H&P’s Global Rig Fleet * Estimates include existing rigs and announced new build commitments. 77 90 89 88 96 111 127 130 128 151 193 224 254 257 279 281 0 50 100 150 200 250 300 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011E* 2012E* Rigs Available Fiscal Year (Ending Sept 30) International Land Offshore U.S. Land

H&P’s Growing Exposure to Oil and Liquids Estimated proportion of H&P’s active U.S. Land rigs in markets primarily associated with oil, liquids rich gas, and dry gas. Oil Liquids Rich Gas Dry Gas

H&P’s Contracted U.S. Land Fleet (as of 2/8/11) 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 13 pending new build FlexRigs. Eagle Ford Shale, 41 Cana Woodford, 24 Haynesville Shale, 23 Permian Basin, 23 Avalon/Bone Springs Shale, 5 Bakken Shale, 22 Marcellus Shale, 13 Barnett Shale, 12 Piceance Basin, 10 Granite Wash, 9 East Woodford, 2 Niobrara, 2 Other Unconventional, 11 Conventional Oil, 12 Conventional Gas, 3

 * Does not include the impact of early contract termination revenue. Technology and Quality Service Make a Difference ** Represents weighted-average rig margin per day for PTEN, NBR and UNT through Q3CY10. 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 Q1CY10 Q2CY10 Q3CY10 Q4CY10 Average Rig Margin per Day Quarter Ended U.S. Land Average Daywork Margins* H&P Peers**

 * Utilization is herein calculated to be average active rigs divided by estimated available marketable rigs during the period. Technology and Quality Service Make a Difference ** Represents estimated average combined utilization for PTEN, NBR and UNT in the Lower 48 through Q3CY10. H&P’s Utilization Premium 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 Q1CY10 Q2CY10 Q3CY10 Q4CY11 Estimated Avarege Rig Utilization Quarter Ended U.S. Land Estimated Average Rig Utilization* H&P Peers**

 H&P’s Global Fleet Under Term Contracts 128 120 105 91 78 72 64 55 0 20 40 60 80 100 120 140 160 Q2FY11 Q3FY11 Q4FY11 Q1FY12 Q2FY12 Q3FY12 Q4FY12 Q1FY13 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

 Since March 2010, H&P has announced the construction of 31 new FlexRigs, all of which are contracted under multi-year term agreements. Having completed the construction of 18 of these 31 rigs, 13 are scheduled to be completed during calendar 2011. New build rigs will be deploying primarily to oil and liquids rich markets including the Eagle Ford Shale, the CANA Woodford Shale, the Bakken Shale, and the Permian Basin. H&P New Builds

 Customers continue to focus on efficiency to achieve lower total well costs. Drilling today involves more complex well designs. Increasing safety and environmental sensitivity Market Trends Favor H&P

Market Observations Strong oil prices and the ability of H&P customers to shift their drilling targets to oil and gas liquids rich plays has been a very positive driver for service providers in the U. S. market. Not long ago, a shift to oil drilling would have been considered a negative for H&P since so much of the activity used to be shallow, vertical, “bread and butter” type drilling. That has changed; today, with the strong emphasis on directional and horizontal drilling, the new mix plays to H&P’s strengths. Older, conventional equipment is increasingly less suitable to the customers’ needs and today’s drilling complexity for both oil and gas. Increasing drilling complexity, a focus on better efficiencies and requirements for strong safety and operational performance should all provide a positive environment for H&P to build shareholder value and capture market share both in the U. S. and internationally.

 While natural gas will still be critical to the future domestic energy picture and to our business, nearly 60% of H&P’s U.S. land fleet is drilling for oil and gas liquids, as compared to a more traditional dry gas target. Driven by incremental new builds and the return of rigs from Mexico, we expect total revenue days in the U.S. land segment to increase between three and four percent from the first to the second fiscal quarter of 2011. Quarterly average rig revenue per day is expected to increase between $400 and $500 per day from the first to the second fiscal quarter of 2011. Including only rigs that are already under fixed commitments, we expect to have an average of 121 rigs under term contract in fiscal 2011 and 76 in fiscal 2012 H&P’s U.S. Land Operations

 While the Company will benefit from FlexRigs going back to work in the U.S. at higher margins than they would have earned in Mexico, segment operating income for the international segment during the second fiscal quarter will be negatively impacted by ceasing operations in Mexico. Total revenue days during the second fiscal quarter are expected to decrease by about 25 percent sequentially from the first fiscal quarter of 2011. Average rig margin per day, including early termination revenues, is expected to decrease by about 35 to 40 percent in the second fiscal quarter as compared to the first fiscal quarter of 2011. H&P’s International Land Operations

 Seven of the Company’s nine offshore platform rigs remain active, including two under long-term contracts. The number of revenue days during the second fiscal quarter of 2011 are expected to increase approximately five percent sequentially. Average rig margin per day is expected to increase by 15 to 20 percent during the second fiscal quarter of 2011 as compared to the first fiscal quarter. Segment operating income during the second fiscal quarter of 2011 will be negatively impacted by approximately $2 million associated with less management contract revenue. H&P’s Offshore Operations

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

Driller on a Conventional Rig vs. FlexRig™ Drawworks Brake Handle Drawworks Joystick Control 31

Safety Excellence Also Generates Savings Reduced Workers Comp and General Liability Losses per Man Hour EMR = Experience Modifier Ratio (Industry Average = 1.00) $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 FY10 = .34 FY09 = .35 FY08 = .34 FY07 = .33 FY06 = .30 FY05 = .32 FY04 = .32 FY03 = .34 FY02 = .37 FY01 = .38 FY00 = .41

Source: EnergyPoint Research, Inc. * Trailing four quarters average Customer Satisfaction Index 10 = “Highly Satisfied”, 1 = “Highly Dissatisfied”

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 2010 (Spot Market) (Spot Market) (Spot Market) 1. Drilling days 20 14 10 Completion days 3 3 3 Moving days 7 4 3 Total rig revenue days per well 30 21 16 2. Drilling contractor dayrate $17,500 $23,000 $25,000 Operator’s other intangible $25,000 $25,000 $25,000 cost per day estimate Total daily cost estimate $42,500 $48,000 $50,000 Total cost per well (daily services) $1,275,000 $1,008,000 $800,000 3. Total well savings with H&P – per well $475,000 $208,000 per year $10.8MM $4.8MM Increased wells per rig per year versus conventional average: 11 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

* Represents the customer’s fastest reported Bakken Shale well before deploying a H&P FlexRig. FlexRig3 – Performance Sample 59% Improvement 45% Improvement

31% Improvement 50% Improvement FlexRig3 – Performance Sample

45% Improvement 30% Improvement FlexRig3 – Performance Sample

FlexRig4M – Performance Sample 33 % Improvement 58 % Improvement

FlexRig4S – Performance Sample 35% Improvement 68% Improvement

Improving Rig Counts U.S. Land International Land 0 300 600 900 1,200 1,500 1,800 2,100 2,400 2,700 0 300 600 900 1,200 1,500 1,800 2,100 2,400 2,700 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

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