Raymond James 33rd Annual Institutional Investors Conference

Transcription

1 Raymond James 33rd Annual Institutional Investors Conference March 6, 2012 Presenter: Denny Smith Director, Corporate Development

2 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 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. 2

3 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 3

4 Nabors Global Infrastructure Largest portfolio of premium assets 755 LAND WORKOVER RIGS 499 LAND DRILLING RIGS 12 JACKUPS 7 Drilling 5 Workover 733k PRESSURE PUMPING HHP 4 BARGE RIGS 39 PLATFORM RIGS 25 Workover/Re-Drilling 14 Drilling Actively Marketed Rigs Only As of December 31, 2011 DRILLING INSTRUMENTATION TOP DRIVE MANUFACTURING 4

5 Nabors Global AC Rig Fleet New build rigs for US lower 48 land are only part of the Nabors story 12/31/11 To Be Delivered Total Alaska Drilling US Lower 48 Land Drilling Canada Drilling 24 (1) 2 26 International Drilling US Offshore Drilling Total NBR (1) Includes 10 AC Hybrid Coiled Tubing rigs 5

6 Global Fleet - Cash Flow Equivalent to US Land Rigs More to Nabors than just US land drilling Actual 4Q2011 Rig Years Equivalent US Lower 48 Rig Count (1) Alaska US Lower Canada International Offshore GOM 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. 6

7 Assets Strategically Positioned in Major US Unconventional Plays Shale Plays & Basin Working Drilling Rigs Frac Crews CTU Well Svc Rigs Fluid Svc Trucks Frac Tanks Marcellus Haynesville Bakken/Rockies Eagle Ford Permian Barnett Granite Wash Other Total Note: Includes 2012 scheduled new equipment deployments 7

8 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 8

9 Re-Establish Balance Sheet Flexibility Increased 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 12/31/ x Diluted Average Shares Outstanding 292,484 Fitch, Moody s and S&P BBB+, Baa2, BBB 9

10 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 10

11 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 11

12 Our Business Lines: An Overview Accelerating Operating Cash Flow 4Q Consolidated Run Rate exceeds Prior High and Increasing GAAP FY 2008 FY Q11 Annualized US Lower 48 $839 $703 $826 US Well Servicing US Offshore Alaska Canada International Pressure Pumping Oil & Gas Other Sub total $2,035 $2,006 $2,225 Corporate & Eliminations Total $1,872 $1,851 $2,050 12

13 Our Business Lines: An Overview Operating 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 13

14 Business Line & Asset Class Evaluation Criteria > Leadership position > Attractive investment returns > Capable of growth or otherwise strategic 14

15 Drilling Rigs & Services 15

16 Drilling Rigs & Services US Lower 48 Land Drilling: Total Working Rigs: 222 now 247 w/ new builds 16

17 Drilling Rigs & Services US Lower 48 Land Drilling: Shale Plays and Basins Nabors Rigs Including New Builds Frac Crews Marcellus Haynesville/Tuscaloosa Permian Barnett Eagle Ford Woodford Fayetteville Granite Wash Niobrara Uinta Bakken / Three Forks Other Basins Total

18 Drilling Rigs & Services US Lower 48 Land Drilling - Premium Fleet Makeup NDUSA Rig Fleet # of Rigs Util. AC 12/31/ % SCR Upgraded 65 85% SCR 44 50% Mechanical 41 68% Current Total % AC Rigs still to be deployed % Total % Expected % AC and AC Equivalent 71% 18

19 Lower 48 Summary by Basin Basin Oil/Gas Working Rigs Approx. 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

20 U.S. Lower 48 Land Drilling Term Contracts in Force at 12/31/11 Quarter end number of rigs subject to term contracts (1) 4Q11 1Q12 2Q12 3Q12 4Q12 3Q Q Contract Signatures 1Q11 2Q11 3Q11 4Q11 Replaced Incremental Total Signed (1) Represents the quarter end number of contracts in force with no incremental contract awards in the future. 20

