EX-99.1 2 ppt20090810.htm POWER POINT PRESENTATION ppt20090810.htm
NASDAQ:PETD
Petroleum Development Corporation
2009 Second Quarter Teleconference
August 10, 2009
Richard W. McCullough, Chairman & CEO
Gysle R. Shellum, Chief Financial Officer
Barton R. Brookman, SVP Exploration & Production
 
 
 
See Slide 2 regarding Forward Looking Statements
2
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 2008 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.
Disclaimer
 
 
 
See Slide 2 regarding Forward Looking Statements
3
Rick McCullough
Chairman & Chief Executive Officer
 
 
 
See Slide 2 regarding Forward Looking Statements
Q2 2009 Corporate Update
4
 • Completed Denver Headquarters Relocation
 o Moved eight employees
 o Consolidated senior executive team
 o Consolidated all CFO functions except Accounting (remains in Bridgeport)
 o Accounting accelerated recent SEC filings (2008 10-K and 2009 10-Q’s)
 • Partnership Compliance Progress
 o PDC’s accounting department has undertaken a major initiative to bring
 existing drilling partnerships into SEC filing compliance and expects to
 bring several more into compliance in 2009
 o SEC recently approved filings on four drilling partnerships, for the three
 year period 2005 - 2007
 o Equivalent to filing 36 Form 10-Q’s and 12 Form 10-K’s
 • Completed Strategic Assessment Initiative
 
 
 
See Slide 2 regarding Forward Looking Statements
Q2 2009 Strategic Update
5
 • July 16, 2009 Denver Analyst Day Theme
 o Scale and cost control
 o Alternative capital sources - Marcellus JV
 o Financial focus - hedging
 o Diversify and increase projects - A&D
 • Announcements
 o Dewey Gerdom, VP - Eastern Operations (Marcellus)
 o Lance Lauck, SVP - Business Development
 o Hired an advisor to accelerate Marcellus JV
 
 
 
See Slide 2 regarding Forward Looking Statements
2Based on forward curve as of 6/30/09.
³Based on 6/30/09 PDP.
Strong Hedge Position
Weighted average natural gas prices
Percentage of forecasted PDP production³
2010
6
2009
 
 
 
See Slide 2 regarding Forward Looking Statements
Quarterly Realized Hedge Price
7
 
 
 
See Slide 2 regarding Forward Looking Statements
Q2 2009 Highlights
8
• Operations
 – Production in line with forecast, up 27% over Q2 2008
 
 – Continued focus on cost control and CAPEX spending
 • Drilled primarily in Wattenberg where our CAPEX costs have
 been reduced to $0.5 million range per well, resulting in an
 IRR of ~33%
 – In the six months ended June 30, 2009
 • 27% reduction in unit lifting costs vs. 2008
 • 33% reduction in production and well operations costs vs. 2008
 
 – 24 gross wells drilled in Q2 2009
 – Continuing with Marcellus development
 
 
 
See Slide 2 regarding Forward Looking Statements
Q2 2009 Highlights
• Financial
 – Adjusted cash flow was $37.7 million and adjusted net loss
 was ($3.7) million
 – Strong hedging position preserved realized prices of
 $5.87/Mcfe (hedged price of $7.51/Mcfe)
 – G&A expense included $3.9 million of non-recurring items
 – DD&A rates increased largely due to 2008 year-end reserve
 revisions
 – Available liquidity was $154 million at 6/30/09
 
 
 
See Slide 2 regarding Forward Looking Statements
Note: The revolver due in 2012 has a borrowing base size of $350 million.
Relative Balance Sheet Strength
qPDC’s leverage and coverage measures
 compare favorably to its peer group
qPDC’s leverage and coverage measures
 compare favorably to “BB” credits.
qPDC is a ‘B’ credit due to its smaller size
 and scale
qMaturity schedule reflects:
 q Mitigation of liquidity risk
 q Diversification of funding sources
Debt/Book Capitalization
Debt/Proved Reserves
Maturity Profile
Debt/LTM EBITDA
10
Revolver
Senior Notes
In $millions
Source: EnerCom, June 2009
PDC Peer Group: BBG, BRY, COG, GDP, KWK, PLLL, PVA, ROSE, WLL
10
$0.56
$0.89
 
