10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended September 30, 2010
	OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to

Commission file number 1-4221

HELMERICH & PAYNE, INC.
(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)	73-0679879 (I.R.S. Employer Identification No.)
1437 S. Boulder Ave., Suite 1400, Tulsa, Oklahoma (Address of Principal Executive Offices)	74119-3623 (Zip Code)
(918) 742-5531 Registrant's telephone number, including area code

         Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock ($0.10 par value)	New York Stock Exchange
Preferred Stock Purchase Rights	New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o

         Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

         Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). Yes ý    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

         Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý Accelerated filer o Non-accelerated filer o
(Do not check if a smaller reporting company) Smaller reporting company o

         Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         At March 31, 2010 the aggregate market value of the voting stock held by non-affiliates was $3,896,541,940

         Number of shares of common stock outstanding at November 18, 2010: 105,985,768

DOCUMENTS INCORPORATED BY REFERENCE

         Certain portions of the following documents have been incorporated by reference into this Form 10-K as indicated:

Documents		10-K Parts
	(1)    Annual Report to Stockholders for the fiscal year ended September 30, 2010	Parts I and II
	(2)    Proxy Statement for Annual Meeting of Stockholders to be held March 2, 2011	Part III

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

        THIS REPORT INCLUDES "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF THE SECURITIES ACT OF 1933, AS AMENDED, AND THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS REGARDING THE REGISTRANT'S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS. IN ADDITION, FORWARD-LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY THE USE OF FORWARD-LOOKING TERMINOLOGY SUCH AS "MAY", "WILL", "EXPECT", "INTEND", "ESTIMATE", "ANTICIPATE", "BELIEVE", OR "CONTINUE" OR THE NEGATIVE THEREOF OR SIMILAR TERMINOLOGY. ALTHOUGH THE REGISTRANT BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO BE CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE REGISTRANT'S EXPECTATIONS ARE DISCLOSED IN THIS REPORT UNDER THE CAPTION "RISK FACTORS" BEGINNING ON PAGE 5, AS WELL AS IN MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ON, AND INCORPORATED BY REFERENCE TO, PAGES 6 THROUGH 41 OF THE COMPANY'S ANNUAL REPORT (EXHIBIT 13 TO THIS FORM 10-K). ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE REGISTRANT, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY SUCH CAUTIONARY STATEMENTS. THE REGISTRANT ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE.

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HELMERICH & PAYNE, INC.
FORM 10-K
YEAR ENDED SEPTEMBER 30, 2010
TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		1
Item 1A.	Risk Factors		5
Item 1B.	Unresolved Staff Comments		10
Item 2.	Properties		10
Item 3.	Legal Proceedings		16
Item 4.	[Removed and Reserved.]		16
	Executive Officers of the Company		16
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		17
Item 6.	Selected Financial Data		17
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		18
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		18
Item 8.	Financial Statements and Supplementary Data		18
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		18
Item 9A.	Controls and Procedures		19
Item 9B.	Other Information		22
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		23
Item 11.	Executive Compensation		23
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		23
Item 13.	Certain Relationships and Related Transactions, and Director Independence		23
Item 14.	Principal Accountant Fees and Services		23
PART IV
Item 15.	Exhibits and Financial Statement Schedules		24
SIGNATURES			28

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HELMERICH & PAYNE, INC. AND SUBSIDIARIES
Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the Fiscal Year Ended September 30, 2010

PART I

Item 1.    BUSINESS

        Helmerich & Payne, Inc. (hereafter referred to as the "Company", "we", "us" or "our"), was incorporated under the laws of the State of Delaware on February 3, 1940, and is successor to a business originally organized in 1920. We are primarily engaged in contract drilling of oil and gas wells for others and this business accounts for almost all of our operating revenues.

        Our contract drilling business is composed of three reportable business segments: U.S. land drilling, offshore drilling and international land drilling. Our U.S. land drilling is conducted primarily in Oklahoma, California, Texas, Wyoming, Colorado, Louisiana, Mississippi, Pennsylvania, Utah, Arkansas, New Mexico, Alabama, Montana, North Dakota and West Virginia. Offshore drilling operations are conducted in the Gulf of Mexico, and offshore of California, Trinidad and Equatorial Guinea. Our international land segment operated in seven international locations during fiscal 2010: Ecuador, Colombia, Argentina, Mexico, Tunisia, Bahrain and Venezuela.

        We are also engaged in the ownership, development and operation of commercial real estate and research and development of rotary steerable technology. Each of the businesses operates independently of the others through wholly-owned subsidiaries. This operating decentralization is balanced by centralized finance and legal organizations.

        Our real estate investments located exclusively within Tulsa, Oklahoma, include a shopping center containing approximately 441,000 leasable square feet, multi-tenant industrial warehouse properties containing approximately 990,000 leasable square feet and approximately 210 acres of undeveloped real estate.

        Our subsidiary, TerraVici Drilling Solutions, Inc. ("TerraVici"), is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. We acquired TerraVici to complement our existing drilling rig technology. The process of drilling has become increasingly challenging as preferred well types deviate from simple vertical drilling. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer.

        On June 30, 2010, the Venezuelan government seized 11 rigs owned by our Venezuelan subsidiary and associated real and personal property. We are currently evaluating various remedies, including any recourse we may have against Petroleos de Venezuela, S.A. ("PDVSA"), the Venezuelan state-owned petroleum company, or related parties, any remuneration or reimbursement that we might collect from PDVSA or related parties, and any other sources of recovery for our losses. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. Our financial statements have been prepared with the net assets, results of operations, and cash flows of the Venezuelan operations presented as discontinued operations. The operations from our Venezuelan subsidiary were previously an operating segment within our International Land segment. All historical statements have been restated to conform to this presentation. Refer to Note 2 of the Consolidated Financial Statements.

CONTRACT DRILLING

General

        We believe that we are one of the major land and offshore drilling contractors in the western hemisphere. Operating principally in North and South America, we specialize in shallow to deep drilling in oil and gas producing basins of the United States and in drilling for oil and gas in international locations. In the United States, we draw our customers primarily from the major oil companies and the larger independent oil companies. In South America, our current customers include major international oil companies.

        In fiscal 2010, we received approximately 57 percent of our consolidated operating revenues from our ten largest contract drilling customers. Occidental Oil and Gas Corporation, Devon Energy Production Co. LP, and ExxonMobil Corporation (respectively, "Devon", "Oxy" and "Exxon"), including their affiliates, are our three largest contract drilling customers. We perform drilling services for Oxy on a world-wide basis, for Devon in U.S. land operations, and for Exxon in U.S. land and offshore operations. Revenues from drilling services performed for Oxy, Devon and Exxon in fiscal 2010 accounted for approximately 13 percent, 11 percent and 6 percent, respectively, of our consolidated operating revenues for the same period.

Rigs, Equipment and Facilities

        We provide drilling rigs, equipment, personnel and camps on a contract basis. These services are provided so that our customers may explore for and develop oil and gas from onshore areas and from fixed platforms, tension-leg platforms and spars in offshore areas. Each of the drilling rigs consists of engines, drawworks, a mast, pumps, blowout preventers, a drillstring and related equipment. The intended well depth and the drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job. A land drilling rig may be moved from location to location without modification to the rig. A platform rig is specifically designed to perform drilling operations upon a particular platform. While a platform rig may be moved from its original platform, significant expense is incurred to modify a platform rig for operation on each subsequent platform. In addition to traditional platform rigs, we operate self-moving platform drilling rigs and drilling rigs to be used on tension-leg platforms and spars. The self-moving rig is designed to be moved without the use of expensive derrick barges. The tension-leg platforms and spars allow drilling operations to be conducted in much deeper water than traditional fixed platforms.

