raymond james 33 rd annual - s25.q4cdn.com
TRANSCRIPT
March 6, 2012
Presenter:
Denny Smith
Director, Corporate Development
Raymond James 33rd Annual Institutional Investors Conference
Forward-Looking Statements
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 “forward-looking statements” within the meaning of the
safe-harbor provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking 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 where we operate; and
• general economic conditions including the capital and credit markets.
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. Additional information concerning these and other risk factors is contained in our most recently filed annual reports on
Form 10-K, subsequent quarterly reports on Form 10-Q, recent current reports on Form 8-K, and other SEC filings.
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A Great Platform
> An unparalleled asset base
> Established worldwide infrastructure
> Supply chain advantages
> Access to virtually all major worldwide markets
> Customer relationships with most major players
> Ideal corporate structure for efficient access to capital
> Deep bench of experienced senior management
> Know-how and technology differentiators
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Nabors Global InfrastructureLargest portfolio of premium assets
Actively Marketed Rigs Only
As of December 31, 2011DRILLING INSTRUMENTATION
TOP DRIVEMANUFACTURING
755 LAND WORKOVER RIGS 499 LAND DRILLING RIGS
12 JACKUPS
�7 Drilling�5 Workover
4 BARGE RIGS 39 PLATFORM RIGS
�25 Workover/Re-Drilling�14 Drilling
733k PRESSURE
PUMPING HHP
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Nabors Global AC Rig FleetNew build rigs for US lower 48 land are only part of the Nabors story
12/31/11
To Be
Delivered Total
Alaska Drilling 3 0 3
US Lower 48 Land Drilling 119 25 144
Canada Drilling 24(1) 2 26
International Drilling 34 2 36
US Offshore Drilling 4 2 6
Total NBR 184 31 215
(1) Includes 10 AC Hybrid Coiled Tubing rigs
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Global Fleet - Cash Flow Equivalent to US Land RigsMore to Nabors than just US land drilling
Actual 4Q2011
Rig Years
Equivalent US
Lower 48 Rig Count (1)
Alaska 5.0 15
US Lower 48 216.7 217
Canada 45.2 66
International 113.2 115
Offshore GOM 10.0 16
Well Servicing - 64
Canrig - 43
SWSI 22 Crews 102
Total 638
(1) Number of US lower 48 land rigs equivalent to each division’s 4Q2011 gross margin based on NDUSA 4Q2011 average margin per day per rig of $10,922.
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Assets Strategically Positioned in Major US Unconventional Plays
Shale Plays & BasinWorking
Drilling RigsFrac
Crews CTUWell Svc
RigsFluid Svc
TrucksFrac
Tanks
Marcellus 14 4 3 27 155 720
Haynesville 32 1 - 9 43 186
Bakken/Rockies 76 11 3 84 26 323
Eagle Ford 43 4 4 33 126 588
Permian 26 3 - 92 274 1017
Barnett 3 1 - 30 95 185
Granite Wash 11 1 - 46 125 608
Other 42 - 2 227 77 100
Total 247 25 12 548 921 3727
Note: Includes 2012 scheduled new equipment deployments
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Refining Our Business
> Enhance balance sheet flexibility
> Review each Business Unit for:
– Strategic fit
– Execution effectiveness
– Capital efficiency
> Realign with Customers
– Drilling & Rig Services
– Completion & Production Services
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Re-Establish Balance Sheet FlexibilityIncreased Focus on Balance Sheet Management and Net Debt Reduction
Balance Sheet Data as of December 31, 2011 ($ Millions)
Cash & Securities 540
Accounts Receivable 1,577
Working Capital 1,286
Property, Plant and Equipment, Net 8,630
Total Assets 12,912
Total Debt 4,624
Shareholders’ Equity 5,588
Net Debt to Total Capitalization 42%
Net Debt to TTM EBITDA @ 12/31/2011 2.21x
Diluted Average Shares Outstanding 292,484
Fitch, Moody’s and S&P BBB+, Baa2, BBB
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Re-Establish Balance Sheet Flexibility
Liquidity
> Current liquidity approximately $1.0 billion
> Expect 2012 OCF to fund all capital expenditures, redeem current
debt and provide significant free cash flow
Total debt
> Weighted average coupon is 5.8%
> Interest coverage ratio approximately 8 to 1
Term debt
> 92% has maturity of 2018 or later > No financial covenants
Revolving debt
> Lines total $1.4 billion
> Rate equals Libor plus 150 bps (currently 1.75%)
