Attached files
 Global Hunter Securities
Conference
July 18-19, 2011
Exhibit 99.1 |
 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:
$788 million (July 14, 2011)
Stock price:
$14.61 (July 14, 2011)
Average 3-month daily
trading volume:
739,849 shares
Public float*:
Approximately 54 million shares
Employees:
2,692
Headquarters:
San Antonio, Texas
Website:
www.pioneerdrlg.com
3
*Does not include effect of 6,000,000 share offering priced on close of business July
14, 2011 |
 4
Pioneer Drilling Overview |
 Pioneer Drilling Company
5
71 Drilling Rigs in 8 Locations
Approximately 9th largest contract driller
80 Well Service Rigs in 11 Locations
Approximately 7th largest well service
provider
99 Wireline Units in 21 Locations
81 cased hole
18 open hole |
 6
Leading Service Provider Across Well Life Cycle
Diversified Business and Geography Mix
TTM March 31, 2011
Total Revenue: $555 million
Total Margin: $187 million |
 Investment Considerations
Continued organic growth opportunities in core businesses: land drilling,
well services and wireline
Signed five new-build drilling term contracts for delivery in the first and
second quarters of 2012
Adding 12 well service rigs in 2011
Adding 17 wireline units in 2011
Recently opened West Texas drilling division with ten rigs drilling and four
additional rigs under contract to begin drilling late 2011
Strong contract backlog
37 rigs backed by term contracts (approximately 76% of working rigs)
Enhanced balance sheet flexibility
Equity offering of 6,000,000 shares priced on July 14, 2011, netting approximately
$82MM
Recently amended and restated credit agreement for $250mm, 5-yr, senior secured
credit facility maturing in 2016
Over 60% of Q1 revenue derived from oil/liquids-focused activity
7 |
 High Quality Drilling Fleet,
Focused on Unconventional Plays
8
Historical Fleet Growth
Drilling 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
**10 rigs drilling, 4 under contract to begin drilling by the end of 2011
16 rigs
South Texas
9 rigs
East Texas
58%
42%
49%
31%
20%
Electric
Mechanical
550-999
HP
1,000-1,499
HP
1,500-2,000
HP
9 rigs
North Dakota
14 rigs
West Texas**
3 rigs
Utah
7 rigs
Appalachia
8 rigs
Colombia
5 rigs
Oklahoma* |
 0%
20%
40%
60%
80%
100%
Pioneer
Helmerich & Payne
Patterson-UTI
Nabors
Precision (U.S.)
9
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 July 5, 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
69%
currently
(1)
Comparable Utilization Rates
69% |
 10
Modern, Efficient Drilling Fleet
35 rigs working with top drives (49%
of fleet)
16 walking/skidding systems on rigs
34 pairs of 1,300/1,600 HP mud pumps
62% of rigs have iron roughnecks
42% of rigs are electric
50 Series Rig |
 New-Builds Driving Visible Organic Growth
11
Five state-of-the-art AC rigs under construction
Rigs secured with long term contracts up to four
years
Attractive rates of return (20%+ IRR)
Ideal for drilling complex shales such as Bakken,
Eagle Ford and Marcellus |
 New-Build Features
12
State-of-the-art 550K and 750K sub & mast AC new-
builds
Integrated 500 ton top drives in mast section for
faster rig up and rig down
Crane free rig up / rig down design
30 loads on base rig for fast moves
BOP handling systems
Automatic catwalk
1,600 HP and 2,000 HP mud pumps
Latest features in rig control software
Ability to drill multi-well single-row pads and walk
easily between wells with above ground heads |
 New-Build Pad Drilling Capability
13
BOP Wrangler
Pin On Walking System
One Walker Per Corner
Accumulator/HPU Skid
Pin On Walking System
Can walk in either direction or spin the rig
Can walk with full set back of drill pipes in mast
Accumulator & HPU walks with sub
BOP handling system walks with sub |
 New-Build Advanced Electrical System
14
Festoon System to Manage Electrical Supply to Substructure
|
 Premium Well Servicing Fleet,
Established Positions in Emerging Shale Plays
15
One
of
the
newest
and
most
highly
capable
well
service
fleets
in
the
industry
Seventy-three 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
New
Milford |
 Wireline and Fishing & Rental Overview
16
Wireline Services
Open and cased-hole wireline services
Fleet of 99 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
Wireline 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 |
 17
Industry and Market Conditions |
 Resurgence in U.S. Land Rig Count
1
18
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
July 1, 2011: 1,006
Horizontal
Fall ’08 Peak: 650
July 1, 2011: 1,073 |
 Benefits of Growing Shale Plays
1
19
Oilfield service companies stand to benefit from shale production due to its lower
risk
development
and
increased
service
intensity
(up
to
3
-
5x
conventional)
Shale
gas
is
expected
to
make
up
47%
of
total
U.S.
