THE ELEVENTH OIL & GAS CONFERENCE. August 17, Presenter: Denny Smith, Director, Corporate Development

Transcription

1 THE ELEVENTH OIL & GAS CONFERENCE August 17, 2006 Presenter: 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 forward-looking 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 June 30, 2006 Cash & Securities Accounts Receivable Working Capital (1) Property, Plant and Equipment, Net Total Assets Total Debt (2) Stockholders Equity Total Debt to Total Capitalization Net Debt to Capitalization ($ in millions) Actual $2,008 1,008 2,678 4,564 8,591 4,003 3,076 57% 39% Weighted Average Shares Outstanding (2) 304 Moody s Rating (3) A 3 Standard & Poors A- Indexes S&P 500 & OSX (1) Includes $349M of readily liquidatable marketable securities accounted for as long-term (2) Reflects two for one stock split effective April 18, 2006 and stock repurchase of May 17, 2006 (3) Some debt issues are unrated 3

4 $2.75 Billion Debt Placement Principle Terms: $2.75 Billion Senior Exchangeable Notes Due May 15, % Coupon 30% Conversion premium $45.83 strike price Exchange ratio of Shares per bond. Cash only redemption to full principle value ($45.88) Note Hedge: Nabors purchased calls at $45.83 per share which offsets any dilution above conversion premium. Warrants exercisable at $54.64 per share which effectively raises conversion premium to 55%. Proceeds: $1.0 Billion used to buy Delta (Note holder short position). Approximately 28.5 million shares repurchased at $35.25 per share. $1.57 Billion net proceeds to Nabors 4

5 Bottom Line Results $2.75 Billion convert with 2.3% effective interest rate 55% conversion premium ($54.64 per share) Concurrent repurchase of 28.5 million shares Net savings of 400 Bp s over traditional convertible Approximately $110,000,000 Affect of Share Repurchase from Convertible Accretion to annual EPS as a result of transaction:

6 6 ROCE Will Always Be Our Major Metric

7 RETURN ON AVERAGE CAPITAL EMPLOYED CALCULATION (3) 2Q06 Average Capital Annualized Return of Capital = 22% 6 Months YTD 2006 Average Capital Annualized Return on Capital = 23% ($ in millions) Actual 2Q 06 YTD 06 Net Income Add (deduct): Deferred income taxes Investment income Interest expense Losses (gains) on sales of long-lived assets, impairment charges and other expense (income), net Net operating profit after current tax Average Capital Employed (1) Total Shareholders Equity Long-term debt (including current position) Deferred taxes (net of deferred tax assets) Less: Cash, cash equivalents and other income producing investments (2) (excluding $200 million used in operations) Average capital employed $ (17) 12 4 $291 $3,444 2, (1,167) $5,411 $ (31) 20 8 $600 $3,549 2, (1,260) $5,224 (1) The amounts included in the calculations below for 2Q06 represent a two-point average of each respective item for 2Q06 calculated as the average of the balances as of June 30, 2006 and March 31, The amounts included in the calculations below for the six months ended June 30, 2006, represent a three-point average of each respective item for the six months ended June 30, 2006 calculated as the average of the balances as of June 30, 2006, March 31, 2006 and December 31, (2) Includes cash, cash equivalents and short-term investments which are liquid and available for current operations and our long-term investments which are typically liquid and redeemable within 90 days. (3) Calculations per Stern Stewart methodology. 7

8 2004 Avg. Drilling North America Alaska US 48 Drilling GOM Offshore Canada International Int l Land (1) Int l Offshore (1) Total Drilling Fleet Status as of August 11, Avg Q06 Actual Today Q07 Expected W.O./Well Servicing US Lower 48 Canada Total W.O./Well Servicing (1) Represents Nabors Net Interest in J.V. Rigs in 50%, operating rig count includes those leased from GOM Offshore (2) Represents current firm and prospective near-term contract commitments 8

9 A New Era for Nabors Acquire and consolidate Upgrade and redeploy rigs 2000? Realize pricing leverage 2005? Underwritten capacity expansion 9

