Helmerich & Payne, Inc. · NYSE:HP
Helmerich & Payne — Sanders Morris Harris Group presentation (December 2004)
31 slides from Helmerich & Payne's conference presentation, Dec 15, 2004
Slide 1: Helmerich & Payne, Inc. Presentation for Sanders Morris Harris Group
December 2004 ESTABLISHED 1920 HELMERICH & PAYNE, INC. A Presentation for Sanders Morris Harris Group 16 December 2004
Slide 2: Forward-looking information
The information contained within this presentation is forward looking and involves risks and uncertainties that could significantly impact expected results. A discussion of these risks and uncertainties is contained in the Company's Form 10-Q filed with the Securities and Exchange Commission on Augu
Slide 3: Rig Locations
Rig Locations 101 U.S. Rigs 27 International Rigs 128 Total H&P Rigs 8 Management Contracts South America Venezuela 10/12 Colombia 2/2 Ecuador 8/8 Bolivia 0/3 Argentina 1/1 GOM 6/11 U.S. Land 84/90 California Equatorial Guinea Russia Hungary 1/1
Slide 4: Rig Fleet Size Has Increased 45% Since 2000
2000 2001 2002 2003 2004 Rig Fleet Size 88 96 111 128 128 Has Increased Its Total Rig Fleet by 45% Since 2000 45% Increase
Slide 5: Net Debt to Total Capitalization
Equity Net Debt After Tax Portfolio Value Total Capitalization 0.82 0.06 0.12 Net Debt To Total Capitalization September 30, 2004
Slide 6: Portfolio Liquidation
Portfolio Liquidation 1996 1997 1998 1999 2000 2001 2002 2003 2004 6/27/1905 Tax Basis 86 83 68 68 69 64 48 47 35 29.1 Tax Basis Market Value @ 9-30-95 $158 million Net Proceeds FY 1996 - Present $178 million Market Value @ 12-10-04 $193 million 12-04
Slide 7: Three Distinct Markets
International Platform Conventional FlexRigs Rig Fleet 27 11 29 61 Three Distinct Markets December 2004
Slide 8: Move from Deep to Mid-Depth Land Rigs
1997 1998 1999 2000 2001 2002 2003 2004 Rigs 18,000' + 15 15 15 16 18 22 22 21 Rigs 8 - 18,000' 15 21 25 23 31 44 61 69 Move from Deep to Mid-Depth Land Rigs
Slide 9: Newest Fleet In Industry
Newest Fleet In Industry Built or Upgraded December 2004 % of Fleet 1980 - 1989 16 12% 1990 - 1994 23 18% 1995 - 1999 38 30% 2000 - 2003 51 40% Total Rigs 128 100% Electric Rigs (SCR & AC) 93% Varco Top Drives 109
Slide 10: Rig Status as of 15 December 2004
Rigs Available 61 26 11 27 3 128 Rigs Working/ Contracted 61 23 6 22 0 112 % Activity 100% 88% 55% 81% 0% 88% U.S. Land, FlexRig & Mobile U.S. Land, Conventional U.S. Platform International Land In transit to the U.S. Total Management Contracts: U.S. GOM & CA Equatorial Guinea Russia Total Rigs Work
Slide 11: Segment Outlook - U.S. Land
Segment Outlook - U.S. Land Strong and Improving! Sustained rig demand Potential for continuing dayrate increases Growing customer focus on safety and performance Exploit H&P's competitive advantages
Slide 12: Rig Count and EBITDA
1996 1997 1998 1999 2000 2001 2002 2003 2004 Rig Count 585 583 606 614 629 643 655 682 682 708 714 714 689 719 745 748 778 830 818 842 858 856 835 861 836 811 772 726 696 692 670 656 635 606 587 531 479 432 410 387 395 435 468 510 573 608 639 635 635 627 634 659 689 715 763 819 848 886 893 920 929 9
Slide 13: U.S. Land Cash Flow Margin
Baker Hughes US Land Rig Count U.S. Land Cash Flow Margin 4,200 1,000 800 600 400 200 LEAACEA LE EPECEEPEERE EERE EERE Helmerich & Payne, Inc. mmEDom. Land CashFlowMargin Baker Hughes US Land Rig Count 99,000 38,000 $7,000 6,000 $5,000 34,000 $3,000 $2,000 1,000 0 Cash Flow Margin Per Rev. Day
Slide 14: FlexRig3 Incremental Return Estimates
FlexRig3 32 rigs 29 months in field 20 months average rig age FlexRig3 Incremental Return Estimates 4000 5000 6000 7000 8000 9000 10000 11000 Actual 12 mos. FY2004 Avg. Dayrate* $11,560 CoCR, No Tax CoCR, Fully Taxed Projected Avg. Dayrate $15,000 Projected Avg. Dayrate $16,500 Actual Last 3 Months
Slide 15: Segment Outlook - Offshore, U.S. GOM
Steady platform rig demand and supply Continues to be a rewarding business (Outstanding performance, reasonable ROI) Operating leverage available for potential recovery Rig management contract opportunities Segment Outlook - Offshore, U.S. GOM Steady, Good Potential
Slide 16: Segment Outlook - International
? Venezuela - Nine deep rigs are working. Tenth large rig has LOI. ? Colombia - One rig working. Second rig has LOI for December start. ? Ecuador - Eight rigs working. Possibility of one year firm contract for additional 2000 HP rig with Ecuadorian operator. ? Hungary - As forecast, R168 will comple
Slide 17: Russia - High Potential
Russia - High Potential H&P now four months into assistance contract for four Russia rigs. Early Results of Assistance Team: ? Good relationship with customer. ? Steep learning curve for Russian & artic environment. ? Improving field performance. ? FlexRig design offers a clear advantage over Russia
Slide 18: Why Do Operators Select H&P Rigs?