production
in
2035
vs.
its
16%
share in 2009
(1)
Reintroduction
of
the
Majors
in
the
U.S.
market
should
result
in
greater
activity
levels
Recent U.S. Shale Investments
Growing Importance of Shale
$Millions
$40,991
12/14/2009
$12,100
7/13/2011
$4,700
5/28/2010
$3,500
6/1/2011
$3,375
11/11/2008
$3,200
11/9/2010
$2,250
12/30/2009
$1,900
9/2/2008
(1)
SOURCE:
EIA
“ANNUAL
ENERGY
OUTLOOK
2011”
APRIL
2011
U.S. NATURAL GAS PRODUCTION
1990 –
2035
(1) |
 Conclusion: Improving Oil Service Outlook
1
20
North American capital spending and activity outlook is much
improved
Upstream Spending Outlook
Well Service / Workover Jobs Outlook
Source: Spears & Associates
Source: Spears & Associates. |
 21
Financials |
 22
$177
$145
$215
$75
$103
$154 -
$157
$174 -
$186
$0
$50
$100
$150
$200
$250
2006
2007
2008
2009
2010
2011E
Q2
TTM
2011E
Q2
Ann.
Strong Revenue and Adjusted EBITDA Growth
Revenue ($ 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.
(a) Please see our Form 8K dated July 12, 2011 for further information.
$396
$417
$610
$326
$487
$606 -
$611
$675 -
$695
$0
$150
$300
$450
$600
$750
2006
2007
2008
2009
2010
2011E
Q2
TTM
2011E
Q2
Ann.
(a)
(a)
(a)
(a) |
 23
Recent Developments
New-Build Contracts
5 new-build AC drilling rigs with term contracts
Preliminary 2Q 2011 Operating Result Expectations
Drilling
rig
utilization
is
expected
to
be
between
approximately
68%
to
70%
Workover
rig
utilization
is
expected
to
be
between
approximately
89%
to
91%
Revenues are expected to be between approximately $168.8 and $173.8 million
Drilling Services is expected to be between approximately $105.0
and $108.0 million
Production Services is expected to be between approximately $63.8 and $65.8
million Net Income is expected to be between $2.6 and $4.6 million
EPS is expected to be between $0.05 and $0.08 per diluted share
Adjusted
EBITDA
is
expected
to
be
between
$43.6
million
to
$46.6
million
Capex is estimated to be between $200 and $220 million for full year 2011
Note: We have provided ranges for certain of our preliminary, estimated operating
results primarily because our quarter-end accounting close procedures for the three months ended June
30,
2011 are not
complete. As a result, there is a possibility that our final operating results
will vary materially from the preliminary estimates. Please see our Form 8K dated July 12, 2011 for further information. |
 24
Recent Developments (cont.)