 
 
See Slide 2 regarding Forward Looking Statements
Summary
11
• Another good quarter of Cash Flow per Share,
 Adjusted Net Income and Operating Costs
• July 16, 2009 Analyst Day Message Regarding
 Strategy
 – Introduced and provided status updates on
 four initiatives
 – Plan to share more news in the near future
• PDC Team is focused on operational enhancements
 and plans to capitalize on market recovery
 
 
 
See Slide 2 regarding Forward Looking Statements
12
Bart Brookman
Senior V.P. Exploration & Production
 
 
 
See Slide 2 regarding Forward Looking Statements
13
Core Operating Regions
Q2 2009 Production Summary
See Slide 2 regarding Forward Looking Statements
Rocky Mountains
2008 Production:  1.6 Bcfe
1st Q 2009 Production 0.3 Bcfe
2nd Q 2009 Production 0.4 Bcfe
 
Michigan Basin
2008 Production:  3.9 Bcfe
1st Q 2009 Production 1.0 Bcfe
2nd Q 2009 Production 1.0 Bcfe
Appalachian Basin
2008 Production:    33.2 Bcfe
1st Q 2009 Production 9.9 Bcfe
2nd Q 2009 Production 9.8 Bcfe
Q2 2009 Production
11.2 Bcfe
• 27% increase over 2nd
 Quarter 2008
• 123 MMcfe average daily
 production rate during Q2 2009
 
 
 
See Slide 2 regarding Forward Looking Statements
14
• Estimated 2009 production of
 43.4 Bcfe
• Actual production slightly above
 forecast
• Strong production optimization
 efforts underway
 
 
 
See Slide 2 regarding Forward Looking Statements
15
2009 Drilling Activity
• Plan 105 gross wells in 2009
• ~88% of 2009 wells drilled are
 planned for the Wattenberg
 basin
• Currently drilling 6th vertical
 Marcellus well
 
 
 
See Slide 2 regarding Forward Looking Statements
16
2009 CAPEX
 
Actual
Six Months Ended
June 30, 2009
Estimated
Six Months Ended
December 31, 2009
Estimated
Total
2009
Net Development Capital (MM$)
$53
$24
$77
Exploration, Land, G&G (MM$)
6
9
15
Acquisitions (MM$)
2
2
4
Miscellaneous Capital (MM$)
6
6
12
Total Net Capital (MM$)
$67
$41
$108
 
 
 
See Slide 2 regarding Forward Looking Statements
17
 
Q4 2008
Average Costs
Estimated
Current Costs
at July 1, 2009
$ Improvement
% Improvement
Piceance
$2,700
$2,030
$670
25%
Wattenberg
$765
$550
$215
28%
NECO
$250
$188
$62
25%
East
$413
$310
$103
25%
CAPEX Improvements
(per well cost, $ in thousands)
 
 
 
See Slide 2 regarding Forward Looking Statements
Lease Operating Expenses
18
 2009 Operating Cost Improvements
(per Mcfe)
 
Twelve Months
Ended
December 31, 2008
Three Months Ended
June 30, 2009
Six Months Ended
June 30, 2009
Year-to-Date
% Variance
2008 vs. Six Months
Ended June 30, 2009
Direct Well Expenses
$0.84
$0.41
$0.55
-34%
Indirect Well Expenses
$0.23
$0.23
$0.23
0%
Lifting Cost ($ per Mcfe)
$1.07
$0.64(1)
$0.78
-27%
 
 
 
 
 
Production Taxes
$0.48
$0.25
$0.21
-56%
Well Operations Segment
$0.15
$0.15
$0.15
0%
Overhead and Other
Production Expenses
$0.32
$0.21
$0.21
-34%
Oil & Gas Production and
Well Operations Costs
$2.02
$1.25
$1.36
-34%
(1) The Q2 2009 average lifting cost includes a benefit for the reimbursement of costs incurred in Q1 2009.
 
