Exhibit 99.1
| Investor Relations Contact: Mike Drickamer — (918) 588-5190 — mike.drickamer@hpinc.com Helmerich & Payne, Inc. Meetings with Investors October 12-13, 2010 |
| 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 Conditions” 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. |
| Market Observations Realities of a segmented market will shape the land drilling landscape. Customers will continue to rely on drilling efficiencies to offset cost pressures and weak natural gas prices. The Company’s industry leading manufacturing effort reflects our customers’ future drilling intentions. |
| International Land ** 29 Offshore 9 Mobile & Conventional 38 U.S. FlexRigs * 193 U.S. Land * 231 269 Total Rigs (Includes New Build Commitments) * Includes 12 new rigs with customer commitments scheduled for completion by early to mid calendar 2011. ** Includes 16 FlexRigs, one of which will be deployed from the U.S. to Bahrain during the first fiscal quarter of 2011. Also includes six rigs assigned to the Company’s operations in Mexico, some of which are returning to the U.S. H&P’s Global Rig Fleet |
| * Estimates include existing rigs and announced new build commitments. 77 90 89 88 96 111 127 130 128 151 193 224 254 257 269 0 50 100 150 200 250 300 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011E* Rigs Available Fiscal Year (Ending Sept 30) International Land Offshore U.S. Land H&P’s Global Rig Fleet |
| Dayrates continue to improve as FlexRig utilization currently stands at 100%. We continue to expect an increase of ten percent or more in average rig activity, or total quarterly revenue days, from the third to the fourth fiscal quarter of 2010. Quarterly average rig revenue per day (excluding the impact of early termination and new build delivery delay revenues) is still expected to increase by several hundred dollars per day from the third to the fourth fiscal quarter of 2010. Given the incremental demand for term contracts, the Company now expects an average of approximately 124 rigs to remain under term contracts during the fourth fiscal quarter of 2010. The corresponding estimated annual averages for rigs already under term contracts for fiscal 2011 and fiscal 2012 are now 102 and 61 rigs, respectively. H&P’s U.S. Land Operations |
| 34 47 52 54 56 61 89 99 106 112 119 123 128 150 163 170 177 185 0 25 50 75 100 125 150 175 200 Avg. Q1FY10 Avg. Q2FY10 Avg. Q3FY10 6/30/2010 7/29/2010 9/30/2010 Number of Active H&P U.S. Land Rigs Active Rigs in Spot Market Active Rigs on Term* Delayed New Builds** ** 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. H&P’s U.S. Land Fleet Activity |
| 123 58 124 61 34 0 25 50 75 100 125 150 Under Term Spot Market Active Spot Market Stacked* Number of H&P Rigs Highly Mobile Conventional FlexRigs H&P’s U.S. Land Fleet Status (as of 9/30/10) *Excludes rigs assigned to the Company’s operations in Mexico that are returning to the U.S. |
| 124 125 107 96 81 69 64 59 0 12 24 36 48 60 72 84 96 108 120 132 144 Q4FY10 Q1FY11 Q2FY11 Q3FY11 Q4FY11 Q1FY12 Q2FY12 Q3FY12 Number of Rigs Already Under Long-Term Contracts (Estimated Quarterly Average) Term Contract Status - H&P Global Fleet* (Including Committed New Builds) U.S. Land Offshore International Land * Includes delayed new builds which are expected to generate revenue but not revenue days. H&P’s Global Fleet Under Term Contracts |
| 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 (%) H&P’s U.S. Land Fleet (as of 9/30/10)* * 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. ** Composition & Utilization (by Rig Type) Composition & Utilization (by Rig Type) H&P’s U.S. Land Fleet (as of 9/30/10)* Industry’s Estimated U.S. Land Fleet** |
| Eagle Ford Shale, 26 Haynesville Shale, 25 Bakken Shale, 19 Permian Basin, 19 Barnett Shale, 17 Cana Woodford, 14 Piceance Basin, 14 Marcellus Shale, 12 Granite Wash , 8 East Woodford, 5 Niobrara, 2 Other Unconventional, 16 Conventional Oil, 11 Other Conventional, 9 H&P’s Contracted U.S. Land Fleet (as of 9/30/10) Note: The above numbers corresponding to H&P’s contracted U.S. land fleet include one delayed new build which generates revenue but does not generate revenue days and 12 pending new build FlexRigs. |
| 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 (219 Rigs as of 9/30/10) H&P is Leading the U.S. Land New Build Effort Refurbished rigs, built between 1940s and 1982 73% 11% 16% 17% 75% 8% Note: The above estimates corresponding to the total available U.S. 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 (219 Rigs as of 9/30/10) AC Driven Rigs SCR Rigs Mechanical Rigs Total Available U.S. Land Fleet (Estimates) (~2,500 Rigs) H&P and U.S. Land Fleet (by Rig Type) 53% 31% 16% 21% 75% 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. |
