Morgan Stanley Summer Houston Energy Summit

Transcription

1 Morgan Stanley Summer Houston Energy Summit August 28, 2012 Presenter: Dennis A. Smith Director, Corporate Development & Investor Relations

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 Section 27A of the Securities Act of 1933 and Section 21E of 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 in which we do business; 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. 2

3 Macro Outlook Lower Commodity Pricing Affecting Customers Cash Flows & Budgets 120 Oil prices down 7% since Jan 2012 and up 4% Jan Natural Gas prices down 5% since Jan 2012 and down 38% since Jan NGL prices down 37% since Jan 2012 and down 26% since Jan /3/2011 4/3/2011 7/3/ /3/2011 1/3/2012 4/3/2012 7/3/ Source: Bloomberg WTI Crude Spot Price NGL US Blend Average Henry Hub Nat Gas Spot 3

4 Macro Outlook Rapidly Declining Gas Directed Rig Count Impacting Horizontal Activity 1,500 1, oil rig increase since Oct ,408 Oil 1,300 1,200 1,100 1,080 Horiz 1, gas rig decrease since Oct Gas 400 1/7/2011 4/7/2011 7/7/ /7/2011 1/7/2012 4/7/2012 7/7/2012 Source: Baker Hughes US Rotary Rig Count Oil Gas Horizontal 4

5 US Land Rig Count At inflection point? Down 113 rigs from Nov 2011 peak, 35 since July US Land Rig Count ( Current) /3/2003 1/3/2004 1/3/2005 1/3/2006 1/3/2007 1/3/2008 1/3/2009 1/3/2010 1/3/2011 1/3/ US Land Rig Count US Land Rig Count (Peak - Current) /4/ /4/2011 1/4/2012 2/4/2012 3/4/2012 4/4/2012 5/4/2012 6/4/2012 7/4/2012 8/4/ Source: Baker Hughes US Rotary Rig Count US Land Rig Count 5

6 Nabors Business Outlook > North America rigs and pumping services challenged by weak natural gas prices & volatile oil and NGL prices Contract backlog helps mitigate downside risk Relocation of equipment challenging supply/demand balance Competitors speculative building effecting supply/demand balance > Outlook outside of Lower 48 is improving International activity poised to increase Potential for international expansion of Nabors services Alaska exploration activity improving Canada oily markets steady but vulnerable to oil prices > Long-term demand for well-servicing still attractive > Internal mandates driving near-term operational and financial performance improvement 6

7 Improving Our Performance > Core principles that built Nabors Maintain a strong and flexible balance sheet Invest capital for returns well above our cost of capital Make use of our size Deliver operational excellence > Our Priorities Streamlined scope of services Free cash flow generation Extract more from our asset base 7

8 Our Priorities: Streamlined Scope of Services Simplify The Operations: Two Lines of Business > Drilling and Rig Services > Completion and Production Services 8

9 Our Priorities: Free Cash Flow Generation > Refined capital spending Higher selectivity on capital projects Higher scrutiny on sustaining capital > Consolidation savings and synergies > Asset Sales E&P properties Selective non-core assets 9

10 Ample Liquidity With Five Year Duration As of June 30, 2012 ($M s) Liquidity and Revolving Credit: Maturity Interest Rate Face Value Available Cash + Investments $460,634 Credit Line 9/ % $1,400, ,000 Current Liquidity $950,634 Term Debt: Maturity Coupon Rate Face Value Senior Secured Notes REDEEMED 08/15/12 $275,000 Senior Secured Notes 2/ % 975,000 Senior Secured Notes 1/ % 1,125,000 Senior Secured Notes 9/ % 700,000 Senior Secured Notes 9/ % 700,000 Total Term Debt $3,500,000 Weighted Average Interest Rate 6.6% (1) (1) Excludes 8/12 maturity 5.7 year duration (1) 10