 
 
See Slide 2 regarding Forward Looking Statements
Q2 2009 Operating Highlights
• Marcellus Update
 – 5,000 acres added to Cambria and Indiana Counties, PA
 – Expect to complete fifth, sixth and seventh WV vertical
 wells by September 2009; an additional two PA vertical
 wells are planned in late 2009
 – Ten square mile seismic shoot underway in WV
 – Expect to drill first horizontal well in Q1 2010
• Operating one rig in the Wattenberg
• Continued capital cost and LOE reductions
• Production in-line with forecast
19
 
 
 
See Slide 2 regarding Forward Looking Statements
20
Gysle Shellum
Chief Financial Officer
 
 
 
See Slide 2 regarding Forward Looking Statements
21
Q2 2009 Highlights
• 27.4% production increase Q2 2009 over Q2 2008
 
• Realized hedging gains of $24.3 MM for Q2 2009
 
• Key financial metrics (comparison to First Quarter 2009):
 – Average realized prices (including realized gains/losses on
 derivatives) per Mcfe were $5.87 in Q2 2009, a 17%
 decrease from $7.08 per Mcfe in Q1 2009
 
 – Average Lifting Costs per Mcfe decreased 31% to $0.64 in
 Q2 2009 from $0.93 in Q1 2009(1)
 
 
(1) The Q2 2009 average lifting cost includes a benefit for the reimbursement of costs incurred in Q1 2009.
(2) See appendix for reconciliation to GAAP.
 
 
 
See Slide 2 regarding Forward Looking Statements
22
Summary Financial Results
($ in millions, except for per share data)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2009
2008
2009
2008
O&G Revenues
$41.6
$94.5
$81.3
$166.2
O&G Production & Well Operating Costs
$14.0
$21.3
$30.4
$39.5
O&G Operating Margins(1)
$27.6
$73.2
$50.9
$126.7
Net Income (Loss)
($33.1)
($40.7)
($38.8)
($54.6)
Earnings (Loss) per Diluted Share
($2.23)
($2.76)
($2.62)
($3.71)
Adjusted Net Income (Loss)(2)
($3.7)
$15.3
($.4)
$25.7
Adjusted Cash Flow from Operations(2)
$37.7
$59.2
$77.4
$99.6
Adjusted Cash Flow from Operations
(per share) (2)
$2.54
$4.02
$5.23
$6.76
DD&A
$33.8
$22.1
$68.2
$43.2
G&A
$14.8
$9.2
$26.9
$19.1
(1) O&G operating margins is defined as O&G sales less O&G production and well operations costs.
(2) See appendix for reconciliation to GAAP.
 
 
 
See Slide 2 regarding Forward Looking Statements
23
• $350 million revolver matures
 May 22, 2012
 
• Maturity schedule reflects:
 – Mitigation of liquidity risk
 
 – Diversification of funding
 sources
 
• As of June 30, 2009:
 – $218 MM drawn balance
 – $22 MM cash balance
 – $154 MM available liquidity
 
• November 2009 borrowing
 base redetermination
Debt Maturity Schedule
(as of June 30, 2009)
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
$218
$200.
5
$350
 
 
 
See Slide 2 regarding Forward Looking Statements
Energy Market Exposure
Percentage of Mcfe Sold by Market
(for Three Months Ended June 30, 2009)
 
 
 
See Slide 2 regarding Forward Looking Statements
Oil and Gas Hedges
in Place as of August 4, 2009
 