H&P is the leader in: Well and personnel safety Field performance Best value Why Do Operators Select H&P Rigs?
Slide 19: 2003 Safety Performance
LS Helmerich & Payne, Inc. 2003 Safety Performance’ 5.77 (72%) 1.62 (66%) ae 58 IADC H&P. IADC = U.S. LAND U.S. OFFSHORE * OSHA Recordable Injuries Per 200,000 Manhours Worked
Slide 20: H&P is the Leader in Field Performance
Innovative technology Reduced move times Reliability Drilling performance H&P is the Leader in Field Performance
Slide 21: Apply New Ideas & Technology
Apply New Ideas & Technology Integrated Top Drive Mechanized Tubular Handling VFD AC Drawworks BOP Handling V-ICIS eD Controls Communications
Slide 22: H&P Land Rig Moves 1998 to 2004
H&P Land Rig Moves 1998 to 2004 1200 HP Mobile Rigs 1500 HP FlexRigs 1000 HP 1500 HP 2000 HP 3000 HP Average Rig Move Days 2.39 3.31 5.75 7.27 8.27 10.38 # moves 723 1150 266 158 130 89 Conventional Rigs (Rig move time: Time from rig release on last well to spud of next well including time to rig do
Slide 23: FlexRig3 Highlights
FlexRig3 Highlights of Rigs 210 - 241 1. Field performance vs. customer's planned drill curves ? 474 complete wells to date ? 323 wells (68%) under ? 22 wells (5%) on ? 129 wells (27%) over 2. 50% of FlexRig3s are currently drilling directional, more technically difficult wells, compared to 26% for
Slide 24: H&P FlexRig3 Downtime Performance
H&P FlexRig3 Downtime Performance June 2002 - November 2004 FlexRigs Contracted Downtime Percentage
Slide 25: Example of Best Value: H&P FlexRig3
Example of Best Value: H&P 213 FlexRig3
Slide 26: Best Value - Reduced Well Cycle Time
Average of best Best of Competition H&P R213 in field to Aug 02 Dec 04 Jan 05 Drilling days 21 9.5 7.5 Completion days 2 2 2 Moving days 6 5 3 Well cycle in days 29 16.5 12.5 2. Contractor rate/day $8,000 $12,000 $15,500 Operator's other intangible cost per day estimate $7,000 $7,000 $7,000 Operator
Slide 27: Best Value Reduced Well Cycle Time
Best Value Reduced Well Cycle Time 3. Added value from FlexRig3 operations Lowest total well cost Increased wells per rig per year: 1st Year: 18 wells vs. 12.5 wells Wells 28 - 41: 29 wells vs. 12.5 wells Early production: Incremental wells on production 1st Year: 5.5 wells / yr Wells 28 - 41: 16.5
Slide 28: Sale of Rigs and Projected Returns on Investment
SALE OF RIGS 191 & 192 1. Projected Potential Average Financial Returns on Investment U.S. Land 7% S. America 5% Saudi A. / Indonesia 8% New construction or reactivation ^16% 2. Supporting considerations ? Avoid investing $4.5 - 11.3 per rig in older rigs to capture low rates of return. ? Use a spec
Slide 29: Prospects and Areas of Interest
Prospects and Areas of Interest
Slide 30: Why We Are Optimistic About The Future?
Why We Are Optimistic About The Future? Expanded rig fleet provides greater leverage Returning idle international and offshore rigs to work provides upside Achieve historic advantage of higher utilization rates and margins Value proposition becomes more compelling in an improving market
Slide 31: FlexRig3 H&P Rig - Wyoming
FlexRig3 H&P Rig 241 - Wyoming
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