price

With Floors $9.45 $7.62 $8.58

With Ceilings $9.55 $9.74 $10.45

% of 9/30/08 Production 63% 71% 31%

Weighted Avg Assumed Forward Prices(1) N/A $4.85 $5.85

Blended Pricing @ 9/30/08 Production Levels N/A $6.82 $6.70

Blended Pricing @ 15% Increase in Production N/A $6.48 $6.56

(1)	Assuming forward prices for unhedged production as of January 9, 2009.

See Slide 2 regarding Forward Looking Statements

Basis Swap Transaction

•	On 12/30/2008 PDC entered into a 4-year basis swap agreement with Sempra Energy Trading, LLC (“Sempra”, acting as agent for The Royal Bank of Scotland plc)

•	The hedge insulates ±80% of PDC’s existing Rockies production from volatility between the monthly CIG delivery point price and the corresponding NYMEX Henry Hub futures price by fixing the difference at $1.88 MMBtu

•	This transaction leverages PDC’s strong banking and commodity trading relationships

See Slide 2 regarding Forward Looking Statements

Benefits of the Swap

•	The basis market has moved $0.18 MMBtu between 12/18/2008 and 01/05/2009, indicating approximately $3million/year in swap value

•	Because Sempra agreed to varying monthly volumes and PDC’s unhedged production increases in the summer (i.e. high basis differential) months, the actual value of the swap will be significantly greater if the March – September basis continues to widen as predicted by the current futures market

•	Since the swap date, several additional large transactions have widened basis even further, with recent quotes for months of Sep – Oct 2010 as wide as - $3.30 MMBtu

See Slide 2 regarding Forward Looking Statements

Production Growth {Graphic}

2006-2009 38% CAGR

2001-2006 19% CAGR

2008 Highlights

•	38.4 Bcfe Net Production

•	37% Organic Production Growth

•	Each Major Basin Exhibits Production Growth

2009 Plan

•	44.4 Bcfe Net Production

•	15% Organic Production Growth

•	Active in All Basins

See Slide 2 regarding Forward Looking Statements

2008 4Q Developments

•	Slowdown in drilling in Wattenberg & NECO relative to plan

•	Production curtailment in Piceance, due to infrastructure, anticipated through late 4th quarter – approximately 10,000 mcf/day

–	Corrected in early 2009

•	Drilling begun on first Marcellus well in WV

•	Production gains in Appalachian basin anticipated with lower line pressures and colder weather

•	Very strong production in Wattenberg

•	Startup of facility expansions in Wattenberg anticipated in mid-2009

•	Fourth Barnett well fraced early Nov – closely monitoring production/reserves/ pricing – early economic results marginal

•	Up to four Bakken tests planned on North Dakota acreage – Joint Venture – minimal capital commitments by PDC

See Slide 2 regarding Forward Looking Statements

Marcellus Shale Exploration Project {Graphic}

PDC Areas of Operation

•	PDC Operates Over 2100 Wells within the Marcellus “Fairway” Area

•	Combination of Lease, Farmout and Wellbore Ownership

•	Approximately 45K Acres within Fairway

–	35K in WV and 10K in PA

•	1 Well Drilled in WV – recently turned downline

•	1 Well Drilled in WV – waiting on completion

•	7 Additional Vertical Tests Planned in 2009 in WV and PA

See Slide 2 regarding Forward Looking Statements

2009 Outlook

•	We will place a premium on liquidity and relative balance sheet strength due to commodity price environment and financial market conditions

•	2009’s anticipated CAPEX and cash flow are comparable allowing us to project that we remain debt neutral for the year

•	Revolver liquidity should remain above $160MM and leverage and coverage measures should remain strong on a relative basis throughout the year

•	2009’s capital allocation optimizes IRR and balances risk and operational efficiencies

See Slide 2 regarding Forward Looking Statements

Maintain Focus on Increasing Shareholder Value

•	Keep our eye on the ball

–	Conservative use of leverage/hedging

–	Execute, execute, execute on development plans

–	Maintain strong operational team

•	Continue an Investor Relations and Talent Management focus

•	Cost control emphasis for continued improvement

See Slide 2 regarding Forward Looking Statements

2Q 2008 Financial Results

Appendix

Adjusted EBITDA Reconciliation ($ in thousands)

Adjusted EBITDA 2006 2007 1Q08 2Q08 3Q08

Net Income(loss) $237,772 $33,209 ($13,928) ($40,712) $129,896

Gain on Sale of Leasehold ($328,000)

Unrealized Derivative (Gain)Loss (7,252) 4,417 39,899 86,444 (172,154)

Litigation Provision --- 1,500 --- 4,195 (170)

Interest, net (5,607) 6,617 4,661 6,319 7,666

Income Taxes 149,637 20,981 (8,202) (22,809) 68,233

Depreciation 33,735 70,844 21,131 22,105 28,645

Adjusted EBITDA 0,285 $137,568 $43,561 $55,542 $59,116

See Slide 2 regarding Forward Looking Statements

Adjusted Cash Flow Reconciliation ($ in thousands)

Adjusted Cash Flow Operations 2006 2007 1Q08 2Q08 3Q08

Net Cash provided by Operating Activities $67,390 $60,304 $48,789 $18,942 $36,062

Changes in Assets & Liabilities to Operations (37,621) 35,322 (8,401) 40,266 23,046

Adjusted Cash Flow from Operations $29,769 $95,626 $40,388 $59,208 $59,108

See Slide 2 regarding Forward Looking Statements

Petroleum Development Corporation

BMO Capital Markets

2009 North American Unconventional Gas Conference

January 13, 2009

NASDAQ GSM:PETD