Exhibit 99.1
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Investor Relations Contact: Mike Drickamer – (918) 588-5190 – mike.drickamer@hpinc.com Helmerich & Payne, Inc. RBC Capital Markets Global Energy & Power Conference June 8, 2010 |
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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 “Risk Factors” and “Management’s Discussion & Analysis of Results of Operations and Financial Condition” sections of the Company’s SEC filings, including but not limited to, its annual report on Form 10-K and quarterly reports on Form 10-Q. |
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H&P’s Global Rig Fleet * Estimates include existing rigs and announced new build commitments. 77 90 89 88 96 111 127 130 128 151 193 224 254 264 0 50 100 150 200 250 300 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E* Rigs Available Fiscal Year (Ending Sept 30) International Land Offshore U.S. Land |
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H&P’s Global Rig Fleet 264 Total Rigs (Includes New Build Commitments) Offshore * Includes two new rigs with customer commitments scheduled for completion by the end of fiscal 2010. ** Includes 15 FlexRigs. U.S. Land 216* U.S. FlexRigs 178* Mobile & Conventional 38 9 International Land 39** |
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A disparity between crude oil and relatively weak natural gas prices exists. This disparity has led E&P operators to increase drilling activity in oil and “liquids-rich” markets. Drilling activity is becoming increasingly complex, with the number of rigs drilling horizontal wells at an all-time high. Our guess is that the U.S. land rig count will be somewhat range-bound in the near-term. Several factors should serve as a downward buffer to the U.S. land rig count: Strong liquids prices Customers drilling to hold valuable leases Hedges in place that locked in higher prices The Market Today |
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Our fleet profile is the newest and most advanced Significant portfolio of term contracts Strong financial position – 13.6% debt-to-total capital ratio (as of March 31st, 2010) About 95% of H&P’s rigs active in the U.S. land spot market are FlexRigs FlexRigs continue to deliver outstanding field performance How is H&P Positioned? |
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H&P’s Global Fleet Under Term Contracts * Includes delayed new builds which are expected to generate revenue but not revenue days. 0 20 40 60 80 100 120 Q3FY10 Q4FY10 Q1FY11 Q2FY11 Q3FY11 Q4FY11 Q1FY12 Q2FY12 Number of Rigs Under Long-Term Contracts (Estimated Quarterly Average) Term Contract Status - H&P Global Fleet* (Including Committed New Builds) U.S. Land Offshore International Land |
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H&P’s U.S. Land Fleet Activity ** Includes delayed new builds (in gray) which generated revenue but did not generate revenue days. * Active rigs on term (in blue) generated both revenue and revenue days, including a few rigs on standby. 116 128 150 154 160 166 0 25 50 75 100 125 150 175 Avg. Q4FY09 Avg. Q1FY10 Avg. Q2FY10 3/31/2010 4/29/2010 6/8/2010 Number of Active H&P U.S. Land Rigs Active Rigs in SpotMarket Active Rigs on Term* Delayed NewBuilds** |
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H&P’s U.S. Land Fleet Status * Includes five FlexRigs with signed contracts. All of the remaining nine uncontracted FlexRigs are FlexRig4’s, which target shallower depth wells. 110 52 14 111 55 48 0 20 40 60 80 100 120 Under Term Spot Market Active Spot Market Stacked* Number of H&P Rigs Highly Mobile Conventional FlexRigs |
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Spot market pricing continues to improve, especially for larger FlexRigs in unconventional plays. We expect a five to ten percent sequential increase in average activity (or revenue days) from the second to the third fiscal quarter of 2010. Average rig margin per day (excluding the impact of early termination and new build delivery delay revenues) is expected to slightly decline from the second to the third fiscal quarter of 2010. We continue to deploy rigs to oil and “liquids-rich” gas plays. By the fourth fiscal quarter, we expect to have 17 rigs active in the Bakken Shale, 16 rigs active in the Eagle Ford Shale, 11 in the Cana, eight in the Granite Wash, and one rig active in the Niobrara Shale. Given the incremental demand for term contracts, the Company now expects an average of approximately 108 rigs to remain under term contracts during the third fiscal quarter and 111 during the fourth fiscal quarter of 2010. The corresponding estimated annual averages for rigs under term contracts for fiscal 2011 and fiscal 2012 are now 78 and 42 rigs, respectively. H&P’s U.S. Land Operations |