10 Current and Forward Market Outlook Nabors conviction in a strong and sustainable cycle Rig demand continues to exceed supply Strategic advantages that allow Nabors to capture a disproportionate share of global incremental rig demand Nabors is second to none in technology, innovation and performance The breadth and magnitude of our opportunities are unparalleled and unprecedented 10

11 Conviction in a Strong and Sustainable Cycle Customer plans and willingness to commit to long-term rig contracts into 2010 Customer ability to assure returns with forward sales Infrastructure lead times for alternatives Enduring supply challenges in North America gas Emerging supply challenges in global oil Increasing rig intensity per BOE 11

12 Rig Intensity Per BOE is Increasing The number of U.S. gas rigs operating has tripled in the last decade, but U.S. gas production is flat to down. Current 1408 rigs 2006 YTD Average 1332 rigs 12

13 Rig Intensity Per BOE is Increasing The Middle East rig count has doubled in the last decade and will rise sharply going forward, but excess capacity has diminished Average 248 rigs 2005 Year End 262 rigs 13

14 Saudi Aramco s Ramp-up is a Good Indicator of Prospective Rig Demand Due to Rig Intensity Oil Gas Land Offshore Total June Today Working Contracted but not yet working Total Change to June x 2.7x 2.5x 7.7x 2.8x Source: Baker Hughes, Nabors 14

15 The Nature of New Rig Demand Rig demand is strong in virtually all markets worldwide led by North America Rig demand is strongest for higher specification and faster moving rigs New rigs incorporate the latest in technology and automation 15

16 Drilling Efficiency is Paramount The number of complex and sophisticated wells are increasing rapidly world-wide Horizontal and multilaterals Higher specification rigs are in strong demand Higher hydraulic horsepower Capable of moving more rapidly Equipped with latest technology and automation Same-well drilling days are improving with rig upgrades and technology advances 16

17 Drilling Efficiency Improvements East Texas Rig margins are increasing faster than drilling cost Q Average $Millions $Millions % Delta 01 Cotton Valley Carthage 9,200-10,200 Average days on well Drilling costs Completion costs Total Well Costs 20 $0.6 $0.2 $ $0.7 $0.7 $1.4 17% 225% 69% Average 1,000 HP East Texas Rig Revenue/Rig Day Margin/Rig Day Average Henry Hub Cash Price $12,127 $5,122 $3.96 $16,590 (1) $8,820 (1) $7.48 (1) 38% 72% 89% Total Well Cycle Time Average Days Drill, Complete & Move (days) Wells per year per rig Today Upgraded Rig New Rig (1) 1Q 2006 Average 17

18 Expected U.S. Land Rig Capacity Increases Land Rig Newsletter (LNRL) identifies +/- 500 rig additions through 2007 (270 new rigs and 230 reactivated rigs) 18

19 US Lower 48 Contract Status and Rollover Schedule Rig June 30, 2006 Working Spot Term Year Contract Maturities First Half n/a 36 Second Half

20 Nabors Edge in New Capacity Advantageous cost and availability of capital Advantageous operating costs Established infrastructure in 28 countries Economies of Scale Synergies among subsidiaries Advantageous capital costs of new and reactivated rigs Procuring for over 400 operating rigs yields favorable price and delivery Multiple sourcing of major components and rig delivery Advantageous delivery schedule Multiple rigs in multiple venues, quicker 20

21 Unmatched Opportunity Set As of June 30, term commitments for new build rigs to date 20 coiled tubing drilling rigs deploying through workover rigs deploying through 2007 Large volume of incremental income from top drives, pipe handling equipment, etc. Significant growth opportunities in each of our 16 operating entities Incremental investment returns averaging 20% plus 21

22 Rig Construction Program Rig Type: Offshore Land Drilling Coil Tubing Subtotal Refurbished Total Drilling U.S. Land U.S. Offshore Canada Int l Total Workover 500 HP Workover 200 HP Total Workover

23 New Rigs with Term Commitments 1,000/ As of May 8, HP 1,500 HP 2,000 HP 3,000 HP Total US Lower Canada International Africa 8 8 Middle East Latin America 2 2 Far East 2 2 Total