2009
2010
2011
Weighted Average Hedge Price (Mcfe)(1)
With Floors
$8.24
$8.31
$7.92
With Ceilings
$11.08
$9.71
$9.30
% of Forecasted Production(2)
69%
66%
26%
Weighted Avg Forward Price(3)
$4.86
$6.39
$7.13
Weighted Avg Price of
Forecasted Production(4)
$7.19
$7.66
$7.34
Weighted Avg Price of
Forecasted Production
Assuming 15% increase in Production
$6.89
$7.50
$7.31
(1) Excludes basis swaps from 4/2010 through 12/2013
(2) Based on 6/30/09 PDP
(3) Based on forward curves as of 6/30/2009
(4) Represents a blended price for forecasted PDP production at hedged prices and at forward prices
25
 
 
 
See Slide 2 regarding Forward Looking Statements
26
Adjusted Cash Flow
from Operations
 • Adjusted cash flow from operations is defined as cash flow
 from operations before working capital changes
Note: See appendix for reconciliation to GAAP.
Q1
Q2
Q3
Q4
$200.1
Full
Year
 
 
 
See Slide 2 regarding Forward Looking Statements
27
Adjusted EBITDA
 • Adjusted EBITDA is defined as
 Net Income + Gain on Sale of
 Leasehold + Unrealized
 Derivative Gain/Loss + Interest +
 Income Taxes + Depreciation,
 Depletion and Amortization +
 Other
 
 • 30% higher average gas sales
 price (including realized gain
 (loss) on derivatives) in 2008
 versus 2007
 
 • 2007 includes a gain on sale of
 leaseholds of $33MM
$192.5
Q3
Q4
Q2
Q1
Q2
Q1
Note: See appendix for reconciliation to GAAP.
Full
Year
 
 
 
See Slide 2 regarding Forward Looking Statements
28
Average Unit Costs Related
to Oil and Gas Drilling (per Mcfe)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2009
2008
2009
2008
Average lifting costs
$0.64(1)
$1.13
$0.79
$1.13
DD&A (O&G Properties Only)
$2.84
$2.33
$2.87
$2.32
(1) The Q2 2009 average lifting cost includes a benefit for the reimbursement of costs incurred in Q1 2009.
 
 
 
See Slide 2 regarding Forward Looking Statements
29
A P P E N D I X
2009 Financial Results
 
 
 
See Slide 2 regarding Forward Looking Statements
30
Adjusted EBITDA Reconciliation
($ in millions)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2009
2008
2009
2008
Net loss
($33.1)
($40.7)
($38.8)
($54.6)
Gain on sale of leasehold
-
-
.01
-
Unrealized derivative loss (1)
47.6
86.3
60.8
125.7
Interest, net
9.4
6.3
17.8
11.0
Income taxes (benefit)
(20.5)
(23.8)
(24.6)
(33.2)
DD&A
33.8
22.1
68.2
43.2
Other
-
4.2
2.6
4.2
Adjusted EBITDA
$37.2
$54.4
$86.0
$96.2
(1) Includes natural gas marketing activities.
 
 
 
See Slide 2 regarding Forward Looking Statements
31
Adjusted Cash Flow Reconciliation
($ in millions)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2009
2008
2009
2008
Net Cash provided by
Operating Activities
$24.8
$18.9
$60.7
$67.7
Changes in Assets & Liabilities
Related to Operations
12.9
40.3
16.7
31.9
Adjusted Cash Flow from
 Operations
$37.7
$59.2
$77.4
$99.6
 
 
 
See Slide 2 regarding Forward Looking Statements
32
Adjusted Net Income Reconciliation
($ in millions)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2009
2008
2009
2008
Net income loss
($33.1)
($40.7)
($38.8)
($54.6)
Unrealized derivative loss (1)
47.6
86.3
60.8
125.7
Tax effect
(18.1)
(34.5)
(24.2)
(49.5)
Other
-
4.2
2.6
4.2
Adjusted net income (loss)
($3.7)
$15.3
$0.4
$25.7
(1) Includes natural gas marketing activities.
 
 
 
NASDAQ:PETD
Petroleum Development Corporation
2009 Second Quarter Teleconference
August 10, 2009