21 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, startups, 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 21

22 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 22

23 Canada Summary by Basin Basin Oil/Gas Working Rigs Term Contracts Approx. Market Share Horn River Gas % Montney Oil/Gas % Duvernay Oil % Oil Sands Oil % Cardium Oil % Saskatchewan Oil % Total 47 23

24 Canrig: A Technology Success Story > Innovation 200th ROCKIT TM system installed in 2011 REVIT TM 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 24

25 Completion & Production Services 25

26 Completion & Production Services US Pressure Pumping: Total Large Frac Crews: 25 Including planned additions 26

27 Pressure Pumping Assets by Basin 4Q Q 2012 EOY 2012 Pressure Pumping Coil Tubing Cementing Pressure Pumping Coil Tubing Cementing Pressure Pumping Coil Tubing Cementing Marcellus Haynesville Bakken/Rockies Eagle Ford Permian Barnett Granite Wash Other Lower Canada Total

28 Pressure Pumping Summary by Basin Basin Oil/Gas # of Crews LTSA Spot Approx. Market Position Marcellus Gas T-4 th Haynesville Gas T-4 th Bakken/Rockies Oil/Gas nd Eagle Ford Oil/Gas T-6 th Permian Oil T-6 th Barnett Gas T-5 th Granite Wash Oil T-11 th Total

29 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 29

30 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 30

31 Well Servicing Product Lines Rig Services 518 Well-Servicing / Workover Rigs Hour Rigs Fluid Services 921 Fluid Transportation Trucks 3727 Frac Tanks 17 Disposal Facilities Condensate Hauling Water Management Special Services Rental and Fishing Services Cementing Excavation/Construction Rig Moving/Hauling - Marcellus Plug & Abandonment (P&A) Pipeline/Well Tending - Marcellus 31

32 Completion & Production Services US Well Servicing: Operating Facilities District California 16 Mid-Continent 12 Rocky Mountain 16 Northeast 9 Southeast 24 Western 21 Total 98 32

33 Well Services Summary by Basin Basin Well Svc Rigs Fluid Svc Trucks Frac Tanks Bakken / Rockies Granite Wash / Mississippian Permian Basin Marcellus / Utica Eagle Ford Barnett / Haynesville San Joachim / Long Beach Total

34 Evaluate Each Business Line Oil & Gas: Expeditiously monetize in an orderly and optimal manner Net Cash Cash Invested Proceeds to Date 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) 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: Investor Presentation October

35 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 35

36 Auxiliary Information 36

37 Margins and Activities 3Q11 4Q11 4Q10 Margin (1) Rig Yrs Margin (1) Rig Yrs Margin (1) Rig Yrs US Lower 48 $10, $10, $9, US Offshore 17, , , Alaska 29, , , Canada 12, , , International 11, , , Well Servicing Rev/Hr Rig Hrs Rev/Hr Rig Hrs Rev/Hr Rig Hrs US Lower 48 $ ,816 $ ,610 $ ,318 Canada $808 52,712 $787 49,788 $719 49,740 (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. 37

38 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 38

39 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. 39

40 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: Three Months Ended (in thousands) December 31, 2011 Adjusted income (loss) derived from operating activities: Contract Drilling: September 30, 2011 December 31, , ,877 85,308 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, , , ,936 76,470 65,052 54,644 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, , ,930 Interest expense (60,852) (58,060) (74,012) 7, ,619 (5,614) 11,607 (6,403) (100,000) (98,072) - 114, , ,134 US Lower 48 Land Drilling US Land Well-Servicing Subtotal Contract Drilling Pressure Pumping Oil & Gas Investment income (loss) Gains (losses) on sales and retirements of longlived assets and other income (expense), net Impairments and other charges Income (loss) from continuing operations before income taxes (1) Represents the elimination of inter-segment transactions and unallocated corporate expenses. 40