        In 1998, we put to work a new generation of highly mobile/depth flexible land drilling rigs (individually the "FlexRig®"). The FlexRig has been able to significantly reduce average rig move and drilling times compared to similar depth-rated traditional land rigs. In addition, the FlexRig allows a greater depth flexibility of between 8,000 to 18,000 feet and provides greater operating efficiency. The original rigs were designated as FlexRig1 and FlexRig2 rigs. In 2001, we announced that we would build the next generation of FlexRigs, known as "FlexRig3 rigs", which incorporated new drilling technology and new environmental and safety design. This new design included integrated top drive, AC electric drive, hydraulic BOP handling system, hydraulic tubular make-up and break-out system, split crown and traveling blocks and an enlarged drill floor that enables simultaneous crew activities.

        Over the last six years, the Company entered into separate drilling contracts with many different customers to build and operate over 160 new FlexRigs, including FlexRig4s (described below). As of November 18, 2010, 12 new FlexRigs remained under construction.

        While FlexRig4s are similar to our FlexRig3s, the FlexRig4s are designed to efficiently drill more shallow depth wells of between 4,000 and 14,000 feet. The FlexRig4 design includes a trailerized version and a skidding version, which incorporate additional environmental and safety design. This design permits the installation of a pipe handling system which allows the rig to be operated by a reduced crew and eliminates the need for a casing stabber in the mast.

        While the trailerized version provides for more efficient well site to well site rig moves, the skidding version allows for drilling of up to 22 wells from a single pad which results in reduced environmental impact. The effective use of technology is important to the maintenance of our competitive position within the drilling industry. As a result of the importance of technology to our business, we expect to continue to develop technology internally.

        We assemble new FlexRigs at our gulf coast facility near Houston, Texas. We also have a 123,000 square foot fabrication facility located on approximately 11 acres near Tulsa, Oklahoma.

Drilling Contracts

        Our drilling contracts are obtained through competitive bidding or as a result of negotiations with customers, and often cover multi-well and multi-year projects. Each drilling rig operates under a separate drilling contract. During fiscal 2010, all drilling services were performed on a "daywork" contract basis,

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under which we charge a fixed rate per day, with the price determined by the location, depth and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. We have previously performed contracts on a combination "footage" and "daywork" basis, under which we charged a fixed rate per foot of hole drilled to a stated depth, usually no deeper than 15,000 feet, and a fixed rate per day for the remainder of the hole. Contracts performed on a "footage" basis involve a greater element of risk to the contractor than do contracts performed on a "daywork" basis. Also, we have previously accepted "turnkey" contracts under which we charge a fixed sum to deliver a hole to a stated depth and agree to furnish services such as testing, coring and casing the hole which are not normally done on a "footage" basis. "Turnkey" contracts entail varying degrees of risk greater than the usual "footage" contract. We have not accepted any "footage" or "turnkey" contracts in over ten years. We believe that under current market conditions, "footage" and "turnkey" contract rates do not adequately compensate us for the added risks. The duration of our drilling contracts are "well-to-well" or for a fixed term. "Well-to-well" contracts are cancelable at the option of either party upon the completion of drilling at any one site. Fixed-term contracts customarily provide for termination at the election of the customer, with an "early termination payment" to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us.

        As of September 30, 2010, we had 142 rigs under fixed-term contracts. While the original duration for these current fixed-term contracts are for six-month to seven-year periods, some fixed-term and well-to-well contracts are expected to be extended for longer periods than the original terms. However, the contracting parties have no legal obligation to extend the contracts. Contracts generally contain renewal or extension provisions exercisable at the option of the customer at prices mutually agreeable to us and the customer. In most instances contracts provide for additional payments for mobilization and demobilization.

Backlog

        Our contract drilling backlog, being the expected future revenue from executed contracts with original terms in excess of one year, as of September 30, 2010 and 2009 was $2,449 million and $2,528 million, respectively. Approximately 59.0 percent of the total September 30, 2010 backlog is not reasonably expected to be filled in fiscal 2011. Term contracts customarily provide for termination at the election of the customer with an "early termination payment" to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid. In addition, a portion of the backlog represents term contracts for new rigs that will be constructed in the future. We obtain certain key rig components from a single or limited number of vendors or fabricators. Certain of these vendors or fabricators are thinly capitalized independent companies located on the Texas gulf coast. Therefore, disruptions in rig component deliveries may occur. Accordingly, the actual amount of revenue earned may vary from the backlog reported. See Item 1A. Risk Factors.

        The following table sets forth the total backlog by reportable segment as of September 30, 2010 and 2009, and the percentage of the September 30, 2010 backlog not reasonably expected to be filled in fiscal 2011:

	Total Backlog Revenue
					Percentage Not Reasonably Expected to be Filled in Fiscal 2011
Reportable Segment	9/30/2010		9/30/2009
	(in millions)
U.S. Land	$	1,999	$	2,016	56.4%
Offshore		139		169	71.9%
International		311		343	69.8%
	$	2,449	$	2,528

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U.S. LAND DRILLING

        At the end of September 2010, 2009 and 2008, we had 220, 201 and 185, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2010 increased by a net of 19 rigs from the end of fiscal 2009. The increase was due to 14 new FlexRigs having been completed and placed into service, 6 transferred from our international operations and 1 rig transferred to our international operations. Our U.S. land operations contributed approximately 75 percent ($1,412.5 million) of our consolidated operating revenues during fiscal 2010, compared with approximately 78 percent ($1,441.2 million) of consolidated operating revenues during fiscal 2009 and approximately 82 percent ($1,542.0 million) of consolidated operating revenues during fiscal 2008. Rig utilization was approximately 73 percent in fiscal 2010 and approximately 68 percent in fiscal 2009, down from approximately 96 percent in fiscal 2008. Our fleet of FlexRigs maintained an average utilization of approximately 87 percent during fiscal 2010 while our conventional and highly mobile rigs had an average utilization rate of approximately 12 percent. A rig is considered to be utilized when it is operated or being mobilized or demobilized under contract. At the close of fiscal 2010, 183 land rigs were working out of 220 available rigs.

OFFSHORE DRILLING

        Our offshore operations contributed approximately 11 percent in both fiscal years 2010 and 2009 ($202.7 million in fiscal 2010 and $204.7 million in fiscal 2009) of the Company's consolidated operating revenues compared to 8 percent in fiscal year 2008 ($154.5) of the Company's consolidated operating revenues. Rig utilization in fiscal 2010 was approximately 80 percent compared to approximately 89 percent in fiscal 2009 and approximately 75 percent in fiscal 2008. At the end of fiscal 2010, we had seven of our nine offshore platform rigs under contract and continued to work under management contracts for three customer-owned rigs. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 34 percent of offshore revenues during fiscal 2010.

INTERNATIONAL LAND DRILLING

General

        Our international land operations contributed approximately 13 percent ($247.2 million) of our consolidated operating revenues during fiscal 2010, compared with approximately 10 percent ($187.1 million) of consolidated operating revenues during fiscal 2009 and 9 percent ($161.1 million) in fiscal 2008. Rig utilization in fiscal 2010 was 71 percent, 70 percent in fiscal 2009 and 72 percent in fiscal 2008.

Colombia

        At the end of fiscal 2010, we had six rigs in Colombia. Our utilization rate was approximately 71 percent during fiscal 2010, approximately 88 percent during fiscal 2009 and approximately 87 percent during fiscal 2008. Revenues generated by Colombian drilling operations contributed approximately 3 percent ($57.5 million) of our consolidated operating revenues during fiscal 2010, compared with 4 percent ($77.3 million) of our consolidated operating revenues during fiscal 2009, and 2 percent ($42.4 million) of our consolidated operating revenues during fiscal 2008. Revenues from drilling services performed for our largest customer in Colombia totaled approximately 2 percent of consolidated operating revenues and approximately 12 percent of international operating revenues during fiscal 2010. The Colombian drilling contracts are primarily with large international or national oil companies.