11 Our Priorities: Enhance Balance Sheet Flexibility Targeted Net Debt Reduction 40% 25% by EOY 2013 Actual Targeted (3) ($MM s) 1Q12 2Q12 EOY 2012 EOY 2013 Total Debt $4,773 $4,674 $4,455 $3,489 Cash and Investments Net Debt 4,273 4,213 3,994 2,902 Shareholders Equity 5,811 5,718 6,045 6,655 Gross Debt to Capitalization 45% 45% 42% 34% Net Debt to Capitalization 42% 42% 40% 30% Coverage (1) 8.0x 7.7x 7.9x 9.7x Leverage (2) 2.4x 2.5x 2.3x 1.5x Note: Does not include any proceeds from asset sales. (1) Coverage defined as EBITDA / Interest Expense (3) Based on consensus EBITDA of $1.1 BN for July to Dec 2012 and (2) Leverage defined as Total Debt / EBITDA $2.3 BN 2013 as of 7/20 11

12 Asset Dispositions Status Timing / Value # of Rigs US: Peak USA Completed $14 MM Canada: Blue Sky/Airborne Evaluating Bids 2012 Hybrid Coiled Tubing Drilling Rigs Withdrawn Workover & Well Services Evaluating Bids Alaska: Peak Oilfield Services Marketing 2012 Subtotal $300 - $400 MM Offshore: US GOM Jackup Rigs In Process TBD 5 US GOM Barge Rigs In Process TBD 5 International Jackup Rigs In Process TBD 8 Subtotal Value To Be Determined 12

13 Asset Dispositions: Oil and Gas Operations Recent Sales: Action Date Proceeds California Sale 4Q11 $72 MM Austin Chalk Sale 1Q12 4 MM Colombia Sale 2Q12 73 MM Miscellaneous 2Q12 5 MM Total $154 MM Remaining Properties: Oil & Gas Assets Status Details Eagle Ford Alaska North Slope British Columbia In Process In Process $ MM Horn River Planned 33,800 acres Montney & Other Planned 31,600 acres NFR Energy (49.8%) (1) Planned 1.3 Tcfe SEC proved (1) At 6/30/12 13

14 Asset Dispositions: Oil and Gas Operations NFR Overview Overview > Focused on low risk, predictable resource development in the Eagle Ford Shale, Haynesville Shale and Cotton Valley Sand fairways in Texas > Solid 534 Bcfe proved developed reserve base > Significant visible multi-year development upside 3,325+ gross unrisked horizontal drilling locations 20+ Years of drilling inventory 13.5 TCFE of Resource Potential Map of Operations Total Company SEC Proved Reserves (1) 1.3 Tcfe % Proved Developed 41% % Gas (PDP) 86% Current Production 140 Mmcfe/d Texas Acreage (Net) ~220,000 acres East Texas Basin ~130,000 net ac Recent Events > Drilled and completed first Eagle Ford JV well, produced 864 BOEPD first 30 days (87% Liquids) > Drilled first DK Prospect well and waiting on completion Liquids rich, 70,000 ac grass roots play Anticipate first production in 3Q NFR acreage position Eagle Ford ~20,000 net ac DK Prospect ~70,000 net ac Office Locations (1) At 6/30/12 14

15 Asset Dispositions: Oil and Gas Operations Alaska Land Position 230,000 Gross Acres Ramshorn ~ 50% WI OU NU MPU Central 56,000 acres NSU CRU Appaloosa KRU PBU LU Telemark BU PTU Tofkat Mustang Western 89,000 acres Eastern 85,000 acres 15

16 Asset Dispositions: Oil and Gas Operations British Columbia Horn River Land Position 33,000 Net Acres 16

17 Our Priorities: Extract More From the Asset Base Target Benefits - Financial > Economies from business unit consolidation Elimination of redundant unit support functions Elimination of redundant facilities > Improved asset utilization > Increased capital discipline and accountability 17

18 Our Priorities: Extract More From the Asset Base Target Benefits - Operational and Technical > Centralized engineering, project management and technology development More effective use of technical resources More rapid and uniform adoption of technology > Standardization of operational processes Health, Safety and Environmental Human Resources > Improved customer interaction Single contact customer account manager Increased management accountability 18

