Tristone Capital Global Energy Forum Presentation

Tristone Capital
energie’ 08
May 13, 2008
Presenter:
Denny Smith, Director, Corporate Development
Forward Looking Statement
We often discuss expectations regarding our markets, demand for our products and services,
and our future performance in our annual and quarterly reports, press releases, and other
written and oral statements. Such statements, including statements in this document
incorporated by reference that relate to matters that are not historical facts are “forwardlooking statements” within the meaning of the safe harbor provisions of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These “forwardlooking statements” are based on our analysis of currently available competitive, financial and
economic data and our operating plans. They are inherently uncertain and investors must
recognize that events and actual results could turn out to be significantly different from our
expectations.
You should consider the following key factors when evaluating these forward-looking
statements:
• fluctuations in worldwide prices and demand for natural gas and oil;
• fluctuations in levels of natural gas and crude oil exploration and development activities;
• fluctuations in the demand for our services;
• the existence of competitors, technological changes and developments in the oilfield
services industry;
• the existence of operating risks inherent in the oilfield services industry;
• the existence of regulatory and legislative uncertainties;
• the possibility of changes in tax laws;
• the possibility of political instability, war or acts of terrorism in any of the countries in which
we do business and;
• general economic conditions.
Our businesses depend, to a large degree, on the level of spending by oil and gas companies
for exploration, development and production activities. Therefore, a sustained increase or
decrease in the price of natural gas or oil, which could have a material impact on exploration
and production activities, could also materially affect our financial position, results of
operations and cash flows.
The above description of risks and uncertainties is by no means all inclusive, but is designed
to highlight what we believe are important factors to consider.
2
A Conservative and Flexible Financial Position
Balance Sheet Data ($ in millions) as of March 30, 2008
Actual
Cash & Securities (1)
Accounts Receivable
Working Capital (2)
Property, Plant and Equipment, Net
Total Assets
Total Debt (3)
Stockholders’ Equity
Total Debt to Total Capitalization
Net Debt to Capitalization
Diluted Weighted Average Shares Outstanding
DBRS, Fitch, Moody’s and S&P
Indexes
$1,821
1,112
1,780
6,759
10,905
4,582
4,788
47%
34%
283
Al, A-, A3, BBB+
S&P 500, OSX & OIH
(1)
Includes $311M of readily liquidatable marketable securities accounted for as long term and $59.9M in cash proceeds receivable
from brokers from the sale of certain marketable equity securities that is included in other current assets.
(2)
Includes $311M of readily liquidatable marketable securities accounted for as long-term
(3)
Some debt issues are unrated
3
Fleet Status as of April 30, 2008
2005
Avg.
2006
Avg.
2007
Actual
Current
2Q08
Expected
North America
Alaska
US 48 Drilling
GOM Offshore
Canada
International
7
236
16
53
8
255
16
53
9
229
16
37
11
237
20
13
11
240
20
13
Int’l Land (1)
61
79
95
100
100
21.5
20
21
21
21
394.5
431
407
402
405
US Lower 48
424
434
391
444
420
Canada
142
147
114
63
61
566
581
505
507
481
Drilling
Int’l Offshore (1)
Total Drilling
W.O./Well Servicing
Total W.O./Well Servicing
4
Elements of Forward Growth
> Highly visible growth in International markets:
• 2007 → 2008 growth ≈ 50%
• 2004 → 2008 growth ≈ 5–6X in four years
• Majority of upside is renewals at current market rates
> Visible growth in Alaskan drilling and construction on
smaller base:
• 2006 → 2008 growth > 3X
• Two new heli-rigs and potential for more new pad rigs
• New 15,000 ft. coiled tubing/STEM drilling rig
> Visible growth in “other operating segments”:
• 2006 → 2008 2X (Ex Sea Mar)
• Strong outlook in Canrig, Ryan, and Alaska Logistics & Construction
5
Elements of Forward Growth
> U.S. Land Drilling:
• Deployment of remaining new builds
• Full realization of new rig contributions
• Contract rollovers at lower but better than expected rates
• Completing de-bugging and setting records
> U.S. Workover:
• Deployment of remaining new builds
• Further costs containment
• Millennium rigs achieving full potential
> U.S. Offshore:
• Full contribution of 2 new barge rigs in service less than 30% in
2007
• Improved workover jack-up utilization
6
US Lower 48 Land Drilling
Expanding and Upgrading the Fleet
Premium rigs constitute two-thirds of US fleet
Number of Rigs
Tier
Rig Type
Performance
Factor
Early
2005
Mid (1)
2008
% of 07
Fleet
I
New PACE
1.0
0
81
24%
II
SCR Upgraded
0.90
25
73
22%
III
SCR
0.80
110
72
21%
135
226
67%
Sub-Total
IV
Good
Mechanical
0.60
45
73
22%
V
Old & Tired
Mechanical
0.40
70
37
11%
Sub-Total
115
110
33%
Total
250
336
100%
Excludes five rigs exporting to International for long-term
7
Advances in Rigs, Bits, Muds & Directional Reducing Well Cycle Time
Typical 10,000 ft well in East Texas
2001
2008 Current Drilling Days By Rig Type
Rig Type
N/A
I
II
III
IV
V
Drilling
22
9.5
10
11
13
15
Completion
3
3
3
3
3
3
Rig Move
7
2.5
4.5
5.5
6
6
Total Days/Well
32
15
17.5
19.5
22
24
11.4
25
20
18
16
15
-----
$5,000
$8,000
$12,000
$15,000
$23,000
$18,500
$17,000
$15,000
$13,500
Well Per Year Per Rig
Customers’ Est. Daily Cost Diff.
1,000 HP Dayrate
8
Hallsville Field – East Texas
Record Breaking Well
Carthage Field, East Texas
Days vs. Depth
10
Piceance Basin Performance Chart
Nabors SSD 573 vs. 2006 Conventional Rig Average
PACE F-Series Well – Oklahoma/Mid-Continent
Days vs. Depth (3/9/2008)
High Growth Visibility – Internationally and Alaska
Actual and Implied Operating Income Distribution
*Subsidiary operating income from continuing operations before corporate expenses & inter-company consolidation
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Nabors Drilling International
Elements of Upside Potential
2006 – 2007
2007 – 2008
2008 – 2009
New Rig Start-ups
44%
56%
35%
Prior Year Start-Ups
24%
24%
27%
Contract Renewals
44%
50%
48%
Cost & Utilization %
Changes
-12%
-30%
-10%
Strong International Bid Flow
Recent and Prospective Rig Inquiries
As of March 2008
Number of Rigs
Region
South America
34
Russia & FSU
17
Middle East
10
Mexico
28
North Africa
13
Africa & Far East
10
112 +/-
Note: Bids pending, working & expected including renewals, extensions and
incremental requirements
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International and Other Provides Higher EPS Base
Largest Leverage to North America Gas Recovery Remains
Visible Growth in International, Alaska and Other
Yields Higher Results with Gas Market Recovery
2006 Actual
EBITDA
EBIT
EPS
$1,800
$1,397
$3.31(1)
Plus:
+ Visible growth in International, Alaska, and Other Segments
+ Contribution of new rigs incremental to 2006
+ US Well Service Rates up 10% from 2006 but down 10% from 3Q07
Minus:
– Margins at 80% of 2006 quarterly highs for US and Canadian Drilling
– 20% of US land drilling and workover fleet retired
2010-2011 ??
$2,800
$2,200
$5.80 +/-
2008 Consensus(2)
$1,766
$1,229
$3.04
(1)
(2)
EPS from continuing operations
Source: First Call 1/4/2008
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Summary
> 2008 EPS consensus implies trough at near record levels
- 94% of 2006 Record Results
> Recent and future results less reliant upon U.S. land performance
> Strong and visible growth in non-North American businesses
• International, Alaska, & Other Segments - CanRig, EPOCH, Ryan etc.