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Given the continued improvement in U.S. land activity and market conditions for highly-capable rigs, the company has increased its fiscal 2010 capital expenditures estimate by $20 million to $350 million. The $20 million increase is mostly attributable to higher capital maintenance requirements (as a result of activity improvements). H&P’s Capex Estimate for Fiscal 2010 |
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H&P’s Contracted U.S. Land Fleet (as of 6/8/10) Note: The above numbers corresponding to H&P’s contracted U.S. land fleet include delayed new builds which generate revenue but do not generate revenue days, five idle FlexRigs with signed contracts, and two previously announced pending new build FlexRigs. Haynesville Shale, 27 Woodford Shale / Granite Wash, 23 Bakken Shale, 17 Barnett Shale, 16 Eagleford Shale, 16 Piceance Basin, 14 Marcellus Shale, 11 Other Unconventional, 14 Conventional Oil, 24 Other Conventional, 11 |
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*Represents average active rigs for PTEN, NBR and UNT. The Impact of a Severe Downturn on Activity As of 6/8/10 - 60% - 40% - 20% 0% 20% 40% 60% 80% 100% 120% Q1CY05 Q2CY05 Q3CY05 Q4CY05 Q1CY06 Q2CY06 Q3CY06 Q4CY06 Q1CY07 Q2CY07 Q3CY07 Q4CY07 Q1CY08 Q2CY08 Q3CY08 Q4CY08 Q1CY09 Q2CY09 Q3CY09 Q4CY09 Q1CY10 Change in Average Active Rigs Quarterly Average Growth / Decline in U.S. Lower 48 Average Rig Activity H&P (From 84 to 146 Rigs at ~70% Utilization in Q1CY10) Peers* (From 565 to 340 Rigs at ~44% Utilization in Q1CY10) |
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Technology and Quality Service Make a Difference Utilization Premium Rig Margin Premium **** Represents estimated average combined utilization for PTEN, NBR and UNT in the Lower 48. *** Utilization is herein calculated to be average active rigs divided by estimated available marketable rigs during the period. ** Represents weighted-average rig margin per day for PTEN, NBR and UNT * Does not include the impact of early contract termination revenue. $0 $3,000 $6,000 $9,000 $12,000 H&P Peers** Average U.S. Land Rig Margin per Day* (12 Months Ended March 31, 2010) 10% 30% 50% 70% H&P Peers**** Estimated U.S. Land Rig Utilization*** (12 Months Ended March 31, 2010) |
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Most Profitable Driller in U.S. Land Business * PTEN’s operating income includes drilling operations in Canada. ** NBR’s operating income corresponds to its U.S. Lower 48 Land Drilling segment. - $100 $0 $100 $200 $300 $400 PTEN* UNT NBR** HP Operating Income (Millions) U.S. Land Drilling Operating Income 12 Months Ended March 31, 2010 |
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Active Contracted Idle Total Long-term Contracts Argentina 5 4 9 4 Colombia 4 2 6 2 Ecuador 4 4 Mexico 6 6 6 Tunisia 2 2 Venezuela 11 11 Other 1 1 1 Total 21 1 17 39 13 H&P’s International Land Operations Rig Fleet Status (as of June 8, 2010) 1) Includes one rig under a long-term contract still in the U.S. expected to deploy to Bahrain during the first fiscal quarter of 2011. 2) 13 of 15 FlexRigs (included in the international fleet of 39 rigs) are under long-term contracts. (1) (2) |
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H&P’s International Land Operations We expect quarterly activity (or revenue days) for the segment to sequentially increase by about five percent from the second to the third fiscal quarter of 2010. The new build FlexRig under a long-term contract still in the U.S. is now expected to deploy to Bahrain during the first fiscal quarter of 2011. We expect average daily rig margins for the International Land segment to decrease by about 10% from the second to the third fiscal quarter of 2010. |
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Seven of the Company’s nine offshore platform rigs remain active, including two under long-term contracts. One of the two idle rigs still has a prospect for work beginning in the fourth fiscal quarter of 2010. Although the exact future implications of the deepwater moratorium are currently unclear, it appears that in the near-term, only one of the Company’s seven active platforms rigs could potentially be impacted (only by way of a reduced standby rate). In addition, one of the Company’s three offshore rig management contracts could also potentially begin receiving a reduced standby rate. As we transition from the second to the third fiscal quarter of 2010, we continue to expect a decline in average daily rig margins in the range of 10 to 15 percent. H&P’s Offshore Operations |
