Lehman Brothers CEO Energy/Power. Conference. September 6, Presenter: Denny Smith, Director, Corporate Development

Transcription

1 Lehman Brothers 2006 CEO Energy/Power Conference September 6, 2006 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 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 Bottom Line Results $2.75 Billion convert with 2.3% effective pre-tax interest rate 55% conversion premium ($54.64 per share) Concurrent repurchase of 28.5 million shares Net savings of 350+ Bp s over straight debt Approximately $96 million Effect of Share Repurchase from Convertible Accretion to annual EPS as a result of transaction:

5 ROCE Will Always Be Our Major Metric 5

6 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. 6

7 Drilling 2004 Avg Avg. 2Q06 Actual Today 1Q07 Expected 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 30, 2006 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 A New Era for Nabors Acquire and consolidate Upgrade and redeploy rigs 2000? Realize pricing leverage 2005? State-of-the-Art capacity expansion 8

9 Current and Forward Market Outlook North America Still increasing pricing Still increasing rig count Still substantial interest in new builds International Accelerating rates Accelerating utilization Accelerating deployments in 2006 Accelerating deployments in 2007 Strong bid flow, numerous prospective multi-rig projects Other Businesses Pricing and volume increases continue 9

10 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 10

11 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 11

12 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 12

13 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 13

14 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 14

15 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 15

16 Drilling Efficiency Improvements East Texas Upgraded & New Rigs Are Mitigating F&D Costs 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 $17,690 (1) $9,450 (1) $6.51 (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) 2Q 2006 Average 16

17 Expected U.S. Land Rig Capacity Increases Land Rig Newsletter (LNRL) identifies +/- 500 rig additions through 2007 (270 new rigs and 230 reactivated rigs) 17

18 Nabors Edge in New Capacity Established market leading culture in HSE 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 nearly 450 operating rigs yields favorable price and delivery Multiple sourcing of major components and rig delivery Advantageous delivery schedule Multiple rigs in multiple venues, quicker 18

19 2005 through today Unmatched Opportunity Set 104 term commitments for new build rigs to date 11 Term commitments for refurbished land rigs 4 Incremental offshore rigs (2 barges & 2 Super Sundowner platform rigs) 20 A/C coiled tubing/stem drilling rigs deploying through new workover rigs deploying through 2008 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 19

20 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%

21 Rigs without Contracts but Excellent Prospects Projected As of May 8, 2006 Offshore GOM 2 Barge, 2 Super Sundowners Coiled Tubing Drilling Rigs New Workover Rigs Total CapEx Total Operating Income ROCE (including working capital & cash taxes) Economics $410 $150 30% 21

22 Second Quarter Rigs at Current Market Rates U.S. Lower 48 Drilling International Actual 2Q06 EBIT $ Incremental Current Market Rates 2Q06 $90 80 Annualized $ U.S. Offshore Total $288 $178 $712 Pricing power still exists in Canada, US Well Servicing, and ten other subsidiaries. 22

23 Summary of Incremental Potential Incremental Effects to 2Q06 Results New Rigs with Commitments (87 rigs) Refurbished Rigs with Commitments (11 rigs) Potential Increment to 2Q06 Annualized $348 Million 46 Million New Rigs with Prospects (4 offshore, 17 coiled tubing & 90 workover) current leading edge (assume only 50%) Total Potential Incremental EPS per year Actual 2Q06 EPS Annualized 150 Million 356 Million $900 Million $2.11 $3.28 Accretion of Convertible Issue $.56 Imputed Annualized EPS Run Rate (1) $5.95 (1) Potential results excluding 3Q06 and further pricing and capacity increases 23

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

25 Unprecedented Visibility A historically high level of contracted income 2006 Now 2007 Projected US Lower 48 Land Drilling 52% 44% 55% Total Consolidate 49% 40% 57% (Percent of projected operating income subject to term contracts) 25

26 Continually Increasing Estimates Compressing PE 26

27 The Way We See It! We are acutely aware that there appear to be two distinct rig markets, the one which actually exists and the one that the majority of analysts expect to develop out of the current gas storage overhang. We fully recognize the potential for short-term softening in the rig market if gas prices cause significant customer spending reductions. While this situation reduces the degree of certainty of our outlook over the near-term, recent and prospective developments lead us to conclude that any impact on our results will likely be much less and shorter in duration than consensus expectations imply for both this year and next. Source: Nabors 2Q06 Earnings Release dated July 24,

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