Attached files
| file | filename |
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| 8-K - FORM 8-K - PIONEER ENERGY SERVICES CORP | d8k.htm |
 Jefferies & Company
May 17-18, 2011
Exhibit 99.1
“Well-positioned
for
unconventional
plays.”
Pioneer Drilling Company |
 2
Forward-looking Statements
This presentation contains various forward-looking statements and information that are based on
management’s current expectations and assumptions
about future events. Forward-looking statements are generally accompanied by words such as “estimate,” “project,”
“predict,” “expect,”
“anticipate,” “plan,”
“intend,”
“seek,”
“will,” “should,”
“goal,”
and other words that convey the uncertainty of future events and
outcomes. Forward-looking information includes, among other matters, statements regarding the
Company’s anticipated growth, quality of assets, rig
utilization rate, capital spending by oil and gas companies, production rates, the Company's
growth strategy, and the Company's international operations. Although the Company believes
that the expectations and assumptions reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations and assumptions will prove to have
been correct. Such statements are subject to certain risks, uncertainties and assumptions, including,
among others: general and regional economic conditions and industry trends; the continued strength of
the contract land drilling industry in the geographic areas where the Company operates; decisions
about onshore exploration and development projects to be made by oil and gas companies; the
highly competitive nature of the contract land drilling business; the Company’s future financial performance, including availability,
terms and deployment of capital; the continued availability of qualified personnel; changes in
governmental regulations, including those relating to the environment; the political, economic and other
uncertainties encountered in the Company's international operations and other risks,
contingencies and uncertainties, most of which are difficult to predict and many of which are
beyond our control. Should one or more of these risks, contingencies or uncertainties materialize,
or should underlying assumptions prove incorrect, actual results may vary materially from those
expected. Many of these factors have been discussed in more detail in the Company's annual
report on Form 10-K for the fiscal year ended December 31, 2010. Unpredictable or
unknown factors that the Company has not discussed in this presentation or in its filings with
the Securities and Exchange Commission could also have material adverse effects on actual results
of matters that are the subject of the forward-looking statements. All forward-looking statements
speak only as the date on which they are made and the Company undertakes no duty to update or revise
any forward-looking statements. We advise our shareholders to use caution and common sense
when considering our forward looking statements.
|
 Overview
Ticker Symbol:
PDC
Market Cap:
$712 million (May 11, 2011)
Stock price:
$13.12 (May 11, 2011)
Average 3-month daily
trading volume:
879,066 shares
Public float:
Approximately 54 million shares
Employees:
2,692
Headquarters:
San Antonio, Texas
Website:
www.pioneerdrlg.com
3 |
 4
Pioneer Drilling Overview
4 |
 Investment Considerations
34 rigs backed by term contracts (approximately 68% of working rigs)
Opened West Texas drilling division with four rigs currently drilling and
nine
additional
rigs
under
contract
to
begin
drilling
throughout
2011
Continued organic growth opportunities in core businesses: land
drilling, well services and wireline
Signed two new-build drilling term contracts for delivery in the first quarter
of 2012
Adding 12 well service rigs in 2011
Adding 17 wireline units in 2011
5 |
 6
Colombia
Overview of Pioneer
71
land
drilling
rigs
(approximately
9
th
largest
contract
driller)
78
well
service
rigs
(approximately
7
th
largest
well
service
provider)
98 wireline units (81 cased hole, 17 open hole)
Diversified Energy Services Provider
TTM March 31, 2011
Total Revenue: $555 million
Total Margin: $187 million
Service Points
Drilling Services
Well Services
Wireline
Services
Fishing & Rental
Services
PDC
HQ |
 Drilling Services-Segment Overview
7
Historical Fleet Growth
Locations
Current Rig Fleet Mix
Note: Rig counts for 2004, 2005 and 2006 represent fiscal years ended March 31,
2004, 2005 and 2006 while 2007, 2008 and 2009 represent fiscal years ended
December 31, 2007, 2008 and 2009. * Cold-stacked
18 rigs
South Texas
11 rigs
East Texas
Electric
Mechanical
550-999
HP
1,000-1,499
HP
1,500-2,000
HP
9 rigs
North Dakota
9 rigs
West Texas
3 rigs
Utah
7 rigs
Appalachia
8 rigs
Colombia
6 rigs
Oklahoma* |
 8
Strong Utilization Through the Cycles
Source: Helmerich & Payne, Patterson-UTI, & Precision Drilling
data consists of U.S. domestic utilization rates derived from Form 10-K, Form 10-Q reports, & press releases. Nabors utilization rates for worldwide land fleet obtained from
public documents and industry analysts. Helmerich & Payne Q3 2010 only
estimated based on analyst reports. Pioneer Drilling utilization rates include Colombian operations beginning Q3 2007.