Priced equity offering of 6,000,000 shares on July 14, 2011
Estimated net proceeds of $82MM
Excludes exercise of over-allotment option of 15% (900,000 shares)
Amended and Restated Credit Agreement
Increases the aggregate amount of commitments from $225 million to $250
million Extends the maturity date from August 31, 2012 to June 30, 2016
Note: We have provided ranges for certain of our preliminary, estimated operating
results primarily because our quarter-end accounting close procedures for the three months ended June
30,
2011 are not complete. As a result,
there is a possibility that our final operating results will vary materially from
the preliminary estimates. Please see our Form 8K dated July 12, 2011 for
further information. |
 Strong Liquidity and Capital Structure
25
Pro Forma Capitalization (As of March 31, 2011)
Pro Forma
$82MM Net Equity Offering
($ in millions)
March 31, 2011
Cash
$
15.3
$
55.2
Revolving
Credit
Facility
($250)
(1)
42.0
-
Sr. Unsecured Notes
240.3
240.3
Other
2.3
2.3
Total Debt
$
284.6
$
242.6
Stockholders' Equity
392.8
474.7
Total Capitalization
$
677.5
$
717.3
Liquidity
(2)
189.1
296.2
Debt
/
LTM
EBITDA
(3)
2.2x
1.9x
Debt / Total Book Capitalization
42.0%
33.8%
(1) Excludes $9.2 million of LCs outstanding. Pro-Forma for amended and
restated $250 mm credit facility. (2) Defined as remaining credit
facility capacity plus cash less LCs outstanding. (3) Total consolidated
leverage ratio as reported in form 10Q for 2011. |
 26
Appendix |
 27
Reconciliation of Adjusted EBITDA to Net Income
We define Adjusted EBITDA as earnings (loss) before interest income (expense),
taxes, depreciation, amortization, impairments, and the Colombian
Net
Equity
Tax.
Although
not
prescribed
under
GAAP,
we
believe
the
presentation
of
Adjusted
EBITDA
is
relevant
and
useful
because it helps our investors understand our operating performance and makes it
easier to compare our results with those of other companies that have
different financing, capital or tax structures. Adjusted EBITDA should not be considered in isolation from or as a
substitute for net earnings (loss) as an indication of operating
performance or cash flows from operating activities or as a measure of
liquidity. A reconciliation of net earnings (loss) to Adjusted EBITDA is included
in the table below. Adjusted EBITDA, as we calculate it, may not be
comparable to EBITDA measures reported by other companies. In addition, Adjusted EBITDA does not represent funds
available for discretionary use.
($ in millions)
Q3
2010
Q4
2010
Q1
2011
Q2
2011E
TTM
Adjusted EBITDA
34.2
37.7
38.9
43.6 - 46.6
154.4 - 157.4
Colombian Net Equity Tax
-
-
(7.3)
-
(7.3)
Depreciation & Amortization
(30.8)
(31.5)
(32.3)
(32.4)
(127.0)
Net Interest
(7.6)
(7.8)
(7.5)
(8.0)
(30.9)
Impairment Expense
-
(3.3)
-
-
(3.3)
Income Tax (Expense) Benefit
1.6
(1.0)
2.1
(0.6) - (1.6)
2.1 - 1.1
Net Income (Loss)
(2.6)
(6.0)
(6.0)
2.6 - 4.6
(12.0) - (10.0)
TTM
($ in millions)
2006
2007
2008
2009
2010
Adjusted EBITDA
176.6
144.5
214.8
74.9
103.2
Colombian Net Equity Tax
-
-
-
-
-
Depreciation & Amortization
(47.6)
(63.6)
(88.1)
(106.2)
(120.8)
Net Interest
3.6
3.3
(11.8)
(8.9)
(26.6)
Impairment Expense
-
-
(171.5)
-
(3.3)
Income Tax (Expense) Benefit
(47.7)
(27.3)
(6.1)
17.0
14.3
Net Income (Loss)
84.8
56.9
(62.7)
(23.2)
(33.3)
Fiscal Year
(a) Please see our Form 8K dated July 12, 2011 for further information.
(a)
(a) |
 28 |