Helmerich & Payne (HP) 8-K Regulation FD Disclosure

Exhibit 99.1

Investor Relations Contact: Juan Pablo Tardio – (918) 588-5383 – juanpablo.tardio@hpinc.com Helmerich & Payne, Inc. Howard Weil Energy Conference March 22, 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 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.

 Oil prices remain strong, but natural gas spot prices are below $5 per mcf. U.S. land and international rig counts are recovering. A colder than average winter left U.S. natural gas inventories slightly above the five-year average. The number of U.S. rigs drilling horizontal wells is at an all-time high. Dayrates continue to recover in the U.S. land spot market, especially for highly-capable rigs. The Market Today

 Economic recovery and political uncertainty Impact of increasing shale gas potential LNG import potential Is the rig count too high? Continuing Debate on U.S. Natural Gas

Increasing Focus on More Difficult Drilling 69% 25% 27% 35% 42% 49% 53% 21% 78% 0 400 800 1200 1600 2003 2004 2005 2006 2007 2008 Peak Trough Mar-10 Number of Active Rigs (Smith Bits S.T.A.T.S.) Sample Week in April 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 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

 Unconventional plays are a “game changer.” Not just for E&P companies but for land drillers, too. “Shale gas divides the world into haves and have nots.” (Large Operator) The Impact of Unconventional Plays

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 (212 Rigs as of 3/22/10)

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 (212 Rigs as of 3/22/10) AC Driven Rigs SCR Rigs Mechanical Rigs Total Available U.S. Land Fleet (Estimates) (~2,500 Rigs)

** Represents the weighted-average rig margin per day for PTEN, NBR and UNT in the Lower 48. * Does not include the impact of early contract termination revenue. Technology and Quality Service Make a Difference H&P’s Margin Premium $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000 Q1CY05 Q2CY05 Q3CY05 Q4CY05 Q1CY06 Q2CY06 Q3CY06 Q4CY06 Q1CY07 Q2CY07 Q3CY07 Q4CY07 Q1CY08 Q2CY08 Q3CY08 Q4CY08 Q1CY09 Q2CY09 Q3CY09 Q4CY09 Average Rig Margin per Day Quarter Ended U.S. Land Average Daywork Margins* H&P Peers**

** 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. H&P’s Utilization Premium Technology and Quality Service Make a Difference 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Q1CY05 Q2CY05 Q3CY05 Q4CY05 Q1CY06 Q2CY06 Q3CY06 Q4CY06 Q1CY07 Q2CY07 Q3CY07 Q4CY07 Q1CY08 Q2CY08 Q3CY08 Q4CY08 Q1CY09 Q2CY09 Q3CY09 Q4CY09 Estimated Avarege Rig Utilization Quarter Ended U.S. Land Estimated Average Rig Utilization* H&P Peers**

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. - $50 $50 $150 $250 $350 $450 $550 PTEN* UNT NBR** HP Operating Income (Millions) U.S. Land Drilling Operating Income 12 Months Ended December 31, 2009

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. 116 128 143 148 155 0 20 40 60 80 100 120 140 160 180 Avg. Q4FY09 Avg. Q1FY10 12/31/2009 1/28/2010 3/22/2010 Number of Active H&P U.S. Land Rigs Active Rigs in Spot Market Active Rigs on Term* Delayed New Builds**

H&P’s U.S. Land Fleet Status * Includes six FlexRigs with signed contracts. All of the remaining 18 uncontracted FlexRigs are FlexRig4’s, which target shallower depth wells. (as of March 22, 2010) 104 46 24 49 106 57 0 15 30 45 60 75 90 105 Under Term Spot Market Active Spot Market Stacked* Number of H&P Rigs Highly Mobile Conventional FlexRigs

 The Company recently secured three multi-year term contracts to build and operate three new FlexRigs, two in the Bakken Shale and one in the Haynesville Shale. In addition, the Company recently secured four five-year term contracts to operate four FlexRigs in the Bakken Shale. These FlexRigs were built in previous years and will be adapted to fit the corresponding requirements. Given the incremental demand for term contracts, the Company now expects an average of 102 rigs to remain under term contracts during all of fiscal 2010. The corresponding estimated annual averages for rigs under term contracts for fiscal 2011 and fiscal 2012 are now 72 and 42 rigs, respectively. H&P’s U.S. Land Operations

H&P’s Global Rig Fleet 264 Total Rigs (Includes New Build Commitments) Offshore * Includes four 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**

