Calyon Securities (USA), Inc. Energy Conference

Transcription

1 Calyon Securities (USA), Inc. Energy Conference May 16, 2007 Presenters: Gene Isenberg, Chairman & CEO Denny Smith, Director, Corporate Development 1

2 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 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

3 A Conservative and Flexible Financial Position Balance Sheet Data as of March 31, 2007 ($ in millions) Actual Cash & Securities $1,501 Accounts Receivable 1,131 Working Capital (1) 2,021 Property, Plant and Equipment, Net 5,811 Total Assets Total Debt (2) Stockholders Equity Total Debt to Total Capitalization Net Debt to Capitalization Weighted Average Shares Outstanding (2) 9,580 4,005 3,832 48% 37% 285 DBRS, Fitch, Moody s and S&P AL, A-, A 3, A- Indexes S&P 500, OSX & OIH (1) Includes $550M of readily liquidatable marketable securities accounted for as long-term (2) Reflects two for one stock split effective April 18, 2006 and stock repurchases of March 31, 2006 (3) Some debt issues are unrated 3

4 ROCE Will Always Be Our Major Metric 4

5 Fleet Status as of May 11, 2007 Drilling Q07 2Q07 Avg. Avg. Actual Current Expected North America Alaska US 48 Drilling GOM Offshore Canada International Int l Land (1) Int l Offshore (1) Total Drilling W.O./Well Servicing US Lower 48 Canada Total W.O./Well Servicing

6 Elements of Forward Growth > Volume expansion with term contracts > Volume expansion in strong non-term markets > Ongoing Pricing power Internationally, US Offshore and Alaska > High degree of contracted forward income > Limited downside in North America 6

7 Increasing Rig Demand and Sophistication Limited production response with higher decline rates 7

8 Major Drivers of Growth Incremental Rigs Yet to Deploy as of May 1, 2007 > New capacity additions with long-term contracts 53 out of 112 new built drilling rigs 1 out of 40 refurbished drilling rigs > New capacity additions for shorter-term contract markets 1 out of 3 Ultra deep drilling shallow water barge rigs 6 out of 13 A/C Coiled Tubing/STEM drilling rigs 141 out of 180 top drive units (58 Nabors and 83 to Third Parties) > New capacity other markets 37 out of 81 new 500 hp Millennium workover rigs 100 out of 100 new 400 hp Millennium workover rigs 10 out of 20 new 200 hp Millennium workover rigs 8

9 PACE 750 > Programmable AC electric rig with PLC controls. > Central control center allows driller full control of: drawworks top drive mud pumps all other significant equipment > Compact and powerful. > Drills in a broad range of depths. in a variety of geographical and geological areas > Engineered to move rapidly, reducing time between wells. 46 new rigs 9

10 PACE 1,500 > Larger version of the PACE 750. > Progammable AC electric with PLC controls. > Stronger mast and substructure; with additional mud tank. > Capable of drilling deeper horizontal wells. 35 new rigs 10

11 PACE 2,000 & PACE 3,000 > Special purpose ultra-deep capacity drilling rigs. > Easily adapted to lift and roll and automated pipe handling systems. > Equipped with a system for pre-assembly of drill pipe stands. 17 new rigs 11

12 Barge 35,000' Capacity > Geared towards the ultra-deep gas prospects in the shallow GOM waters. > Designed for deep workover and/or shallow drilling. > Capable of drilling up to 35,000' in depths as shallow as seven feet. 1 existing 1 new drilling 1 new workover 12

13 Millennium Workover and Well-Servicing Rigs Series > Breakthrough in workover and well-servicing technology. > Available in 400 and 500 HP models for servicing deeper, directional wells. > Safety and efficiency features combine to make a more durable and easier-to-operate rig. 180 new rigs 13

14 Well-Servicing Rigs 200 Series > Ideal for servicing shallow, closely spaced wells in rugged terrain. > Improved visibility and greater maneuverability with: shorter wheelbase drive-in capability > Real-time performance monitoring with advanced instrumentation system. 20 new rigs 14

15 Other Businesses Growth with Pricing & Asset Additions Alaska Drilling: Increased utilization and rates of existing fleet Two new Heli-Rigs deploying late 2007 Alaska Construction: Increasing activity with renewed exploration and development Peak USA & Nabors Well Servicing Fluid Hauling: 300 New trucks, trailers, etc. and 225 Frac tanks Ryan, Epoch: Technology driven asset expansion Canrig: 140+ NBR top drives in backlog with 73% from third parties Pragma Automated Pipe Handling Equipment New proprietary K-Box system developed with EPOCH 15

16 K-Box Upgrades Mechanical and SCR Rigs to replicate much of the advantages of A/C PLC systems > Integrates suite of technologies Nabors Automatic Driller Drill Smart RIGWATCH Instrumentation Equipment condition monitoring Top Drive > Future products Choke Monitoring and Control Crown/Floor Saver Engine Monitoring 16