Ecuador

        At the end of fiscal 2010, we had four rigs in Ecuador. The utilization rate in Ecuador was 100 percent in both fiscal 2010 and 2009, compared to 59 percent in fiscal 2008. Revenues generated by Ecuadorian drilling operations contributed approximately 3 percent of our consolidated operating revenues during fiscal 2010, 2009 and 2008 ($52.1 million, $52.3 million and $55.1 million, respectively). Revenues from drilling services performed for the largest customer in Ecuador totaled approximately 2 percent of consolidated operating revenues and approximately 16 percent of international operating revenues during fiscal 2010. The Ecuadorian drilling contracts are primarily with large international or national oil companies.

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Argentina

        At the end of fiscal 2010, we had nine rigs in Argentina. Our utilization rate was approximately 53 percent during fiscal 2010, approximately 52 percent during fiscal 2009 and approximately 88 percent during fiscal 2008. Revenues generated by Argentine drilling operations contributed approximately 3 percent ($55.9 million) of our consolidated operating revenues during fiscal 2010 compared with approximately 2 percent in both fiscal years 2009 and 2008 ($42.1 million in fiscal 2009 and $44.4 million in fiscal 2008). Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 2 percent of consolidated operating revenues and approximately 19 percent of international operating revenues during fiscal 2010. The Argentine drilling contracts are primarily with large international or national oil companies

Other Locations

        In addition to our operations discussed above, at the end of fiscal 2010 we had two rigs in Tunisia, five rigs in Mexico, one rig in Bahrain and one rig en route to Bahrain.

FINANCIAL

        Information relating to revenues, total assets and operating income by reportable operating segments may be found on, and is incorporated by reference to, pages 78 through 82 of our Annual Report (Exhibit 13 to this Form 10-K).

EMPLOYEES

        We had 6,396 employees within the United States (13 of which were part-time employees) and 1,092 employees in international operations as of September 30, 2010.

AVAILABLE INFORMATION

        Information relating to our internet address and information relating to our Securities and Exchange Commission ("SEC") filings may be found on, and is incorporated by reference to, page 84 of our Annual Report (Exhibit 13 to this Form 10-K).

Item 1A.    RISK FACTORS

        In addition to the risk factors discussed elsewhere in this Report, we caution that the following "Risk Factors" could have a material adverse effect on our business, financial condition and results of operations.

Oil and natural gas prices are volatile, and low prices could negatively affect our financial results in the future.

        Our operations can be materially affected by low oil and gas prices. We believe that any significant reduction in oil and gas prices could depress the level of exploration and production activity and result in a corresponding decline in demand for our services. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and gas. Fluctuations during the last few years in the demand and supply of oil and gas have contributed to, and are likely to continue to contribute to, price volatility. Any prolonged reduction in demand for our services could have a material adverse effect on our business, financial condition and results of operations.

A sluggish global economy may affect our business.

        As a result of volatility in oil and natural gas prices and a continuing sluggish global economic environment, we are unable to determine whether our customers will further reduce spending on exploration and development drilling or whether customers and/or vendors and suppliers will be able to access financing necessary to sustain their current reduced level of operations, fulfill their commitments and/or fund future operations and obligations. The current global economic environment may continue to impact industry fundamentals and result in reduced demand for drilling rigs. These conditions could have a material adverse effect on our business.

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The contract drilling business is highly competitive.

        Competition in contract drilling involves such factors as price, rig availability, efficiency, condition and type of equipment, reputation, operating safety, and customer relations. Competition is primarily on a regional basis and may vary significantly by region at any particular time. Land drilling rigs can be readily moved from one region to another in response to changes in levels of activity, and an oversupply of rigs in any region may result, leading to increased price competition.

        Although many contracts for drilling services are awarded based solely on price, we have been successful in establishing long-term relationships with certain customers which have allowed us to secure drilling work even though we may not have been the lowest bidder for such work. We have continued to attempt to differentiate our services based upon our FlexRigs and our engineering design expertise, operational efficiency, safety and environmental awareness. This strategy is less effective when lower demand for drilling services intensifies price competition and makes it more difficult or impossible to compete on any basis other than price. Also, future improvements in operational efficiency and safety by our competitors could negatively affect our ability to differentiate our services.

The loss of one or a number of our large customers could have a material adverse effect on our business, financial condition and results of operations.

        In fiscal 2010, we received approximately 57 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 29 percent of our consolidated operating revenues from our three largest customers (including their affiliates). We believe that our relationship with all of these customers is good; however, the loss of one or more of our larger customers could have a material adverse effect on our business, financial condition and results of operations.

International uncertainties and local laws could adversely affect our business.

        International operations are subject to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of terrorism, kidnapping of employees, expropriation of equipment as well as expropriation of a particular oil company operator's property and drilling rights, taxation policies, foreign exchange restrictions, currency rate fluctuations and general hazards associated with foreign sovereignty over certain areas in which operations are conducted. On June 30, 2010 the Venezuelan government seized 11 rigs owned by our Venezuelan subsidiary and associated real and personal property.

        There can be no assurance that there will not be changes in local laws, regulations and administrative requirements or the interpretation thereof which could have a material adverse effect on the profitability of our operations or on our ability to continue operations in certain areas. Because of the impact of local laws, our future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. While we believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable.

        Although we attempt to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2010, approximately 13 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2010, approximately 67 percent of the international operating revenues were from operations in South America and approximately 69 percent of South American operating revenues were from Argentina and Colombia.

Our operations are subject to a number of operational risks, including weather.

        Our drilling operations are subject to the many hazards inherent in the business, including inclement weather, blowouts and well fires. These hazards could cause personal injury, suspend drilling operations, seriously damage or destroy the equipment involved and cause substantial damage to producing formations and the surrounding areas. Our offshore drilling operations are also subject to potentially greater

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environmental liability, adverse sea conditions and platform damage or destruction due to collision with aircraft or marine vessels. Specifically, we operate several platform rigs in the Gulf of Mexico. The Gulf of Mexico experiences hurricanes and other extreme weather conditions on a frequent basis, the frequency of which may increase with any climate change. Damage caused by high winds and turbulent seas could potentially curtail operations on such platform rigs for significant periods of time until the damage can be repaired. Moreover, even if our platform rigs are not directly damaged by such storms, we may experience disruptions in operations due to damage to customer platforms and other related facilities in the area.

        We have a new-build rig assembly facility located near the Houston, Texas ship channel. Also, our principal fabricator and other vendors are located in the gulf coast region. Due to their location, these facilities are exposed to potentially greater hurricane damage.

Our operations present risks of loss that, if not insured or indemnified against, could adversely affect our results of operations.

        With the exception of "named wind storm" risk in the Gulf of Mexico, we insure rigs and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self-insure a $1.0 million per occurrence deductible, as well as 10 percent of the estimated replacement cost of offshore rigs and 30 percent of the estimated replacement cost for land rigs and equipment. We also carry insurance with varying deductibles and coverage limits with respect to offshore platform rigs and "named wind storm" risk in the Gulf of Mexico. Rig property insurance coverage expires in May 2011. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, we are generally indemnified under our drilling contracts from this risk. The Company self-insures a number of other risks including loss of earnings and business interruption.

        We have insurance coverage for comprehensive general liability, automobile liability, worker's compensation and employer's liability, and certain other specific risks. Generally, casualty deductibles range from $1 million to $2.5 million per occurrence, depending on the type of claim as well as whether a claim occurs inside or outside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. We retain a significant portion of our expected losses under our worker's compensation, general liability and automobile liability programs. We record estimates for incurred outstanding liabilities for unresolved worker's compensation, general liability and for claims that are incurred but not reported. Estimates are based on adjuster estimates, historical experience or statistical methods that we believe are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

        No assurance can be given that all or a portion of our coverage will not be cancelled during fiscal 2011 or that insurance coverage will continue to be available at rates considered reasonable. No assurance can be given that our insurance and indemnification arrangements will adequately protect us against all liabilities that could result from the hazards of our drilling operations. Incurring a liability for which we are not fully insured or indemnified could materially affect our business, financial condition and results of operations.