19 Nabors Global Reach > High-graded drilling fleet with global footprint At EOY 2012: 207 new AC rigs since 2005 At EOY 2013: 223 new AC rigs since 2005 Significant forthcoming technological advantages > Large N.A. platform servicing the life of the well 675 well servicing rigs 805,000 fracing horsepower 1,000 fluid hauling trucks 3,800 frac tanks 100,000 other pumping horsepower 19

20 Drilling & Rig Services Global Rig Fleet Land AC SCR Mech Total US Lower International Canada Alaska Offshore US GOM International Total Note: Includes 2012 and 2013 scheduled new equipment deployments 20

21 Drilling & Rig Services US Lower 48 Land Drilling - Premium Fleet Makeup > By June 2013, will have built 152 new AC rigs since 2005 > 92 rigs will have walking systems by June 2013 > Since 2006, 28 major upgrades have taken place, mostly consisting of engine package, AC top drives and 1600 HP mud pumps 21

22 Drilling & Rig Services International Quick Facts > 131 premium rigs throughout all major oil & gas operating regions > 96% of drilling rigs have top drives (79 AC & 51 DC) > 41 newbuilds in last 5 years > 62 refurbs/upgrades in last 5 years > 75 rigs have 3 mud pumps > 89 rigs have iron roughnecks > 80 rigs have automated catwalks > 49 rigs have moving systems 22

23 Drilling & Rig Services Canada Quick Facts Since 2007: 11 AC new build deployed 13 AC top drives installed 29 automated catwalks installed 8 moving systems installed 35 pump upgrades 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 Focus on Unconventional Development N.A. Assets Total Workover / Well-Servicing Rigs 678 Coil Tubing Rigs 12 Frac Cementing & Other 805,000 HHP ~100,000 HHP Tanker Trucks 1,020 Frac Tanks 3,834 Disposal Wells 17 Note: As of 7/20/12 25

26 Completion & Production Services Strategically Positioned Assets Shale Plays & Basin Frac Crews LTSA Spot CTU Well Svc Rigs Fluid Svc Trucks Frac Tanks Marcellus/Utica Bakken/Rockies Eagle Ford Permian ,106 Barnett/Haynesville Granite Wash Canada Other Idle Total ,020 3,834 Note: As of 7/20/12 26

27 Summary: Why Nabors? > Global footprint provides opportunity > Significant efficiency and consolidation savings > Long-term contracts limit downside in pressure pumping and gas drilling > Lowering leverage > Free cash flow generation > Multiple expansion potential 27

28 Auxiliary Slides 28

29 Nabors Global Infrastructure Expected Seasonally Weak Second Quarter Operating Income ($MM s) FY Q12 2Q12 US Lower 48 $414 $132 $127 US Offshore Alaska Canada (4) International Rig Services Drilling and Rig Services Total $717 $267 $186 Well Servicing $75 $22 $29 Pressure Pumping Completion and Production Services Total $304 $87 $75 Oil & Gas Corporate & Eliminations (153) (38) (36) Subtotals may not sum due to rounding Total Operating Income $927 $321 $230 29

30 Nabors Global Infrastructure Margins and Activities 2Q11 1Q12 2Q12 Drilling Margin (1) Rig Yrs Margin (1) Rig Yrs Margin (1) Rig Yrs US Lower 48 $10, $10, $11, US Offshore 11, , , Alaska 44, , , Canada 11, , , International 13, , , Well Servicing Rev/Hr Rig Hrs Rev/Hr Rig Hrs Rev/Hr Rig Hrs US Lower 48 $ ,949 $ ,026 $ ,304 Canada , , ,710 (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. 30

31 Drilling & Rig Services US Lower 48 Term Contracts in Force at June 30, 2012 Quarter End Number Of Rigs Subject To Term Contracts (1) 2Q12 3Q12 4Q12 1Q13 2Q13 1Q Q ($MM s) Actual Estimates Non-Working Rig Revenue 2Q12 3Q12 4Q12 Out Years Lump Sum $1.2 $ Lump Sum: Amortized Monthly $0.6 $0.6 $0.6 $4.7 Standby: Monthly $2.6 $2.9 $2.7 $3.9 Total $4.4 $11.9 $3.3 $8.6 (1) Represents the quarter end number of contracts in force with no incremental contract awards in the future 31