> Largest exposure to North American gas recovery
• US Land Drilling, US Offshore, US Well Servicing, Canadian Drilling and Well Servicing
• Pricing unlikely to be most significant driver
• Most significant driver likely to be additional new and upgraded rigs
• Nabors has largest number of high efficiency rigs able to return to service
• Currently bidding additional new rigs
> Efficiency gains with new rigs have changed the cycle permanently
• Margin spreads will track efficiency differentials
• Nabors has the largest global fleet of new & high efficiency rigs
• 151 new rigs in US, Canada, Alaska & International – 50% more than any other entity
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AUXILIARY
INFORMATION
19
Margins and Activities
4Q 07
1Q 08
1Q 07
Margin (1)
Rig Yrs
Margin (1)
Rig Yrs
Margin (1)
Rig Yrs
US Lower 48
$8,917
225.7
$9,187
224.7
$9,908
243.0
US Offshore
$13,146
16.1
$14,868
14.0
$16,830
17.2
Alaska
$24,884
10.6
$18,548
8.3
$26,160
9.5
Canada
$10,988
49.4
$12,088
33.4
$10,228
58.1
International
$13,343
117.8
$13,589
114.2
$10,834
111.6
Well
Servicing
Rev/Hr
Rig Hrs
Rev/Hr
Rig Hrs
Rev/Hr
Rig Hrs
US Lower 48
$449
259,477
$458
254,895
$451
299,088
Canada
$777
79,137
$777
71,677
$698
97,588
(1) Margin = gross margin per rig per day for the period. Gross margin is computed by subtracting direct costs
from operating revenues for the period.
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Quarterly Adjusted Income
Derived from Operating Activities
($000’s)
1Q 08
4Q 07
1Q 07
$126,871
$137,948
$172,926
Nabors Well Services
30,386
30,491
43,356
US Offshore
6,458
8,008
15,049
Alaska
17,783
8,388
16,567
Canada
41,973
24,990
53,128
International
90,650
92,282
66,018
US Lower 48
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Non-GAAP Financial Information
Within the preceding slides in this presentation, we present, both historically and on a
forward-looking basis, our adjusted income (loss) derived from operating activities, which is a
“non-GAAP” financial measure under Regulation G. The components of adjusted income
derived from operating activities are computed using amounts which are determined in
accordance with accounting principles generally accepted in the United States of America
(GAAP). Adjusted income derived from operating activities is computed by: subtracting
direct costs, general and administrative expenses, and depreciation and amortization, and
depletion expense from Operating revenues and then adding Earnings from unconsolidated
affiliates. Such amounts should not be used as a substitute to those amounts reported under
GAAP. However, management evaluates the performance of our business units and the
consolidated company based on several criteria, including adjusted income (loss) derived from
operating activities, because it believes that this financial measure is an accurate reflection of
the ongoing profitability of our company. We have provided within the table presented below
a reconciliation for the applicable historical and forward-looking periods of adjusted income
derived from operating activities to income before income taxes, which is its nearest
comparable GAAP financial measure.
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Non-GAAP Financial Information (continued)
The following table provides a reconciliation of adjusted income derived from continuing operating activities for our
reportable segments to income before income taxes for the three months ended March 31, 2008, December 31, 2007,
and March 31, 2007, using historical information determined in accordance with GAAP:
Three Months Ended
(in thousands)
March 31, 2008
December 31, 2007
March 31, 2007
Adjusted income derived from continuing operating activities:
Contract Drilling:
US Lower 48 Land Drilling
US Land Well-Servicing
US Offshore
Alaska
Canada
International
Subtotal Contract Drilling
Oil & Gas
Other Operating Segments
Other Reconciling items (1)
Total
Interest expense
Investment income
Gains (losses) on sales of longlived assets, impairment charges
and other income (expense), net
Income before income taxes
(1)
$126,871
30,386
6,458
17,783
41,973
90,650
$314,121
$137,948
30,491
8,008
8,388
24,990
92,282
$302,107
$172,926
43,356
15,049
16,567
53,128
66,018
$367,044
(4,852)
12,434
(34,550)
$287,153
(18,109)
26,182
33,763
6,643
(34,586)
$307,927
(13,467)
(7,862)
1,128
11,594
(39,739)
$340,027
(13,052)
28,709
(8,097)
$287,129
(6,120)
$280,478
(13,885)
$341,799
Represents the elimination of inter-segment transactions and unallocated corporate expenses.
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