We depend on a limited number of vendors, some of which are thinly capitalized and the loss of any of which could disrupt our operations.

        Certain key rig components are either purchased from or fabricated by a single or limited number of vendors, and we have no long-term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply or increased demands in the industry. If we are unable to procure certain of such rig components, we would be required to reduce our rig construction or other operations, which could have a material adverse effect on our business, financial condition and results of operations.

        If our principal fabricator, located on the Texas gulf coast, was unable or unwilling to continue fabricating rig components, then we would have to transfer this work to other acceptable fabricators. This transfer could result in significant delay in the completion of new FlexRigs. Any significant interruption in

7

the fabrication of rig components could have a material adverse impact on our business, financial condition and results of operations.

        Certain key rig components are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from us or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, downturn in the energy industry or reduction or unavailability of credit. Therefore, disruptions in rig component delivery may occur, and such disruptions and terminations could have a material adverse effect on our business, financial condition and results of operations.

Our securities portfolio may lose significant value due to a decline in equity prices and other market-related risks, thus impacting our debt ratio and financial strength.

        At September 30, 2010, we had a portfolio of securities with a total fair value of $326 million. These securities are subject to a wide variety of market-related risks that could substantially reduce or increase the fair value of our holdings. Except for investments in limited partnerships carried at cost, the portfolio is recorded at fair value on our balance sheet with changes in unrealized after-tax value reflected in the equity section of our balance sheet. Any reduction in fair value would have an impact on our debt ratio and financial strength. At November 18, 2010, the fair value of the portfolio had increased to approximately $397 million.

Government regulations and environmental laws could adversely affect our business.

        Many aspects of our operations are subject to government regulation, including those relating to drilling practices and methods and the level of taxation. In addition, the United States and various other countries have environmental regulations which affect drilling operations. Drilling contractors may be liable for damages resulting from pollution. Under United States regulations, drilling contractors must establish financial responsibility to cover potential liability for pollution of offshore waters. Generally, we are indemnified under drilling contracts from liability arising from pollution, except in certain cases of surface pollution. However, the enforceability of indemnification provisions in foreign countries may be questionable.

        We believe that we are in substantial compliance with all legislation and regulations affecting our operations in the drilling of oil and gas wells and in controlling the discharge of wastes. To date, compliance has not materially affected our capital expenditures, earnings, or competitive position, although compliance measures may add to the costs of drilling operations. Additional legislation or regulation may reasonably be anticipated, and the effect thereof on our operations cannot be predicted.

Regulation of greenhouse gases and climate change could have a negative impact on our business.

        Some scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs") and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. We are aware that The United States Congress is actively considering legislation to reduce GHG emissions. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding GHG emissions could materially impact our business, financial condition and results of operations.

        In addition, because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have an adverse impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. A reduced demand for oil and natural gas or reduced economic activity could materially impact our business, financial condition and results of operations.

8

New legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

        The U.S. Environmental Protection Agency, or the EPA, has commenced a study of the potential environmental impacts of hydraulic fracturing, including the impact on drinking water sources and public health, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have and others are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. Any new laws, regulation or permitting requirements regarding hydraulic fracturing could lead to operational delay, or increased operating costs or third party or governmental claims, and could result in additional burdens that could serve to delay or limit the drilling services we provide to third parties whose drilling operations could be impacted by these regulations or increase our costs of compliance and doing business as well as delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing.

Our business and results of operations may be adversely affected by foreign currency devaluation.

        Contracts for work in foreign countries generally provide for payment in United States dollars, except for amounts required to meet local expenses. However, government-owned petroleum companies may in the future require that a greater proportion of these payments be made in local currencies. Based upon current information, we believe that our exposure to potential losses from currency devaluation in foreign countries is immaterial. With the exception of Argentina, all receivables and payments in foreign counties are currently in U.S. dollars. Cash balances are also kept at an insignificant level which assists in reducing exposure. In Argentina we invoice in U.S. dollars and are paid in pesos equivalent to the dollar invoice. Our Argentine subsidiary then remits the dollars to the parent by exchanging pesos through the Argentine Central Bank. While the Argentine peso was devalued in both 2009 and 2010, the devaluation losses in those years were not material to our financial statements.

Fixed-term contracts may in certain instances be terminated without an early termination payment.

        Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an "early termination payment" to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. Even if an early termination payment is owed to us, the current global economic environment may affect the customer's ability to pay the early termination payment.

Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

        We have in place a $400 million senior unsecured credit facility which expires in December of 2011. We had $10 million borrowed and two letters of credit totaling $21.9 million outstanding against the facility at September 30, 2010. As of November 18, 2010, the $10 million outstanding balance had been paid. The interest rate on the borrowings is based on a spread over LIBOR and we pay a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee is determined according to a scale based on a ratio of our total debt to total capitalization. We also have the option to borrow at the prime rate for maturities of less than 30 days. Interest rates could rise for various reasons in the future and increase our total interest expense, depending upon the amount borrowed against the credit lines.

Shortages of drilling equipment and supplies could adversely affect our operations.

        The contract drilling business is highly cyclical. During periods of increased demand for contract drilling services, delays in delivery and shortages of drilling equipment and supplies can occur. These risks are intensified during periods when the industry experiences significant new drilling rig construction or refurbishment. Any such delays or shortages could have a material adverse effect on our business, financial condition and results of operations.

9

New technologies may cause our drilling methods and equipment to become less competitive, resulting in an adverse effect on our financial condition and results of operations.

        Although we take measures to ensure that we use advanced oil and natural gas drilling technology, changes in technology or improvements in competitors' equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive.

Competition for experienced technical personnel may negatively impact our operations or financial results.

        We utilize highly skilled personnel in operating and supporting our businesses. In times of high utilization, it can be difficult to retain, and in some cases find, qualified individuals. Although to date our operations have not been materially affected by competition for personnel, an inability to obtain or find a sufficient number of qualified personnel could materially impact our business, financial condition and results of operations.

Improvements in or new discoveries of alternative energy technologies could have a material adverse affect on our financial condition and results of operations.

        Since our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse impact on our business, financial condition and results of operations.

Item 1B.    UNRESOLVED STAFF COMMENTS

        We have received no written comments regarding our periodic or current reports from the staff of the Securities and Exchange Commission that were issued 180 days or more preceding the end of our 2010 fiscal year and that remain unresolved.

Item 2.    PROPERTIES

CONTRACT DRILLING

        The following table sets forth certain information concerning our U.S. land and offshore drilling rigs as of September 30, 2010:

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
FLEXRIGS
TEXAS		164	18,000	SCR (FlexRig1)	1,500
TEXAS		165	18,000	SCR (FlexRig1)	1,500
TEXAS		166	18,000	SCR (FlexRig1)	1,500
TEXAS		167	18,000	SCR (FlexRig1)	1,500
TEXAS		168	18,000	SCR (FlexRig1)	1,500
TEXAS		169	18,000	SCR (FlexRig1)	1,500
NORTH DAKOTA		179	18,000	SCR (FlexRig2)	1,500
MONTANA		180	18,000	SCR (FlexRig2)	1,500
TEXAS		181	18,000	SCR (FlexRig2)	1,500
TEXAS		182	18,000	SCR (FlexRig2)	1,500
TEXAS		183	18,000	SCR (FlexRig2)	1,500
TEXAS		184	18,000	SCR (FlexRig2)	1,500
TEXAS		185	18,000	SCR (FlexRig2)	1,500
TEXAS		186	18,000	SCR (FlexRig2)	1,500
TEXAS		187	18,000	SCR (FlexRig2)	1,500
TEXAS		188	18,000	SCR (FlexRig2)	1,500
OKLAHOMA		189	18,000	SCR (FlexRig2)	1,500
TEXAS		210	18,000	AC (FlexRig3)	1,500
TEXAS		211	18,000	AC (FlexRig3)	1,500
TEXAS		212	18,000	AC (FlexRig3)	1,500

