Merrill Lynch Global Energy Large Cap Conference

Transcription

1 Merrill Lynch Global Energy Large Cap Conference December 2, 2008 Presenter: Denny Smith Director, Corporate Development

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. Page 2

3 A Conservative & Flexible Financial Position Balance Sheet Data ($ in millions) as of September 30, 2008 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 Fitch, Moody s and S&P Indexes Actual $1,074 1,161 1,505 7,166 10,776 4,212 4,997 44% 37% A-, Baa1, BBB+ S&P 500, OSX & OIH (1) Includes $230M of readily liquidatable marketable securities accounted for as long term and $6.1M in cash proceeds receivable from brokers from the sale of certain marketable equity securities that is included in other current assets. (2) Includes $230 M of readily liquidatable marketable securities accounted for as long-term (3) Some debt issues are unrated Page 3

4 Globally Positioned Portfolio of High-End Assets 700 LAND WORKOVER RIGS 525 LAND DRILLING RIGS 13 JACK-UPS > 8 Drilling > 5 Workover 3 BARGE RIGS 37 PLATFORM RIGS > 23 Workover/Re-Drilling > 14 Drilling DRILLING INSTRUMENTATION TOP DRIVE MANUFACTURING OILFIELD SERVICES Actively Marketed Rigs Only As of September 30, 2008 Page 4

5 Global Working Rig Fleet Status Drilling 2005 Avg Avg Actual Current 4Q08 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 As of November 25, 2008 Page 5

6 Current Environment > North America Drilling (U.S. Lower 48): Rig count still near all-time high of 273 but expected to fall off December through April. 81 new rigs currently operating and setting performance records. 32 new rig commitments scheduled to deploy 3Q08-3Q09 at margins 2x current average for legacy rigs. Expect much higher resiliency than market. > North America Drilling (Canada): Secured 2 new build commitments. 4-6 more probable. Slower Alberta activity substantially offset by Saskatchewan (Bakken) and British Colombia Shales (Horn River & Montney). Market softening overall Nabors expects year over year to be flat to down slightly. > International: Rig count and margins still improving. Expanding operations into two new areas (Romania & Kuwait). Bid prospects still strong some areas slowing EBIT expected to be +$100 million over Page 6

7 Current Environment > U.S. Offshore: 3Q08 Strong pricing & activity: margins over $20k per rig day and four additional rigs working since 2Q08. Two new MODS platform rigs in process for term commitments. Barge 100 damaged in Hurricane Gustav. Market still strong but vulnerable to slowing in jack-ups and barges. > Alaska: Increasing demand driven by accelerated recovery effort in existing fields, new field development & strong exploration. 2 new rigs deployed plus 1 under construction. 3 existing rigs undergoing upgrades for long-term contracts. Some deferral of projects possible. > Other Segments: Increasing financial significance with strong growth in Canrig, EPOCH and Ryan, potential increase of 60% 2007 over Increasing, but seasonal/volatile, activity and pricing in Alaska JVs. Page 7

8 Upside Drivers/Downside Mitigators > Higher overall resiliency to market down turns > New rig additions: 190 new rigs globally by mid 2010 Increased weighting to higher margin rigs U.S. Lower 48 land, International, Alaska and US Offshore > International growth > Alaska growth > Oil & Gas growth > Other segments growth Page 8

9 Largest Global New Rig Additions New Build Commitments ( ) Significant Further Potential Land Offshore Coil Barge Drilling Tubing Rigs Jack-Up Platform Total US Lower * 115 US Offshore International ** 43 Alaska Canada Total Includes new build commitments still to be deployed *Note: Includes one rig working for Nabors Well Services **Note: Platform-type rig mounted inside drillship Page 9

10 Nabors USA Rig Fleet Transition New Technology Financed Term - Contracts Mechanical SCR AC August % 53% 0% August % 34% 33% 67% of Fleet Page 10

11 PACE Rig Fleet Growth Primarily Driven by Unconventional Plays 106 out of 113 PACE Rigs working in Shale developments Bakken 6 Piceance/Pinedale 25 Barnett 14 Woodford/Fayetteville 16 Haynesville/Bossier - 45 Page 11

12 Record Breaking Well - Anadarko Carthage, TX Page 12

13 Piceance Basin Nabors SSD 573 vs. 06 Conventional Rig Average Page 13

14 NBR PACE 101 1,000 HP Record Breaking Well Wamsutter June 08 > Nabors Rig 101 eclipsed both the previous directional & vertical records for all operators in the field > Previous best well stood since March 2005 Nabors PACE 2007 Field Average Rig 101 Record Well Change Days to 10k feet % Well Cycle Time (days) % Well Non Productive Time % 16.30% 2.10% -87% Page 14