| -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 Q2CY10 Change in Average Active Rigs Quarterly Average Growth / Decline in U.S. Lower 48 Average Rig Activity H&P (From 84 to 158 Rigs at ~76% Utilization in Q2CY10) Peers* (From 565 to 384 Rigs at ~50% Utilization in Q2CY10) *Represents average active rigs for PTEN, NBR and UNT. H&P Taking Market Share As of 9/30/10 |
| 0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20% NBR PTEN UNT HP 0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20% NBR HP PTEN UNT Organically Growing Active Rig Market Share 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. Lower 48 U.S. Land Market Share As of October 13, 2000 Lower 48 U.S. Land Market Share As of October 1, 2010 |
| $0 $3,000 $6,000 $9,000 $12,000 H&P Peers** Average U.S. Land Rig Margin per Day* (12 Months Ended June 30, 2010) 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. 10% 30% 50% 70% H&P Peers**** Estimated U.S. Land Rig Utilization*** (12 Months Ended June 30, 2010) |
| H&P’s International Land Operations We continue to expect quarterly activity (or revenue days) for the segment to sequentially increase by about five percent from the third to the fourth fiscal quarter of 2010. Our first FlexRig in the Middle East is currently working under a long-term contract. We expect to mobilize a second FlexRig to the region in the first fiscal quarter of 2011. Some of the rigs assigned to the Company’s operations in Mexico are returning to the U.S. Excluding any favorable impact corresponding to early termination revenue, we continue to expect average daily rig margins for the International Land segment to decrease by five to ten percent from the third to the fourth fiscal quarter of 2010. |
| H&P’s International Land Operations Active Contracted Idle Total Long-term Contracts Argentina 5 4 9 4 Bahrain 1 1 2 2 Colombia 5 1 6 2 Ecuador 4 4 Mexico 6 6 6 Tunisia 2 2 Total 23 1 5 29 14 Rig Fleet Status (as of September 30, 2010) 1) Some of the six rigs assigned to the Company’s operations in Mexico are returning to the U.S. 2) 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. 3) 14 of 16 FlexRigs (included in the international fleet of 29 rigs) are under long-term contracts. (1) (2), (3) (2) (2) |
| H&P’s Offshore Operations Seven of the Company’s nine offshore platform rigs remain active, including two under long-term contracts. Currently, one of the Company’s seven active platform rigs is being impacted by the deepwater moratorium by way of a reduced standby rate. As we transition from the third to the fourth fiscal quarter of 2010, we continue to expect a decline in average daily rig margins in the range of fifteen to twenty percent. |
| Since March 2010, we have announced the construction of 19 new FlexRigs, all of which are contracted under multi-year term agreements. Having completed the construction of seven of these 19 rigs, we currently have 12 left to be completed through early to mid calendar 2011. New build rigs will be deploying primarily to oil and liquids rich markets including six in the Eagle Ford Shale, three in the Woodford Shale, and two in the Bakken Shale. We continue to have encouraging conversations with customers regarding new build commitments for incremental FlexRigs. H&P New Builds |
| 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 |
| Estimated Estimated Peer H&P FlexRig3 Conventional Fit-for-purpose Average Average Average Mid 2010 (Spot Market) (Spot Market) (Spot Market) 1. Drilling days 26 14 11 Completion days 2 2 2 Moving days 5 4 3 Total rig revenue days per well 33 20 16 2. Drilling contractor dayrate $15,500 $21,500 $24,500 Operator’s other intangible $22,500 $22,500 $22,500 cost per day estimate Total daily cost estimate $38,000 $44,000 $47,000 Total cost per well (daily services) $1,254,000 $880,000 $752,000 3. Total well savings with H&P – per well $502,000 $128,000 per year $11.5MM $2.9MM Increased wells per rig per year versus conventional average: 12 wells Increased wells per rig per year versus peer fit-for-purpose: 5 wells A Value Proposition Example – H&P vs. Competitors |
| 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 |
| -$50 $50 $150 $250 $350 $450 PTEN* UNT NBR** HP Operating Income (Millions) U.S. Land Drilling Operating Income 12 Months Ended June 30, 2010 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. |