10

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
TEXAS		213	18,000	AC (FlexRig3)	1,500
NEW MEXICO		214	18,000	AC (FlexRig3)	1,500
COLORADO		215	18,000	AC (FlexRig3)	1,500
TEXAS		216	18,000	AC (FlexRig3)	1,500
PENNSYLVANIA		217	18,000	AC (FlexRig3)	1,500
TEXAS		218	18,000	AC (FlexRig3)	1,500
OKLAHOMA		219	18,000	AC (FlexRig3)	1,500
LOUISIANA		220	18,000	AC (FlexRig3)	1,500
TEXAS		221	18,000	AC (FlexRig3)	1,500
TEXAS		222	18,000	AC (FlexRig3)	1,500
NEW MEXICO		223	18,000	AC (FlexRig3)	1,500
LOUISIANA		224	18,000	AC (FlexRig3)	1,500
PENNSYLVANIA		225	18,000	AC (FlexRig3)	1,500
LOUISIANA		226	18,000	AC (FlexRig3)	1,500
TEXAS		227	18,000	AC (FlexRig3)	1,500
TEXAS		229	18,000	AC (FlexRig3)	1,500
TEXAS		232	18,000	AC (FlexRig3)	1,500
ALABAMA		233	18,000	AC (FlexRig3)	1,500
OKLAHOMA		235	18,000	AC (FlexRig3)	1,500
CALIFORNIA		236	18,000	AC (FlexRig3)	1,500
TEXAS		238	18,000	AC (FlexRig3)	1,500
COLORADO		239	18,000	AC (FlexRig3)	1,500
CALIFORNIA		240	18,000	AC (FlexRig3)	1,500
NORTH DAKOTA		241	18,000	AC (FlexRig3)	1,500
TEXAS		243	18,000	AC (FlexRig3)	1,500
TEXAS		244	18,000	AC (FlexRig3)	1,500
TEXAS		245	18,000	AC (FlexRig3)	1,500
TEXAS		246	18,000	AC (FlexRig3)	1,500
TEXAS		247	18,000	AC (FlexRig3)	1,500
TEXAS		248	18,000	AC (FlexRig3)	1,500
LOUISIANA		249	18,000	AC (FlexRig3)	1,500
OKLAHOMA		250	18,000	AC (FlexRig3)	1,500
OKLAHOMA		251	18,000	AC (FlexRig3)	1,500
OKLAHOMA		252	18,000	AC (FlexRig3)	1,500
TEXAS		254	18,000	AC (FlexRig3)	1,500
NORTH DAKOTA		255	18,000	AC (FlexRig3)	1,500
NORTH DAKOTA		256	18,000	AC (FlexRig3)	1,500
NORTH DAKOTA		257	18,000	AC (FlexRig3)	1,500
NORTH DAKOTA		258	18,000	AC (FlexRig3)	1,500
NORTH DAKOTA		259	18,000	AC (FlexRig3)	1,500
TEXAS		260	18,000	AC (FlexRig3)	1,500
CALIFORNIA		261	18,000	AC (FlexRig3)	1,500
CALIFORNIA		262	18,000	AC (FlexRig3)	1,500
TEXAS		263	18,000	AC (FlexRig3)	1,500
TEXAS		264	18,000	AC (FlexRig3)	1,500
OKLAHOMA		265	18,000	AC (FlexRig3)	1,500
TEXAS		266	18,000	AC (FlexRig3)	1,500
TEXAS		267	18,000	AC (FlexRig3)	1,500
OKLAHOMA		268	18,000	AC (FlexRig3)	1,500
OKLAHOMA		269	18,000	AC (FlexRig3)	1,500
COLORADO		271	14,000	AC (FlexRig4)	1,500
PENNSYLVANIA		272	14,000	AC (FlexRig4)	1,500
WYOMING		273	14,000	AC (FlexRig4)	1,500
PENNSYLVANIA		274	14,000	AC (FlexRig4)	1,500
WYOMING		275	14,000	AC (FlexRig4)	1,500

11

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
NORTH DAKOTA		276	14,000	AC (FlexRig4)	1,500
NORTH DAKOTA		277	14,000	AC (FlexRig4)	1,500
COLORADO		278	14,000	AC (FlexRig4)	1,500
PENNSYLVANIA		279	14,000	AC (FlexRig4)	1,500
COLORADO		280	14,000	AC (FlexRig4)	1,500
TEXAS		281	8,000	AC (FlexRig4)	1,150
NEW MEXICO		282	8,000	AC (FlexRig4)	1,150
NEW MEXICO		283	8,000	AC (FlexRig4)	1,150
PENNSYLVANIA		284	14,000	AC (FlexRig4)	1,500
PENNSYLVANIA		285	14,000	AC (FlexRig4)	1,500
NORTH DAKOTA		286	14,000	AC (FlexRig4)	1,500
PENNSYLVANIA		287	14,000	AC (FlexRig4)	1,500
TEXAS		288	14,000	AC (FlexRig4)	1,500
TEXAS		289	14,000	AC (FlexRig4)	1,500
PENNSYLVANIA		290	14,000	AC (FlexRig4)	1,500
NEW MEXICO		292	8,000	AC (FlexRig4)	1,150
NORTH DAKOTA		293	14,000	AC (FlexRig4)	1,500
NORTH DAKOTA		294	14,000	AC (FlexRig4)	1,500
NORTH DAKOTA		295	14,000	AC (FlexRig4)	1,500
TEXAS		296	14,000	AC (FlexRig4)	1,500
TEXAS		297	14,000	AC (FlexRig4)	1,500
UTAH		298	14,000	AC (FlexRig4)	1,500
TEXAS		299	14,000	AC (FlexRig4)	1,500
NEW MEXICO		300	14,000	AC (FlexRig4)	1,500
ARKANSAS		301	8,000	AC (FlexRig4)	1,150
TEXAS		302	8,000	AC (FlexRig4)	1,150
TEXAS		303	8,000	AC (FlexRig4)	1,150
NEW MEXICO		304	8,000	AC (FlexRig4)	1,150
TEXAS		305	8,000	AC (FlexRig4)	1,150
TEXAS		306	8,000	AC (FlexRig4)	1,150
UTAH		307	14,000	AC (FlexRig4)	1,500
WYOMING		308	14,000	AC (FlexRig4)	1,500
NORTH DAKOTA		309	14,000	AC (FlexRig4)	1,500
WYOMING		310	14,000	AC (FlexRig4)	1,500
UTAH		311	14,000	AC (FlexRig4)	1,500
TEXAS		312	14,000	AC (FlexRig4)	1,500
TEXAS		313	14,000	AC (FlexRig4)	1,500
TEXAS		314	14,000	AC (FlexRig4)	1,500
COLORADO		315	14,000	AC (FlexRig4)	1,500
COLORADO		316	14,000	AC (FlexRig4)	1,500
NORTH DAKOTA		317	14,000	AC (FlexRig4)	1,500
COLORADO		318	14,000	AC (FlexRig4)	1,500
UTAH		319	14,000	AC (FlexRig4)	1,500
PENNSYLVANIA		320	14,000	AC (FlexRig4)	1,500
COLORADO		321	14,000	AC (FlexRig4)	1,500
COLORADO		322	14,000	AC (FlexRig4)	1,500
OKLAHOMA		323	14,000	AC (FlexRig4)	1,500
NORTH DAKOTA		324	14,000	AC (FlexRig4)	1,500
COLORADO		325	14,000	AC (FlexRig4)	1,500
COLORADO		326	14,000	AC (FlexRig4)	1,500
TEXAS		327	14,000	AC (FlexRig4)	1,500
TEXAS		328	14,000	AC (FlexRig4)	1,500
TEXAS		329	14,000	AC (FlexRig4)	1,500
COLORADO		330	14,000	AC (FlexRig4)	1,500
TEXAS		331	14,000	AC (FlexRig4)	1,500