24 Project Economics for Drilling Rigs with Term Commitments Project Economics New Drilling Rigs Refurbished Drilling Rigs Total Estimated CapEx Estimated Annualized Operating Income Estimated ROCE (including working capital and cash taxes) EBITDA Multiple $1.5 - $1.6 Billion $ $0.46 Billion 22-23%

25 Rigs without Contracts but Excellent Prospects Projected As of May 8, 2006 Offshore GOM 1 Barge, 2 Super Sundowners Coiled Tubing Drilling Rigs New Workover Rigs Total CapEx Total Operating Income ROCE (including working capital & cash taxes) Economics $320 $125 31% 25

26 Second Quarter Rigs at Current Market Rates U.S. Lower 48 Drilling Actual 2Q06 EBIT $213 Incremental Current Market Rates 2Q06 $89 Annualized $356 International U.S. Offshore Total $287 $133 $532 Pricing power still exists in Canada, US Well Servicing, and ten other subsidiaries. 26

27 Summary of Incremental Potential New Rigs with Commitments (87 rigs) (1) Refurbished Rigs with Commitments (11 rigs) (1) New Rigs with Prospects (1) (4 offshore, 17 coiled tubing & 90 workover) current leading edge (2) Total Potential Incremental EPS per year Actual 2Q06 EPS Annualized Potential Increment to 2Q06 Annualized $348 Million 46 Million 112 Million 532 Million $1,038 Million $2.32 $3.28 (1) Reflects rigs not yet working in 2Q06 (2) Reflects difference between 2Q06 actual and current leading renewal rates 27

28 AUXILLIARY INFORMATION 28

29 MARGINS AND ACTIVITY 2Q 06 1Q 06 2Q 05 Margin (1) Rig Yrs Margin (1) Rig Yrs Margin (1) Rig Yrs US Lower 48 $10, $9, $6, US Offshore 20, , , Alaska 11, , , Canada 9, , , International 10, , , Well Servicing Rev/Hr Rig Hrs Rev/Hr Rig Hrs Rev/Hr Rig Hrs US Lower 48 $ ,961 $ ,768 $ ,718 Canada $595 61,648 $ ,224 $436 60,297 (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. 29

30 ADJUSTED INCOME DERIVED FROM OPERATING ACTIVITIES (1) ($000 s) 2Q 06 1Q 06 2Q 05 US Lower 48 $212,696 $179,731 $101,813 US Offshore 23,667 10,454 12,498 Alaska 3,384 4,242 4,159 Nabors Well Services 47,435 46,070 26,401 Canada 19,873 83, International 50,500 37,497 32,558 (1) 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 accounting principles generally accepted in the United States of America (GAAP). However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income derived from operating activities, because it believes that this financial measure is an accurate reflection of the ongoing profitability of our company. A reconciliation of this non-gaap measure to income before income taxes, which is a GAAP measure, is provided within the tables set forth on the slides titled Non-GAAP Financial Information at the end of this presentation. 30

31 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. 31

32 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, 2005, December 31, 2005 and March 31, 2006, using historical information determined in accordance with GAAP: Three Months Ended (in thousands) December 31, 2005 March 31, 2006 June 30, 2006 Adjusted income derived from operating activities: Contract Drilling: US Lower 48 Land Drilling $154,003 $179,731 $212,696 US Land Well-Servicing 32,602 46,070 47,435 US Offshore 6,391 10,454 23,667 Alaska 2,865 4,242 3,384 Canada 61,421 83,102 19,873 International 34,633 37,497 50,500 Subtotal Contract Drilling 291, , ,555 Oil & Gas 2,453 13,436 (584) Other Operating Segments 15,473 20,567 18,469 Other Reconciling items (1) (17,676) (24,594) (25,985) Total $292,165 $370, ,455 Interest expense (11,582) (8,055) (12,168) Investment income 30,886 13,870 16,728 Gains (losses) on sales of long-lived assets, impairment charges and other income (expense), net (22,662) (4,029) (4,216) Income before income taxes $288,807 $372,291 $349,799 (1) Represents the elimination of inter-segment transactions and unallocated corporate expenses. 32