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Peer Group Estimated Return on Equity 0% 2% 4% 6% 8% 10% PTEN NBR PDS H&P ROE Analyst Estimates Fiscal Year 2010 Return on Equity (Source: First Call Consensus, June 2, 2010) |
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H&P is Leading the U.S. Land Retooling Effort Refurbished rigs, built between 1940s and 1982 74% 11% 15% 18% 74% 8% Note: The above estimates corresponding to the total available U.S. land fleet are derived from multiple sources including Rig Data, Smith Bits and corporate filings. Only rigs with equal to or greater than 600 horsepower drawworks ratings are considered. AC Driven New Builds Other New Builds Conventional Rigs Total Available U.S. Land Fleet (Estimates) (~2,500 Rigs) AC Driven (FlexRig 3 & 4) Other New Builds (FlexRig 1 & 2) Conventional Rigs H&P's Available U.S. Land Fleet (214 Rigs as of 6/8/10) |
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H&P and U.S. Land Fleet (by Rig Type) 55% 30% 15% 22% 74% Note: The above estimates corresponding to the total available U.S. land fleet are derived from multiple sources including Rig Data, Smith Bits and corporate filings. Only rigs with equal to or greater than 600 horsepower drawworks ratings are considered. AC Driven Rigs SCR Rigs Mechanical Rigs H&P's Available U.S. Land Fleet (214 Rigs as of 6/8/10) AC Driven Rigs SCR Rigs Mechanical Rigs Total Available U.S. Land Fleet (Estimates) (~2,500 Rigs) |
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H&P’s U.S. Land Fleet (as of 6/8/10)* * Includes operator requested new build delivery delays, which generate revenue but not revenue days. Estimated U.S. Land Activity by Rig Type The above estimates corresponding to the total available U.S. land fleet are derived from multiple sources including Rig Data, Smith Bits and corporate filings. Only rigs with equal to or greater than 600 horsepower drawworks ratings are considered. Industry’s Estimated U.S. Land Fleet** ** Composition & Utilization (by Rig Type) Composition & Utilization (by Rig Type) 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% AC Driven Rigs SCR Rigs Mechanical Rigs Estimated Utilization (%)** Estimated Fleet Composition (%)** 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% AC Driven Rigs SCR Rigs Mechanical Rigs Utilization (%) Fleet Composition (%) |
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Source: EnergyPoint Research, Inc. * Trailing four quarters average * * Customer Satisfaction Index 10 = “Highly Satisfied”, 1 = “Highly Dissatisfied” * * * 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 2006 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 HP Peer A Peer B Peer C |
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Growing focus on technology-based solutions that enable lower total well costs Unconventional plays are the most economically viable and tend to require highly-capable rigs Drilling is becoming more challenging and highly-capable rigs are expected to be in short supply Increasing safety and environmental sensitivity Market Trends Favor H&P |
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End of Presentation |
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Additional References: |
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AC Driven Systems & Integrated Top Drive Mechanized Tubular Handling Computerized Controls BOP Handling Driller’s Cabin Satellite Communications Rig Move Capabilities Leader in New Ideas & Applied Technology 31 |
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New Builds – H&P’s FlexRig Program The FlexRig Difference: Key Advantages Increased drilling productivity and reliability Variable frequency (AC) drives with increased precision and measurability Computerized electronic driller that precisely controls weight on bit, rotation and pressure Designed to move quickly from well to well Accelerated well programs and NPV gains A significantly enhanced and safer workplace Minimized impact to the environment Total well cost savings even at premium dayrates |
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Estimated Estimated Peer H&P FlexRig Conventional Fit-for-purpose Average Average Average Mid 2010 (Spot Market) (Spot Market) (Spot Market) 1. Drilling days 26 15 12 Completion days 2 2 2 Moving days 5 5 3 Total rig revenue days per well 33 22 17 2. Drilling contractor dayrate $15,500 $17,500 $22,500 Operator’s other intangible $15,000 $15,000 $15,000 cost per day estimate Total daily cost estimate $30,500 $32,500 $37,500 Total cost per well (daily services) $823,500 $715,000 $637,500 3. Total well savings with H&P – per well $369,000 $77,500 per year $7.9MM $1.7MM Increased wells per rig per year versus conventional average: 10 wells Increased wells per rig per year versus peer fit-for-purpose: 5 wells A Value Proposition Example – H&P vs. Competitors |