15 US Lower 48 Land Drilling Expanding and Upgrading the Fleet Premium rigs constitute two-thirds of US fleet Tier Rig Type Performance Factor Early 2005 Mid 2009 % of Fleet I New PACE % II SCR Upgraded % III SCR % Sub-Total A/C & SCR % IV Efficient Mechanical % V Legacy Mechanical % Sub-Total Mech % Total % Page 15

16 New Technologies in Rigs, Bits, Muds & Directional Tools Have improved Well Cycle Times Substantially Rig Type: I II III IV V Drilling Completion Rig Move Total Days/Well Well Per Year/Rig Est. Daily Cost Diff $8,500 $13,300 $18,100 $23,000 1,000 HP Dayrate $23,000 $18,500 $17,000 $15,000 $13,500 Page 16

17 Increasing Rig Demand & Sophistication Limited Production Response with Higher Decline Rates Page 17

18 US Lower 48 Land Margins Volatile But Steadily Increasing As of October 2008 Page 18

19 U.S. Lower 48 Land Drilling Term Contracts in Force at September 30, 2008 (1) 3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 # of rigs subject to term contracts Q08 Annualized FY2009 FY2010 EBIT - $Millions $540 $360 $320 (1) Represents the minimum number of contracts in force with no incremental contract awards in the future. Page 19

20 International Margins & Rig Count Three-fold Increase in Seven Years & Inflecting Upwards Page 20

21 International Market Share Growth 14% 12% 10% 8% 6% 4% 2% 0% 1Q06 4Q05 3Q05 2Q05 1Q05 4Q04 3Q04 2Q04 1Q04 3Q06 2Q06 3Q07 2Q07 1Q07 4Q06 3Q08 2Q08 1Q08 4Q07 NDIL Rig Years Nabors Market Share 21

22 Nabors Drilling International Elements of Upside Potential Actual Consensus Implied Consensus Implied Y/Y increase in EBIT $123 Million +/- $90 Million +/- $100 Million New Rig Start-ups 44% 49% 28% Prior Year Start-Ups 24% 23% 56% Contract Renewals 44% 65% 31% Cost & Utilization % Changes -12% -37% -15% Sources of year-over-year incremental % change in EBIT Page 22

23 Strong International Bid Flow Recent and Prospective Rig Inquiries Region Number of Rigs South America Russia & FSU Middle East Mexico North Africa Africa & Far East /- Note: Bids pending, working & expected including renewals, extensions and incremental requirements As of September 2008 Page 23

24 High Growth Visibility Internationally and Alaska Actual and Implied Operating Income Distribution *Subsidiary operating income from continuing operations before corporate expenses & inter-company consolidation Page 24

25 High Growth Visibility Operating Income 25 $3.10 $2.70 Subsidiary operating income from continuing operations before corporate expenses and inter-company consolidation (000 s)

26 AUXILIARY INFORMATION Page 26

27 Margins and Activities 3Q 08 2Q 08 3Q 07 Margin (1) Rig Yrs Margin (1) Rig Yrs Margin (1) Rig Yrs US Lower 48 $10, $8, $8, US Offshore 18, , , Alaska 17, , , Canada 7, , , International 15, , , Well Servicing Rev/Hr Rig Hrs Rev/Hr Rig Hrs Rev/Hr Rig Hrs US Lower 48 $ ,680 $ ,101 $ ,084 Canada $675 67,141 $703 40,257 $702 72,593 (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. Page 27

28 Quarterly Adjusted Income Derived from Operating Activities ($000 s) 3Q 08 2Q 08 3Q 07 US Lower 48 $176,819 $134,322 $130,761 Nabors Well Services 42,433 31,468 42,291 US Offshore 18,456 17,983 9,245 Alaska 10,159 13,466 4,214 Canada 13,396 (14,326) 16,920 International 111, ,752 88,574 Page 28

29 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. Page 29

30 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 September 30, 2008, June 30, 2008 and September 30, 2007, using historical information determined in accordance with GAAP: (in thousands) Adjusted income derived from continuing operating activities: Contract Drilling: US Lower 48 Land Drilling $176,819 US Land Well-Servicing 42,433 US Offshore 18,456 Alaska 10,159 Canada 13,396 International 111,048 Subtotal Contract Drilling 372,311 Oil & Gas 17,577 (1,645) 17,868 Other Operating Segments 18,375 19,006 10,297 Other Reconciling items (1) (42,945) (36,117) (32,837) Total 365, , ,333 Interest expense (25,506) (21,676) (13,450) Investment income (22,235) 25,057 (27,466) (Losses) gains on sales of longlived assets, impairment charges and other (expenses) income, net (10,875) (3,158) (30,524) Income from continuing operations before income taxes September 30, 2008 $306,702 (1) Represents the elimination of inter-segment transactions and unallocated corporate expenses. Page 30 Three Months Ended June 30, 2008 $134,322 31,468 17,983 13,466 (14,326) 101, ,665 $266,132 September 30, 2007 $130,761 42,291 9,245 4,214 16,920 88, ,005 $215,893