12

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
TEXAS		332	14,000	AC (FlexRig4)	1,500
NEW MEXICO		340	8,000	AC (FlexRig4)	1,150
TEXAS		341	14,000	AC (FlexRig4)	1,500
TEXAS		342	14,000	AC (FlexRig4)	1,500
TEXAS		343	8,000	AC (FlexRig4)	1,150
TEXAS		344	8,000	AC (FlexRig4)	1,150
TEXAS		345	8,000	AC (FlexRig4)	1,150
TEXAS		346	8,000	AC (FlexRig4)	1,150
TEXAS		347	8,000	AC (FlexRig4)	1,150
CALIFORNIA		348	8,000	AC (FlexRig4)	1,150
CALIFORNIA		349	8,000	AC (FlexRig4)	1,150
TEXAS		351	8,000	AC (FlexRig4)	1,150
TEXAS		352	8,000	AC (FlexRig4)	1,150
COLORADO		353	14,000	AC (FlexRig4)	1,500
WEST VIRGINIA		354	14,000	AC (FlexRig4)	1,500
TEXAS		370	18,000	AC (FlexRig3)	1,500
MISSISSIPPI		371	18,000	AC (FlexRig3)	1,500
NEW MEXICO		372	18,000	AC (FlexRig3)	1,500
TEXAS		373	18,000	AC (FlexRig3)	1,500
OKLAHOMA		374	18,000	AC (FlexRig3)	1,500
OKLAHOMA		375	18,000	AC (FlexRig3)	1,500
OKLAHOMA		376	18,000	AC (FlexRig3)	1,500
OKLAHOMA		377	18,000	AC (FlexRig3)	1,500
OKLAHOMA		378	18,000	AC (FlexRig3)	1,500
OKLAHOMA		379	18,000	AC (FlexRig3)	1,500
CALIFORNIA		380	18,000	AC (FlexRig3)	1,500
CALIFORNIA		381	18,000	AC (FlexRig3)	1,500
TEXAS		382	18,000	AC (FlexRig3)	1,500
TEXAS		383	18,000	AC (FlexRig3)	1,500
LOUISIANA		384	18,000	AC (FlexRig3)	1,500
PENNSYLVANIA		385	18,000	AC (FlexRig3)	1,500
NORTH DAKOTA		386	18,000	AC (FlexRig3)	1,500
OKLAHOMA		387	18,000	AC (FlexRig3)	1,500
OKLAHOMA		388	18,000	AC (FlexRig3)	1,500
TEXAS		389	18,000	AC (FlexRig3)	1,500
TEXAS		390	18,000	AC (FlexRig3)	1,500
LOUISIANA		391	18,000	AC (FlexRig3)	1,500
NORTH DAKOTA		392	18,000	AC (FlexRig3)	1,500
TEXAS		393	18,000	AC (FlexRig3)	1,500
LOUISIANA		394	18,000	AC (FlexRig3)	1,500
LOUISIANA		395	18,000	AC (FlexRig3)	1,500
TEXAS		396	18,000	AC (FlexRig3)	1,500
TEXAS		397	18,000	AC (FlexRig3)	1,500
LOUISIANA		398	18,000	AC (FlexRig3)	1,500
TEXAS		399	18,000	AC (FlexRig3)	1,500
TEXAS		415	18,000	AC (FlexRig3)	1,500
NEW MEXICO		416	18,000	AC (FlexRig3)	1,500
LOUISIANA		417	18,000	AC (FlexRig3)	1,500
TEXAS		418	18,000	AC (FlexRig3)	1,500
OKLAHOMA		419	18,000	AC (FlexRig3)	1,500
TEXAS		420	18,000	AC (FlexRig3)	1,500
TEXAS		421	18,000	AC (FlexRig3)	1,500

13

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
HIGHLY MOBILE RIGS
ARKANSAS		140	10,000	Mechanical	900
OKLAHOMA		158	10,000	SCR	900
TEXAS		156	12,000	Mechanical	1,200
WYOMING		159	12,000	Mechanical	1,200
OKLAHOMA		141	14,000	Mechanical	1,200
TEXAS		142	14,000	Mechanical	1,200
OKLAHOMA		143	14,000	Mechanical	1,200
TEXAS		145	14,000	Mechanical	1,200
TEXAS		155	14,000	SCR	1,200
TEXAS		146	16,000	SCR	1,200
UTAH		154	16,000	SCR	1,500
CONVENTIONAL RIGS
OKLAHOMA		110	12,000	SCR	700
OKLAHOMA		96	16,000	SCR	1,000
OKLAHOMA		118	16,000	SCR	1,200
OKLAHOMA		119	16,000	SCR	1,200
TEXAS		120	16,000	SCR	1,200
LOUISIANA		122	16,000	SCR	1,700
OKLAHOMA		162	18,000	SCR	1,500
TEXAS		171	18,000	SCR	1,500
NORTH DAKOTA		172	18,000	Mechanical	1,500
LOUISIANA		79	20,000	SCR	2,000
TEXAS		80	20,000	SCR	1,500
OKLAHOMA		89	20,000	SCR	1,500
OKLAHOMA		92	20,000	SCR	1,500
OKLAHOMA		94	20,000	SCR	1,500
OKLAHOMA		98	20,000	SCR	1,500
TEXAS		97	26,000	SCR	2,000
TEXAS		99	26,000	SCR	2,000
TEXAS		137	26,000	SCR	2,000
TEXAS		149	26,000	SCR	2,000
LOUISIANA		72	30,000	SCR	3,000
OKLAHOMA		73	30,000	SCR	3,000
TEXAS		125	30,000	SCR	3,000
LOUISIANA		134	30,000	SCR	3,000
TEXAS		136	30,000	SCR	3,000
TEXAS		157	30,000	SCR	3,000
LOUISIANA		161	30,000	SCR	3,000
LOUISIANA		163	30,000	SCR	3,000
OFFSHORE PLATFORM RIGS
TRINIDAD		203	20,000	Self-Erecting	2,500
GULF OF MEXICO		205	20,000	Self-Erecting	2,000
GULF OF MEXICO		206	20,000	Self-Erecting	1,500
GULF OF MEXICO		100	30,000	Conventional	3,000
LOUISIANA		105	30,000	Conventional	3,000
LOUISIANA		107	30,000	Conventional	3,000
GULF OF MEXICO		201	30,000	Tension-leg	3,000
GULF OF MEXICO		202	30,000	Tension-leg	3,000
GULF OF MEXICO		204	30,000	Tension-leg	3,000

14

        The following table sets forth information with respect to the utilization of our U.S. land and offshore drilling rigs for the periods indicated:

		Years ended September 30,
		2006			2007			2008			2009			2010
U.S. Land Rigs
	Number of rigs at end of period		113			157			185			201			220
	Average rig utilization rate during period (1)		99	%		97	%		96	%		68	%		73	%
U.S. Offshore Platform Rigs
	Number of rigs at end of period		9			9			9			9			9
	Average rig utilization rate during period (1)		69	%		65	%		75	%		89	%		80	%

(1)

A rig is considered to be utilized when it is operated or being moved, assembled or dismantled under contract.