> Net debt/cap covenant less than 60%
Nonetheless flexibility less than historical levels
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Re-Establish Balance Sheet Flexibility
De-levering
� Increase EBITDA to reduce net debt
� More discipline and higher hurdles for new projects
� Monetize non-performing and non-strategic assets
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Our Business Lines: An OverviewAccelerating Operating Cash Flow4Q Consolidated Run Rate exceeds Prior High and Increasing
GAAP
FY 2008 FY 2011 4Q11 Annualized
US Lower 48 $839 $703 $826
US Well Servicing 214 153 180
US Offshore 102 38 53
Alaska 74 63 49
Canada 128 171 214
International 580 397 382
Pressure Pumping 0 331 410
Oil & Gas 3 60 14
Other 95 90 97
Sub total $2,035 $2,006 $2,225
Corporate & Eliminations 163 155 175
Total $1,872 $1,851 $2,050
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Our Business Lines: An OverviewOperating Segments by Line of Business
Drilling and Rig Services
– US Lower 48 – GOM Offshore
– Canada – Ryan
– Alaska – Peak
– International – Canrig
Completion and Production Services
– US Workover and Well Servicing
– US Fluids Management and Logistics
– Canada Workover and Well Servicing
– US and Canada Pressure Pumping
Other – Oil and Gas
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Business Line & Asset Class EvaluationCriteria
> Leadership position
> Attractive investment returns
> Capable of growth or otherwise strategic
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Drilling Rigs & Services
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Drilling Rigs & ServicesUS Lower 48 Land Drilling:
Total Working Rigs:
222 now ���� 247 w/ new builds
107 ���� 127
115 ���� 120
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Drilling Rigs & Services
Shale Plays and BasinsNabors
RigsIncluding
New BuildsFrac
Crews
Marcellus 13 14 3
Haynesville/Tuscaloosa 32 32 1
Permian 26 26 3
Barnett 3 3 2
Eagle Ford 38 43 3
Woodford 3 3 1
Fayetteville 1 1 1
Granite Wash 11 11 0
Niobrara 4 4 1
Uinta 2 2 2
Bakken / Three Forks 51 70 4
Other Basins 38 38 1
Total 222 247 22
US Lower 48 Land Drilling:
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Drilling Rigs & ServicesUS Lower 48 Land Drilling - Premium Fleet Makeup
NDUSA Rig Fleet # of Rigs Util.
AC Rigs @ 12/31/11 119 100%
SCR Upgraded 65 85%
SCR 44 50%
Mechanical 41 68%
Current Total 269 83%
AC Rigs still to be deployed 25 100%
Total 294 84%
Expected % AC and AC Equivalent 71%
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Lower 48 Summary by Basin
Basin Oil/Gas Working RigsApprox.
Market Share
Marcellus Gas 13 6%
Haynesville Gas 26 13%
Bakken/Rockies Oil/Gas 71 20%
Eagle Ford Oil 41 15%
Permian Oil 28 8%
Barnett Gas 3 13%
Granite Wash Oil/Gas 18 5%
Other Oil/Gas 21 N/A
Total 221
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U.S. Lower 48 Land DrillingTerm Contracts in Force at 12/31/11
(1) Represents the quarter end number of contracts in force with no incremental contract awards in the future.
Quarter end number of rigs
subject to term contracts(1) 4Q11 1Q12 2Q12 3Q12 4Q12
3Q 2011 144 124 104 86 69
4Q 2011 186 158 131 101 75
2011 Contract Signatures 1Q11 2Q11 3Q11 4Q11
Replaced
Incremental
13 45 5 19
- 13 18 23
Total Signed 13 58 23 42
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Drilling Rigs & Services
International:
> 2011 EBITDA: $397.1MM; 2011 EBIT: $123.8MM
> 1Q12 should reflect the bottom
> 4Q11 and 1Q12 impacted by delays in contract awards, start-
ups, rig upgrades, and jackup dry docking
> 4Q rig count 113, expected 130 by EOY2012 after incremental
start ups in Saudi, Iraq, Algeria, India, SE Asia, and Colombia
> Rolling out proven technologies – ROCKIT®, ROCKIT®PILOT™,
and CRT
> Assessing development of directional drilling and pressure
pumping expertise internationally
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Drilling Rigs & Services
Canada:
> 2011 EBITDA: $170.6MM; 2011 EBIT: $94.6MM
> Very strong 4Q at $36.5MM EBIT
> ~85% of rigs are active in oil & liquids rich basins, deploying
5 additional upgraded rigs in 1Q12
> Busy winter in Horn River in anticipation of LNG export
sanctioning, dampened somewhat by recent weak gas
environment
> 2 new slant rigs deployed in oil sands in 4Q, expect to
deploy 2 additional in 1Q12
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Canada Summary by Basin
Basin Oil/GasWorking
Rigs Term ContractsApprox.