(1) PDC utilization as of May 12, 2011.
Averaged 85% utilization through cycles since 2001, comparing favorably to
peers Utilization
has
rebounded
from
a
monthly
low
of
33%
in
June
2009
to
70%
currently
(1)
Comparable Utilization Rates
0%
20%
40%
60%
80%
100%
Pioneer
Helmerich & Payne
Patterson-UTI
Nabors
Precision (U.S.) |
 9
Modern, Efficient Drilling Fleet
35 rigs working with top drives (49%
of fleet)
16 walking/skidding systems on rigs
34 pairs of 1300/1600 HP mud pumps
62% of rigs have iron roughnecks
42% of rigs are electric
50 Series Rig
50 Series Rig |
 60
Series Rig 10
Mast
Traveling
Equipment
Mud Tanks
Handling
Equipment
Drawworks
Mud Pumps
Mud Cleaning
Equipment
Pipe Racks
Accumulator
Gas Buster
Choke
Manifold
SCR House
Fuel-Water
Tank
Power
Package
Suitcases |
 Well Service Fleet Overview
11
One
of
the
newest
and
most
highly
capable
well
service
fleets
in
the
industry
Seventy-one 550 HP rigs
Six 600 HP rigs
One 400 HP rig
Established in the Bakken, Fayetteville, Haynesville and Eagle Ford shales
Well Service Fleet Age
Well Service Locations
Average year in service: 2007
68%
2007 or
newer
29%
3%
Williston
Bryan
Palestine
Longview
New Iberia
El Campo
Liberty
Kenedy
Conway
Laurel
2005-2006
2002-2004 |
 Wireline and Fishing & Rental Overview
12
Wireline Services
Open and cased-hole wireline services
Fleet of 98 wireline units has an
average age of less than 6 years
Established in the Bakken, Barnett,
Marcellus, Haynesville, Niobrara, and
Eagle Ford shales
Fishing & Rental Services
Range of specialized services and
equipment that are utilized on a non-
routine basis for both drilling and well
servicing operations
Overview
Locations
Williston
Dickinson
Cut Bank
Billings
Havre
Tyler
Bossier City
Broussard
Graham
Roosevelt
Pratt
Liberal
Hays
Casper
Buckhannon
Ft. Morgan
Brighton
Wray
Woodward
Pampa
Springtown
El Campo
Wireline
Fishing & Rental
Laredo
Laurel
Victoria |
 13
Industry and Market Conditions |
 Recovery in U.S. Land Rig Count
1
14
Steady rig count improvement since the second half of 2009
Horizontal and oil rig counts have surpassed Fall 2008 peak levels
Land Rig Count
Horizontal & Oil Rig Count
Source: Baker Hughes.
Source: Baker Hughes.
Oil
Fall ’08 Peak: 442
May 6, 2011: 934
Horizontal
Fall ’08 Peak: 650
May 6, 2011: 1,038 |
 Benefits of Growing Shale Plays
15
Oilfield service companies stand to benefit from shale production due to its
lower risk development and increased service intensity (up to 3 -
5x
conventional)
Reintroduction
of
the
Majors
in
the
U.S.
market
should
result
in
greater
activity levels
Recent U.S. Shale Investments
Source:
Base
production,
Alaska,
and
LNG
import
data
–
EIA
AEO
2010.