        The following table sets forth certain information concerning our international drilling rigs as of September 30, 2010:

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
Argentina		123	26,000	SCR	2,100
Argentina		139	30,000+	SCR	3,000
Argentina		151	30,000+	SCR	3,000
Argentina		175	30,000	SCR	3,000
Argentina		177	30,000	SCR	3,000
Argentina		335	8,000	AC (FlexRig4)	1,150
Argentina		336	8,000	AC (FlexRig4)	1,150
Argentina		337	8,000	AC (FlexRig4)	1,150
Argentina		338	8,000	AC (FlexRig4)	1,150
Bahrain		339	8,000	AC (FlexRig4)	1,150
Bahrain*		291	8,000	AC (FlexRig4)	1,150
Colombia		133	30,000	SCR	3,000
Colombia		152	30,000+	SCR	3,000
Colombia		176	18,000	SCR	1,500
Colombia		190	26,000	SCR	2,000
Colombia		333	8,000	AC (FlexRig4)	1,150
Colombia		334	8,000	AC (FlexRig4)	1,150
Ecuador		117	26,000	SCR	2,500
Ecuador		121	20,000	SCR	1,700
Ecuador		132	18,000	SCR	1,500
Ecuador		138	26,000	SCR	2,500
Mexico		230	18,000	AC (FlexRig3)	1,500
Mexico		231	18,000	AC (FlexRig3)	1,500
Mexico^		234	18,000	AC (FlexRig3)	1,500
Mexico		237	18,000	AC (FlexRig3)	1,500
Mexico#		253	18,000	AC (FlexRig3)	1,500
Tunisia		228	18,000	AC (FlexRig3)	1,500
Tunisia		242	18,000	AC (FlexRig3)	1,500

*

En route to drilling location at September 30, 2010

#

En route to U.S. Land segment at September 30, 2010

^

En route to U.S. Land segment during first quarter of fiscal 2011

15

        The following table sets forth information with respect to the utilization of our international drilling rigs for the periods indicated:

	Years ended September 30,
	2006			2007			2008			2009			2010
Number of rigs at end of period		16			16			19			33			28
Average rig utilization rate during period (1)(2)		95	%		89	%		72	%		70	%		71	%

(1)

A rig is considered to be utilized when it is operated or being moved, assembled or dismantled under contract.

(2)

Does not include rigs returned to the United States for major modifications and upgrades.

STOCK PORTFOLIO

        Information required by this item regarding our stock portfolio may be found on, and is incorporated by reference to, page 28 of our Annual Report (Exhibit 13 to this Form 10-K) under the caption, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Item 3.    LEGAL PROCEEDINGS

        We are subject to various claims that arise in the ordinary course of our business. In the opinion of management, the amount of ultimate liability with respect to these actions will not materially affect our business, financial position and results of operations. We are not a party to, and none of our property is subject to, any material pending legal proceedings.

Item 4.    [Removed and reserved.]

OUR EXECUTIVE OFFICERS

        The following table sets forth the names and ages of our executive officers, together with all positions and offices held with the Company by such executive officers. Officers are elected to serve until the meeting of the Board of Directors following the next Annual Meeting of Stockholders and until their successors have been duly elected and have qualified or until their earlier resignation or removal.

W. H. Helmerich, III, 87	Chairman of the Board since 1987; Director since 1949
Hans Helmerich, 52	President and Chief Executive Officer since 1989; Director since 1987
John W. Lindsay, 49	Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. since 2006; Vice President of U.S. Land Operations of Helmerich & Payne International Drilling Co. since 1997
Steven R. Mackey, 59	Executive Vice President, Secretary, General Counsel and Chief Administrative Officer since March 2010; Executive Vice President, Secretary and General Counsel from June 2008 to March 2010; Secretary since 1990; Vice President and General Counsel since 1988
Juan Pablo Tardio, 45	Vice President and Chief Financial Officer since April 2010; Director of Investor Relations from January 2008 to April 2010; Manager of Investor Relations from August 2005 to January 2008

16

PART II

Item 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

        The principal market on which our common stock is traded is the New York Stock Exchange under the symbol "HP". The high and low sale prices per share for the common stock for each quarterly period during the past two fiscal years as reported in the NYSE-Composite Transaction quotations follow:

	2009				2010
Quarter	High		Low		High		Low
First	$	43.27	$	17.01	$	44.90	$	36.51
Second		28.93		19.50		48.58		36.40
Third		37.19		21.76		43.30		33.42
Fourth		41.08		26.64		41.62		36.33

        We paid quarterly cash dividends during the past two fiscal years as shown in the following table:

	Paid per Share				Total Payment
	Fiscal				Fiscal
Quarter	2009		2010		2009		2010
First	$	.050	$	.050	$	5,273,254	$	5,286,530
Second		.050		.050		5,274,814		5,300,194
Third		.050		.050		5,281,430		5,303,994
Fourth		.050		.060		5,281,580		6,363,377

        Payment of future dividends will depend on earnings and other factors.

        As of November 18, 2010, there were 609 record holders of our common stock as listed by the transfer agent's records.

Item 6.    SELECTED FINANCIAL DATA

        The following table summarizes selected financial information and should be read in conjunction with the Consolidated Financial Statements and the Notes thereto and the related Management's Discussion and Analysis of Financial Condition and Results of Operations contained on pages 6 through 41 of our Annual Report (Exhibit 13 to this Form 10-K). Amounts have been restated to reflect the Venezuelan operations as discontinued operations. Refer to Part I, Item 1 above for additional information regarding discontinued operations.

17

Five-year Summary of Selected Financial Data

	2006		2007		2008		2009			2010
	(in thousands except per share amounts)
Operating revenues	$	1,140,219	$	1,502,380	$	1,869,371	$	1,843,740		$	1,875,162
Income from continuing operations		269,852		415,924		420,258		380,546			286,081
Income (loss) from discontinued operations		24,006		33,337		41,480		(27,001	)		(129,769	)
Net Income		293,858		449,261		461,738		353,545			156,312
Basic earnings per share from continuing operations	$	2.58		4.03		4.02		3.61			2.70
Basic earnings per share from discontinued operations	$	0.23		0.32		0.40		(0.26	)		(1.23	)
Basic earnings per share	$	2.81		4.35		4.42		3.35			1.47
Diluted earnings per share from continuing operations	$	2.54		3.95		3.93		3.56			2.66
Diluted earnings per share from discontinued operations	$	0.23		0.32		0.39		(0.25	)		(1.21	)
Diluted earnings per share	$	2.77		4.27		4.32		3.31			1.45
Total assets*		2,134,712		2,885,369		3,588,045		4,161,024			4,265,370
Long-term debt		175,000		445,000		475,000		420,000			360,000
Cash dividends declared per common share		0.1725		0.1800		0.0185		0.2000			0.2200

*

Total assets for all years includes amounts related to discontinued operations

Item 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        Information required by this item may be found on, and is incorporated by reference to, pages 6 through 41 of our Annual Report (Exhibit 13 to this Form 10-K) under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Item 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Information required by this item may be found under the caption "Risk Factors" beginning on page 5 of this Report and on, and is incorporated by reference to, the following pages of our Annual Report (Exhibit 13 to this Form 10-K) under Management's Discussion and Analysis of Financial Condition and Results of Operations and in the Notes to Consolidated Financial Statements:

Market Risk	Page
•       Foreign Currency Exchange Rate Risk		37-38
•       Commodity Price Risk		38-39
•       Interest Rate Risk		39-40
•       Equity Price Risk		40-41

Item 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

        Information required by this item may be found on, and is incorporated by reference to, pages 43 through 83 of our Annual Report (Exhibit 13 to this Form 10-K).

Item 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

        None.

18

Item 9A.    CONTROLS AND PROCEDURES

a)

Evaluation of Disclosure Controls and Procedures.