Market Share
Horn River Gas 6 4.0 24.0%
Montney Oil/Gas 8 0.0 19.0%
Duvernay Oil 13 2.0 11.0%
Oil Sands Oil 7 2.0 6.0%
Cardium Oil 11 0.0 13.0%
Saskatchewan Oil 2 0.0 2.0%
Total 47
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Canrig: A Technology Success Story> Innovation
– 200th ROCKITTM system installed in 2011
– REVITTM Stick-Slip system commercialized in 2011 – over 45 installations to date
– Over 35% of services and rentals revenue in 2011 came from new products, technologies
and services introduced the past three years
– Successfully prototyped with a Major in 2011, remote integration within automatic driller
– Received Innovation Award at 2011 OTC for Casing Running Tool
> Investment
– Acquired GE distributorship agreement for AC drive systems – exclusive in North America
– Acquired license for world-class Managed Pressure Drilling technology
> Patent Portfolio
– Filed or acquired over 100 patents (including foreign patents of same IP)
– Beginning to develop patent families, while still investing in new patents
– Successful monetization of IP portfolio
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Completion & Production Services
25
Completion & Production Services
Total Large Frac Crews: 25Including planned additions
US Pressure Pumping:
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Pressure Pumping Assets by Basin
4Q 2011 1Q 2012 EOY 2012
Pressure Pumping
CoilTubing
CementingPressure Pumping
CoilTubing
CementingPressure Pumping
CoilTubing
Cementing
Marcellus 3 - 30 4 2 30 4 3 31
Haynesville 1 - 3 1 - 3 1 - 3
Bakken/Rockies 9 - 6 10 2 6 11 3 10
Eagle Ford 4 3 3 4 3 3 4 4 8
Permian 3 - 1 3 - 1 3 - 4
Barnett 1 - - 1 - - 1 - -
Granite Wash 1 - 5 1 - 5 1 - 6
Other Lower 48 - 2 16 - 2 16 - 2 16
Canada - - - - - - 2 - -
Total 22 5 64 24 9 64 27 12 78
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Pressure Pumping Summary by Basin
Basin Oil/Gas # of Crews LTSA Spot
Approx.Market
Position
Marcellus Gas 4.0 2.0 2.0 T-4th
Haynesville Gas 1.0 0.0 1.0 T-4th
Bakken/Rockies Oil/Gas 11.0 8.0 3.0 2nd
Eagle Ford Oil/Gas 4.0 2.0 2.0 T-6th
Permian Oil 3.0 1.0 2.0 T-6th
Barnett Gas 1.0 1.0 0.0 T-5th
Granite Wash Oil 1.0 0.0 1.0 T-11th
Total 25.0 14.0 11.0
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Completion & Production Services
US Pressure Pumping:
> 2011 EBITDA: $331.1MM; 2011 EBIT: $229.1MM
> Q4 over Q3 operating income margin improved 10% or 184 BP
> Increasingly competitive in certain markets, particularly those
most active
> Currently 22 crews (733k frac HHP) ���� 27 (857.5k frac HHP) by end
of 2Q12 (including 2 in Canada)
> 72% of 2012 projected operating cash flow covered by term
contracts
> Aggressively adding coiled tubing & cementing into markets with
supply/demand imbalance
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Completion & Production Services
US Pressure Pumping:
Opportunities
> Supply chain integration into Nabors
> Material warehousing and storage economies
> Margin improvement
> Sand hauling and logistics capture of revenue
> Water management
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Well Servicing Product Lines
• 518 Well-Servicing / Workover Rigs• 30 - 24 Hour RigsRig Services
• 921 Fluid Transportation Trucks• 3727 Frac Tanks• 17 Disposal Facilities• Condensate Hauling• Water Management
Fluid Services
• Rental and Fishing Services• Cementing• Excavation/Construction• Rig Moving/Hauling - Marcellus• Plug & Abandonment (P&A)• Pipeline/Well Tending - Marcellus
Special Services
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Completion & Production Services
Operating Facilities
District
California 16
Mid-Continent 12
Rocky Mountain 16
Northeast 9
Southeast 24
Western 21
Total 98
US Well Servicing:
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Well Services Summary by Basin
Basin Well Svc Rigs Fluid Svc Trucks Frac Tanks
Bakken / Rockies 84 26 323
Granite Wash / Mississippian 46 125 608
Permian Basin 92 274 1017
Marcellus / Utica 27 155 720
Eagle Ford 33 126 588
Barnett / Haynesville 39 138 371
San Joachim / Long Beach 227 77 100
Total 548 921 3727