Growing Importance of Shale
$Millions
$40,991
12/14/2009
$4,700
5/28/2010
$3,375
11/11/2008
$3,200
11/9/2010
$2,250
12/30/2009
$1,900
9/2/2008
$1,050
6/30/2009
30
35
40
45
50
55
60
65
70
Base Production (all sources)
Unconventional
Alaska
LNG imports |
 Conclusion: Improving Oil Service Outlook
16
North American capital spending outlook much improved
Upstream Spending Outlook
Well Service / Workover Jobs Outlook
Source: Spears & Associates.
Source: Spears & Associates. |
 17
Financials |
 18
$396
$417
$610
$326
$487
$555
$0
$150
$300
$450
$600
$750
2006
2007
2008
2009
2010
TTM
Q1
2011
$177
$145
$215
$75
$103
$126
$0
$50
$100
$150
$200
$250
2006
2007
2008
2009
2010
TTM
Q1
2011
Consolidated Revenue & Adjusted EBITDA
Revenue ($ millions)
Adjusted EBITDA ($ millions)
Note:
Fiscal
year
end
was
changed
from
March
31
to
December
31
effective
on
December
31,
2007;
all
data
points
reflect
calendar
year
and
trailing
twelve
months
information
derived
from
10K
and
10Q
filings. |
 Capitalization
19
($ in millions)
March 31, 2011
Cash
$
15.3
Revolving Credit Facility ($225)
(1)
42.0
Sr. Unsecured Notes
240.3
Other
2.3
Total Debt
$
284.6
Stockholders' Equity
392.8
Total Capitalization
$
677.5
Debt / LTM EBITDA
(2)
2.2x
Debt / Total Book Capitalization
42.0%
(1) Excludes $9.2 million of LCs outstanding.
(2) Total consolidated leverage ratio as reported in form 10Q for
2011. |
 Capital Expenditures
20 |
 21
Appendix |
 22
Reconciliation of Adjusted EBITDA to Net Income
We define Adjusted EBITDA as earnings (loss) before interest income (expense),
taxes, depreciation, amortization and impairments. Although not prescribed
under GAAP, we believe the presentation of Adjusted EBITDA is relevant and useful because it helps our
investors understand our operating performance and makes it easier to compare our
results with those of other companies that have different financing, capital
or tax structures. Adjusted EBITDA should not be considered in isolation from or as a substitute for net
earnings (loss) as an indication of operating performance or cash flows from
operating activities or as a measure of liquidity. A reconciliation of net
earnings (loss) to Adjusted EBITDA is included in the table below. Adjusted EBITDA, as we calculate it, may not be
comparable to EBITDA measures reported by other companies. In addition, Adjusted
EBITDA does not represent funds available for discretionary use.
($ in millions)
2006
2007
2008
2009
2010
Q1 2011
Adjusted EBITDA
176.6
144.5
214.8
74.9
103.2
31.7
Depreciation & Amortization
(47.6)
(63.6)
(88.1)
(106.2)
(120.8)
(32.3)
Net Interest
3.6
3.3
(11.8)
(8.9)
(26.6)
(7.5)
Impairment Expense
-
-
(171.5)
-
(3.3)
-
Income Tax (Expense) Benefit
(47.7)
(27.3)
(6.1)
17.0
14.3
2.1
Net Income (Loss)
84.8
56.9
(62.7)
(23.2)
(33.3)
(6.0)
($ in millions)
Q2
2010
Q3
2010
Q4
2010
Q1
2011
TTM
Adjusted EBITDA
22.0
34.2
37.7
31.7
125.6
Depreciation & Amortization
(29.6)
(30.8)
(31.5)
(32.3)
(124.2)
Net Interest
(7.1)
(7.6)
(7.8)
(7.5)
(30.0)
Impairment Expense
-
-
(3.3)
-
(3.3)
Income Tax (Expense) Benefit
4.5
1.6
(1.0)
2.1
7.2
Net Income (Loss)
(10.1)
(2.6)
(6.0)
(6.0)
(24.7)
TTM |
 23 |