| 0% 2% 4% 6% 8% 10% PDS PTEN NBR H&P ROE Analyst Estimates Fiscal Year 2010 Return on Equity (Source: First Call Consensus October 8, 2010) Peer Group Estimated Return on Equity |
| 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 |
| Additional References: |
| U.S. Land Safety Performance (1994 - 2Q10) OSHA Recordable Injury Incidence Rates MANHOURS = 8.9 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 H&P July ’10 = 0.94 IADC 2Q10 = 3.28 INJURIES PER 200,000 MANHOURS MANHOURS WORKED (MM) Delivering Safety – H&P vs. Industry (IADC) |
| $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 COST/MAN HOUR Actual Cost Per Man Hour Worked U.S. Land & Offshore Operations EMR FY09 = .35 FY08 = .34 FY07 = .33 FY06 = .30 FY05 = .32 FY04 = .32 FY03 = .34 FY02 = .37 FY01 = .38 FY00 = .41 FY99 = .38 Safety Excellence Also Generates Savings Reduced Workers Comp and General Liability Losses per Man Hour EMR = Experience Modifier Ratio (Industry Average = 1.00) |
| 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 Source: EnergyPoint Research, Inc. * Trailing four quarters average * * Customer Satisfaction Index * * * 10 = “Highly Satisfied”, 1 = “Highly Dissatisfied” |
| AC Driven Systems & Integrated Top Drive Mechanized Tubular Handling Computerized Controls BOP Handling Satellite Communications Rig Move Capabilities Leader in New Ideas & Applied Technology Driller’s Cabin |
| Drawworks Brake Handle Drawworks Joystick Control Driller on a Conventional Rig vs. FlexRig TM |
| Roughnecks on a Conventional Rig vs. FlexRig |
| FlexRig3 — Performance Sample 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 22,000 24,000 0 5 10 15 20 25 30 35 40 45 Depth (ft) Time (days) Best competitor offset (2007)* Target Curve Jan 2009 - Aug 2010 H&P Average H&P Best FlexRig3 Bakken Shale 59% Improvement 47% Improvement * Represents the customer’s fastest reported Bakken Shale well before deploying a H&P FlexRig. |
| FlexRig4M — Performance Sample 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 0 2 4 6 8 10 12 14 16 Depth (ft) Time (days) Target Jan - Sep 2010 H&P Average 2010 H&P Best FlexRig4M West Texas 21% Improvement 52% Improvement |
| FlexRig4 — Performance Sample 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) Target Jan to Sep 2010 H&P Average - 15 Wells H&P Best FlexRig EagleFord Shale 42% Improvement 22% Improvement |
| FlexRig4S — Performance Sample 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 20 22 24 26 28 30 32 Depth (ft) Time (days) Target Jan to Sep 2010 H&P Average 2010 H&P Best FlexRig4S Marcellus Shale 39% Improvement 16% Improvement |
| 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 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 Improving Rig Counts U.S. Land International Land Aug-2000 Feb-2001 Aug-2001 Feb-2002 Aug-2002 Feb-2003 Aug-2003 Feb-2004 Aug-2004 Feb-2005 Aug-2005 Feb-2006 Aug-2006 Feb-2007 Aug-2007 Feb-2008 Aug-2008 Feb-2009 Aug-2009 Feb-2010 Aug-2010 |
| 0 2 4 6 8 10 12 14 16 1990 1995 2000 2008 2015 2020 2025 2030 2035 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% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 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 Increasing Focus on More Difficult Drilling 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 |
| 28% 31% 37% 43% 51% 68% 80% 53% 69% 0 400 800 1200 1600 2004 2005 2006 2007 2008 2009 Oct-10 Peak (2008) Trough (2009) 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 Increasing Focus on More Difficult Drilling |
| 36% 39% 31% 33% 40% 41% 55% 42% 41% 0 100 200 300 400 500 600 2004 2005 2006 2007 2008 2009 Oct-10 Peak (2008) Trough (2009) 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 Oil Related Drilling Also Increasingly Complex |
| -40% -30% -20% -10% 0% HP U.S. Land PTEN NBR PDS* UNT Change in Rig Count Estimated Change Since Peak in Active U.S. Land Rigs (Smith Bits Weekly Rig Count - October 17, 2008 to October 1, 2010) Changes in Lower 48 U.S. Land Rig Count * PDS’s active rig count includes both PDS and GW rigs. |
| $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 Crude Oil & Natural Gas Prices Source: Energy Information Administration, Short-term Energy Outlook as of 9/8/2010. Crude Oil Natural Gas Dec-94 Dec-95 Dec-96 Dec-97 Dec-98 Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04 Dec-05 Dec-06 Dec-07 Dec-08 Dec-09 Dec-10 Dec-11 |
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