 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

 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 Q2FY10 Q3FY10 Q4FY10 Q1FY11 Q2FY11 Q3FY11 Q4FY11 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

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 1 1 2 Venezuela 11 11 Other 1 1 1 Total 20 1 18 39 13 H&P’s International Land Operations Rig Fleet Status (As of March 22, 2010) 1) Includes one rig under a long-term contract still in the U.S. waiting on the operator to determine an international location. 13 of 15 FlexRigs (included in the international fleet of 39 rigs) are under long-term contracts. Since we last provided an update on February 2, 2010, no additional progress has been made in Venezuela. (1) (2) (3)

 Seven of the Company’s nine offshore platform rigs are active. Two of the seven active rigs are under long-term contracts. Average rig margins are expected to decline but remain strong at over $20,000 per day. We are now working on three platform rigs owned by customers under management contracts, two in the U.S. and one in Equatorial Guinea. H&P’s Offshore Operations

 Given improving market conditions and a significant increase in U.S. land rig activity, the company has increased its fiscal 2010 capital expenditures estimate by $65 million to $330 million. Incremental spending includes: Incremental maintenance related expenditures Components required for an additional three potential new builds (in addition to the five announced in December 2009) Other special projects, including the refurbishment of existing rigs to comply with new term contracts H&P’s Capex Estimate for Fiscal 2010

Peer Group Return on Equity * NBR’s, PTEN’s and UNT's calculations exclude charges that were a result of asset retirements and impairments, including ceiling test write-downs. - 3% 0% 3% 6% 9% 12% PTEN NBR UNT HP Estimated ROE Return on Equity* 12 Months Ended December 31 , 2009

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 HP Peer A Peer B Peer C

 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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Additional References:

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 H&P FlexRig Competitor Average Early 2010 (Spot Market) (Spot Market) 1. Drilling days 28 18 Completion days 2 2 Moving days 4 3 Total rig revenue days per well 34 23 2. Drilling contractor dayrate $15,500 $18,500 Operator’s other intangible $15,000 $15,000 cost per day estimate Total daily cost estimate $30,500 $33,500 Total cost per well (daily services) $1,037,000 $770,500 3. Total well savings with H&P – per well $266,500 per year $4.2MM Another Value Proposition Example – H&P vs. Competitors

 Value added from FlexRig operations Significant H&P dayrate premium Increased wells per rig per year: 5 wells Early production: Incremental wells on production Lowest total well cost Another 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

* Represents the customer’s fastest reported Bakken Shale well before deploying a H&P FlexRig. FlexRig3 – Performance Sample 48% Improvement 59% Improvement

FlexRig4M – Performance Sample 59% Improvement

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 PTEN UNT Change in Rig Count Estimated Change Since Peak in Active U.S. Land Rigs (Smith Bits Weekly Rig Count - October 17, 2008 to March 12, 2010)

Crude Oil & Natural Gas Prices Source: Energy Information Administration, Short-term Energy Outlook as of 3/10/2010. 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

Improving Rig Counts U.S. Land International Land * In February 2010, MI Swaco restated its historical rig count, making it more inclusive in certain regions. 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 Feb - 2000 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 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

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. - 3/5/10)

Alaska Onshore Unconventional Offshore Onshore Conventional Projections History TCF Source: Energy Information Administration Annual Energy Outlook 2009 with projections to 2030 (March 2009) Unconventional Natural Gas Production Growing 0 2 4 6 8 10 12 14 1990 1995 2000 2007 2010 2015 2020 2025 2030

 Highlights of FlexRig3s 1. Field Performance vs. customers’ planned drill curves 3265 complete wells as of March 17, 2010 1960 wells (60%) under or on 1077 wells (33%) over 228 wells had no planned curves 2. 96% of FlexRig3s are currently drilling directional, more technically difficult wells. FlexRig3 Performance

 FlexRig4 Performance Highlights of FlexRig4s 1. Field Performance vs. customers’ planned drill curves 3966 complete wells as of March 17, 2010 2578 wells (65%) under or on 1110 wells (28%) over 278 wells had no planned curves 2. 86% of FlexRig4s are currently drilling directional, more technically difficult wells.

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

U.S. Land Safety Performance (1994 – Feb 2010) OSHA Recordable Injury Incidence Rates H&P TRIR = 0.95 IADC 2009 = 2.84 INJURIES PER 200,000 MANHOURS MANHOURS WORKED (MM) Delivering Safety – H&P vs. Industry (IADC) MANHOURS = 7.8 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

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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