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Performance is not only about better rigs It’s also about: People Safety Experience Training Culture Supply chain Maintenance Processes Organizational network Support structure A Strong Field Organization |
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* Represents the customer’s fastest reported Bakken Shale well before deploying a H&P FlexRig. FlexRig3 – Performance Sample 48% Improvement 59% Improvement |
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FlexRig4M – Performance Sample 59 % Improvement |
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FlexRig4 – Performance Sample 42% Improvement 22% Improvement 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 0 2 4 6 8 10 12 14 16 18 Depth (ft) Time (days) Customer's Target Curve Jan to June 2010 Average - 9 Wells FlexRig4's Fastest EagleFord Well FlexRig4 EagleFord Shale |
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Alaska Shale Gas Offshore Other Onshore (Includes Tight Sands) Projections History TCF Source: Energy Information Administration Annual Energy Outlook 2010 with projections to 2035 (May 2010). Unconventional Natural Gas Production Growing Coalbed Methane 0 2 4 6 8 10 12 14 16 1990 1995 2000 2008 2015 2020 2025 2030 2035 |
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Increasing Focus on More Difficult Drilling 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2003 2004 2005 2006 2007 2008 2009 2010 Percentage of Active U.S. Rigs (BHI North American Rotary Rig Count) Week Ended U.S. Rig Activity by Drilling Type Vertical Drilling Horizontal or Directional Drilling |
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Increasing Focus on More Difficult Drilling 80% 31% 37% 43% 51% 68% 28% 53% 69% 0 400 800 1200 1600 2004 2005 2006 2007 2008 2009 May-10 Trough (2009) Peak (2008) Number of Active Rigs (Smith Bits S.T.A.T.S.) Annual Average During Each Prior Year Active Rigs in U.S. Land Drilling for Natural Gas Horizontal or Directional Drilling Vertical Drilling |
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Oil Related Drilling Also Increasingly Complex 51% 39% 31% 33% 40% 41% 36% 42% 41% 0 75 150 225 300 375 450 2004 2005 2006 2007 2008 2009 May-10 Trough (2009) Peak (2008) Number of Active Rigs (Smith Bits S.T.A.T.S.) Annual Average During Each Prior Year Active Rigs in U.S. Land Drilling for Oil Horizontal or Directional Drilling Vertical Drilling |
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Crude Oil & Natural Gas Prices Source: Energy Information Administration, Short-term Energy Outlook as of 5/11/2010. Crude Oil Natural Gas $0 $2 $4 $6 $8 $10 $12 $14 $0 $20 $40 $60 $80 $100 $120 $140 U.S. Dollars per Thousand Cubic Feet U.S. Dollars per Barrel Monthly Average West Texas Intermediate Spot Average Forecasted West Texas Intermediate Spot Average Henry Hub Spot Forecasted Henry Hub Spot |
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Improving Rig Counts U.S. Land International Land 0 300 600 900 1,200 1,500 1,800 2,100 2,400 0 300 600 900 1,200 1,500 1,800 2,100 2,400 Apr-2000 Oct-2000 Apr-2001 Oct-2001 Apr-2002 Oct-2002 Apr-2003 Oct-2003 Apr-2004 Oct-2004 Apr-2005 Oct-2005 Apr-2006 Oct-2006 Apr-2007 Oct-2007 Apr-2008 Oct-2008 Apr-2009 Oct-2009 Apr-2010 Monthly Average Baker Hughes U.S. Land and MI Swaco International Land Rig Counts MI Swaco International Land Rig Count BHI U.S. Land Rig Count |
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Changes in Lower 48 U.S. Land Rig Count * PDS’s active rig count includes both PDS and GW rigs. - 50% - 40% - 30% - 20% - 10% 0% HP U.S. Land PDS* NBR UNT PTEN Change in Rig Count Estimated Change Since Peak in Active U.S. Land Rigs (Smith Bits Weekly Rig Count - October 17, 2008 to May 28, 2010) |
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FlexRigs in Demand for More Difficult Wells 0% 20% 40% 60% 80% 100% Land Rigs, Industry Wide FlexRigs Percentage of Applicable Rig Fleet Active Land Rigs Drilling Horizontal or Directional Wells (Data Source: Smith International, Inc. - S.T.A.T.S. - 5/28/10) |
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U.S. Land Safety Performance (1994 – 1Q10) OSHA Recordable Injury Incidence Rates H&P TRIR = 1.13 IADC TRIR = 2.51 INJURIES PER 200,000 MANHOURS MANHOURS WORKED (MM) Delivering Safety – H&P vs. Industry (IADC) MANHOURS = 9.2 MM 0 2 4 6 8 10 12 14 16 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 ' YEAR 0 2 4 6 8 10 12 |
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Safety Excellence Also Generates Savings Reduced Workers Comp and General Liability Losses per Man Hour EMR = Experience Modifier Ratio (Industry Average = 1.00) |
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End of Document |