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Evaluate Each Business LineOil & Gas: Expeditiously monetize in an orderly and optimal manner
Cash Invested Proceeds to Date
Net Cash
Position
$2,100MM $917MM $(1,183)MM
Wholly Owned Net Acreage: (000’s Acres)
British Columbia Shales 65.2 Arkansas – Fayetteville 48.1
Alaskan North Slope 68.9 North Texas – Barnett 4.0
Colombia (Llanos Basin) 252.6 South Texas – Eagleford(1) 18.6
NFR Energy – 2011 Estimated Gross Results(2)
Reserves Proved Developed 718 Bcfe Production 158 Mmcfe/d
Proved Reserves 1,700 Bcfe EBITDA $232MM
2P Reserves 3,200 Bcfe Debt / EBITDA 3.2 X
(1) Northern Eagleford(2) Proforma for recent acquisitions - (Nabors ≈ net 49.7%)
Source: www.nfrenergy.com – Investor Presentation October 2011
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Summary
Great opportunity for Nabors and its shareholders
� Unequalled global asset quality and infrastructure
� Virtually every segment improving with good longer-term outlook
� Numerous attractive growth opportunities
Urgent action items
� Orderly monetization of Oil & Gas assets
� Optimize execution in core businesses
Other Action Items
� Optimize Intra-company synergies & technological advancements
� Improved capital allocation and ROCE
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Auxiliary Information
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Margins and Activities
(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.
4Q11 3Q11 4Q10
Margin (1) Rig Yrs Margin (1) Rig Yrs Margin (1) Rig Yrs
US Lower 48 $10,922 216.7 $10,176 201.8 $9,472 184.3
US Offshore 17,250 10.0 15,318 10.8 9,542 6.5
Alaska 29,489 5.0 26,111 4.7 43,745 6.0
Canada 12,061 45.2 10,320 41.8 9,233 39.3
International 11,065 113.2 11,992 105.3 16,392 102.1
Well Servicing Rev/Hr Rig Hrs Rev/Hr Rig Hrs Rev/Hr Rig Hrs
US Lower 48 $511 202,816 $497 205,610 $457 169,318
Canada $808 52,712 $787 49,788 $719 49,740
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Quarterly Adjusted Income (Loss)Derived from Operating Activities
($000’s) 4Q11 3Q11 4Q10
US Lower 48 $130,114 $104,877 $85,308
Nabors Well Services 24,237 22,839 12,132
US Offshore 3,422 2,457 (5,142)
Alaska 5,343 3,021 11,252
Canada 36,553 21,604 16,572
International 23,450 29,015 71,814
Pressure Pumping 76,470 65,052 54,664
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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
(loss) 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 (loss) 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
(losses) 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 (loss) derived from operating activities to
income (loss) from continuing operations 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 (loss) derived from operating activities for our reportable segments to income (loss) from continuing operations before income taxes for the three months ended December 31, 2011, September 30, 2011 and December 31, 2010, using historical information determined in accordance with GAAP:
(1) Represents the elimination of inter-segment transactions and unallocated corporate expenses.
Three Months Ended
(in thousands) December 31, 2011 September 30, 2011 December 31, 2010
Adjusted income (loss) derived from operating activities:
Contract Drilling:
US Lower 48 Land Drilling 130,114 104,877 85,308
US Land Well-Servicing 24,237 22,839 12,132
US Offshore 3,422 2,457 (5,142)
Alaska 5,343 3,021 11,252
Canada 36,553 21,604 16,572
International 23,450 29,015 71,814
Subtotal Contract Drilling 223,119 183,813 191,936
Pressure Pumping 76,470 65,052 54,644
Oil & Gas 3,400 34,909 4,138
Other Operating Segments 13,152 20,175 9,198
Other Reconciling items (1) (43,453) (34,650) (35,006)
Total 272,688 269,299 224,930
Interest expense (60,852) (58,060) (74,012)
Investment income (loss) 7,908 727 8,619
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net
(5,614) 11,607 (6,403)
Impairments and other charges (100,000) (98,072) -
Income (loss) from continuing operations before income taxes
114,130 125,501 153,134
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