17 US Lower 48 Land Drilling Expanding and Upgrading the Fleet Tier Rig Type Performance Factor Number of Rigs Early 2005 EOY (1) 2007 % of 07 Fleet I New PACE % II SCR Upgraded 0.95 (2) % III SCR 0.85 (2) % Sub-Total % IV V Good Mechanical Old & Tired Mechanical 0.65 (2) % 0.45 (2) % Sub-Total % Total % 1. Excludes five rigs exporting to International for long-term contracts added if K-Box installed 17

18 US Lower 48 Land New Build Status as of 5/1/07 Canadian M-Series F-Series PACE PACE 750 PACE 1500 Total Currently Working To Be Deployed Total

19 Limited US Lower 48 Downside High Proportion of Contracted Rigs and New Rig Deployments Limit Downside Status as of 5/03/07 Actual 2006 Est Actual 2006 EOY 2007 Yet to Rig Years Rig Years Active Fleet Active Fleet Idle* Working Spot Term Commence Forward Status 1Q Act. 2Q 3Q 4Q 1Q 4Q 1Q 4Q 1Q 4Q Term contracts in force excluding renewals (In Rig Years) Incremental to 4Q06 Deployment New & Refurbishment Q Act. 2Q 3Q 4Q 1Q 4Q 1Q 4Q 1Q 4Q Number of Rigs ?? Rig Years * Includes five rigs being exported to International for long-term contracts. 19

20 US Lower 48 Well Servicing Expanding and Upgrading the Fleet Tier Rig Type 2005 Number of Rigs EOY 2008 % of 08 Fleet I New or Millennium % II Recent Refurb % Sub-Total % III Competitive % IV Old & Tired % Total % 20

21 Price Driven International Upside Expected Increases in International Volumes and Margins Should Yield a Six-Fold Increase Over Four Years 2004 Actual EBIT $89 Million 2008 Projected EBIT $500 - $550 Million Horsepower Rig Years GM/day Rig Years GM/day < $2, $6, $5, $14, $10, $22,000++ Platform 10.5 $15, $24,000++ Jack-Up 4.5 $29,000 8 $50,000++ Total

22 Shifting Income Distribution Projected as of May 3, Actual EBIT EPS of $3.54 (1) North American Gas US Lower 48 $ Implied EBIT at Consensus EPS of $3.63 $630 Percentage -24% Canada Subtotal North America U.S. Land Well-Servicing U.S. Offshore Alaska $187 $1,016 $202 $74 $19 $75 $705 $210 $90 $50-60% -31% 4% 21% 163% International $212 $390 84% Other, Oil & Gas Elimination & Corp $(32) Subtotal Other Markets $475 Total $1,491 Oil/Gas Mix 35% / 65% Effective Tax Rate 30.6% Diluted Share Count 299,827 $(85) $655 $1,360 55% / 45% 26.0% 286,145 (170)% 38% (9)% (1) Excludes 4Q 2006 non-cash adjustments to option expense for historical periods 22

23 NBR Estimates vs. PE

24 AUXILIARY INFORMATION 24

25 Margins and Activities 1Q 07 4Q 06 1Q 06 Margin (1) Rig Yrs Margin (1) Rig Yrs Margin (1) Rig Yrs US Lower 48 $9, $11, $9, US Offshore $16, , , Alaska $26, , , Canada $10, , , International $10, , , Well Servicing Rev/Hr Rig Hrs Rev/Hr Rig Hrs Rev/Hr Rig Hrs US Lower 48 $ ,088 $ ,967 $ ,768 Canada $698 97,588 $685 86,210 $ ,224 (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. 25

26 Quarterly Adjusted Income Derived from Operating Activities ($000 s) 1Q 07 4Q 06 1Q 06 US Lower 48 $172,926 $209,909 $179,731 Nabors Well Services 43,356 51,944 46,070 US Offshore 15,049 13,715 10,454 Alaska 16,567 7,793 4,242 Canada 53,128 39,593 83,102 International 66,018 62,563 37,497 26

27 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. 27

28 Non-GAAP Financial Information (continued) The following table provides a reconciliation of adjusted income derived from operating activities for our reportable segments to income before income taxes for the three months ended March 31, 2007, December 31, 2006, and March 31, 2006, using historical information determined in accordance with GAAP: (in thousands) Adjusted income derived from operating activities: Three Months Ended March 31, 2007 December 31, 2006 March 31, 2006 Contract Drilling: US Lower 48 Land Drilling $172,926 $209,909 $179,731 US Land Well-Servicing 43,356 51,944 46,070 US Offshore 15,049 13,715 10,454 Alaska 16,567 7,793 4,242 Canada 53,128 39,593 83,102 International 66,018 62,563 37,497 Subtotal Contract Drilling $367, , ,096 Oil & Gas 1,128 (3,686) 13,436 Other Operating Segments 20,808 14,177 20,567 Other Reconciling items (1) (40,027) (56,424) (24,594) Total $348, ,584 $370,505 Interest expense (13,049) (12,603) (8,055) Investment income 28,709 34,254 13,870 Gains (losses) on sales of longlived assets, impairment charges and other income (expense), net (14,038) (12,344) (4,029) Income before income taxes $350,575 $348,891 $372,291 (1) Represents the elimination of inter-segment transactions and unallocated corporate expenses. 28