As of the end of the period covered by this Annual Report on Form 10-K, our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of September 30, 2010. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that:

•

our disclosure controls and procedures are effective at ensuring that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and

•

our disclosure controls and procedures operate such that important information flows to appropriate collection and disclosure points in a timely manner and are effective to ensure that such information is accumulated and communicated to our management, and made known to our Chief Executive Officer and Chief Financial Officer, particularly during the period when this Annual Report on Form 10-K was prepared, as appropriate to allow timely decision regarding the required disclosure.



b)

Management's Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

(i)

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;



(ii)

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and the Board of Directors; and



(iii)

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Although there are inherent limitations in the effectiveness of any system of internal control over financial reporting, based on this evaluation, management has concluded that our internal control over financial reporting was effective as of September 30, 2010.

The independent registered public accounting firm that audited our financial statements, Ernst & Young LLP, has issued an attestation report on our internal control over financial reporting. This report appears below at the end of this Item 9A of Form 10-K.

19

c)

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during our fourth fiscal quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

* * *

20

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Helmerich & Payne, Inc.

        We have audited Helmerich & Payne, Inc.'s internal control over financial reporting as of September 30, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Helmerich & Payne, Inc.'s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, Helmerich & Payne, Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2010, based on the COSO criteria.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2010 and 2009 and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2010 and our report dated November 24, 2010 expressed an unqualified opinion thereon.

	/S/ Ernst & Young LLP
Tulsa, Oklahoma November 24, 2010

21

Item 9B.    OTHER INFORMATION

        None.

22

PART III

Item 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

        The information required by this item is incorporated herein by reference to the material under the captions "Proposal 1—Election of Directors," "Corporate Governance" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2011, to be filed with the Commission not later than 120 days after September 30, 2010. Information required under this item with respect to executive officers under Item 401 of Regulation S-K appears under "Our Executive Officers" in Part I of this Form 10-K.

        We have adopted a Code of Ethics for Principal Executive Officer and Senior Financial Officers. The text of this code is located on our website under "Corporate Governance." Our Internet address is www.hpinc.com. We intend to disclose any amendments to or waivers from this code on our website.

Item 11.    EXECUTIVE COMPENSATION

        The information required by this item regarding executive compensation, as well as director compensation and compensation committee interlocks and insider participation is incorporated herein by reference to the material beginning with the caption "Executive Compensation Discussion and Analysis" and ending with the caption "Potential Payments Upon Termination", as well as under the captions "Director Compensation in Fiscal 2010" and "Compensation Committee Interlocks and Insider Participation" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2011, to be filed with the Commission not later than 120 days after September 30, 2010.

Item 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

        The information required by this item is incorporated herein by reference to the material under the captions "Summary of All Existing Equity Compensation Plans," "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Management" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2011, to be filed with the Commission not later than 120 days after September 30, 2010.

Item 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

        The information required by this item is incorporated herein by reference to the material under the captions "Transactions With Related Persons, Promoters and Certain Control Persons" and "Corporate Governance" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2011, to be filed with the Commission not later than 120 days after September 30, 2010.

Item 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

        The information required by this item is incorporated herein by reference to the material under the caption "Audit Fees" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2011, to be filed with the Commission not later than 120 days after September 30, 2010.

23

PART IV

Item 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a)	1.	Financial Statements:    The following appear in our Annual Report to Stockholders (Exhibit 13 to this Form 10-K) on the pages indicated below and are incorporated herein by reference:
				Page
		Report of Independent Registered Public Accounting Firm			42
		Consolidated Statements of Income for the Years Ended September 30, 2010, 2009 and 2008			43
		Consolidated Balance Sheets at September 30, 2010 and 2009			44-45
		Consolidated Statements of Shareholders' Equity for the Years Ended September 30, 2010, 2009 and 2008			46
		Consolidated Statements of Cash Flows for the Years Ended September 30, 2010, 2009 and 2008			47
		Notes to Consolidated Financial Statements			48-83
	2.	Financial Statement Schedules:    All schedules are omitted as inapplicable or because the required information is contained in the financial statements or included in the notes thereto.
	3.	Exhibits.    The following documents are included as exhibits to this Annual Report on Form 10-K. Exhibits incorporated by reference are duly noted as such.
		3.1	Amended and Restated Certificate of Incorporation of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 3.1 of the Company's Annual Report on Form 10-K to the Securities & Exchange Commission for fiscal 2006, SEC File No. 001-04221.
		3.2	Amended and Restated By-Laws of the Company are incorporated herein by reference to Exhibit 3.1 of the Company's Form 8-K filed on October 11, 2007, SEC File No. 001-04221.
		4.1	Rights Agreement dated as of January 8, 1996, between the Company and The Liberty National Bank and Trust Company of Oklahoma City, N.A. is incorporated herein by reference to the Company's Form 8-A, dated January 18, 1996, SEC File No. 001-04221.
		4.2	Amendment to Rights Agreement dated December 8, 2005, between the Company and UMB Bank, N.A. is incorporated herein by reference to Exhibit 4 of the Company's Form 8-K filed on December 12, 2005, SEC File No. 001-04221.
		*10.1	Consulting Services Agreement between W. H. Helmerich, III and the Company dated March 30, 1990, is incorporated herein by reference to Exhibit 10.3 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221.
		*10.2	Amendment to Consulting Services Agreement between W. H. Helmerich, III and the Company dated December 26, 1990, is incorporated herein by reference to Exhibit 10.2 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221.
		*10.3	Second Amendment to Consulting Services Agreement between W. H. Helmerich, III and the Company dated September 11, 2006, is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed September 13, 2006, SEC File No. 001-04221.
		*10.4	Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated herein by reference to Appendix "A" of the Company's Proxy Statement on Schedule 14A filed on January 27, 1997.

24

*10.5	Form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 99.2 to the Company's Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997.
*10.6	Form of Restricted Stock Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 10.12 to the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1997, SEC File No. 001-04221.
*10.7	Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Appendix "A" of the Company's Proxy Statement on Schedule 14A filed on January 26, 2001.
*10.8	Form of Agreements for Helmerich & Payne, Inc. 2000 Stock Incentive Plan being (i) Restricted Stock Award Agreement, (ii) Incentive Stock Option Agreement and (iii) Nonqualified Stock Option Agreement are incorporated by reference to Exhibit 99.2 to the Company's Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001.
*10.9	Form of Director Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.
*10.10	Form of Change of Control Agreement for Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.
10.11	Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various insurance companies is incorporated herein by reference to Exhibit 10.20 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2002, SEC File No. 001-04221.
10.12	Credit Agreement dated December 18, 2006, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 20, 2006, SEC File No. 001-04221.
10.13	Note Purchase Agreement dated as of June 15, 2009, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various Note purchasers is incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed July 21, 2009, SEC File No. 001-04221.
10.14	Office Lease dated May 30, 2003, between K/B Fund IV and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.18 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2003, SEC File No. 001-04221.
10.15	First Amendment to Lease between ASP, Inc. and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 29, 2008.
*10.16	Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
*10.17	Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan is incorporated herein by reference to Appendix "A" to the Company's Proxy Statement on Schedule 14A filed January 26, 2006.

25

*10.18	Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on December 8, 2009, SEC File No. 001-04221.
*10.19	Form of Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executives: Nonqualified Stock Option Agreement, Incentive Stock Option Agreement, and Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.3 of the Company's Form 8-K filed on December 8, 2009, SEC File No. 001-04221.
*10.20	Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executive officers are incorporated herein by reference to Exhibit 10.4 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
*10.21	Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executive officers are incorporated herein by reference to Exhibit 10.5 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
10.22	Fabrication Contract between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 7, 2006, SEC File No. 001-04221.
10.23	Contract dated July 18, 2007, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to the Company's Form 8-K filed July 7, 2007, SEC File No. 001-04221.
10.24	Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.33 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221.
10.25	Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.34 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221.
*10.26	Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
*10.27	Supplemental Savings Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
*10.28	Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
13.	The Company's Annual Report to Stockholders for fiscal 2010.
21.	List of Subsidiaries of the Company.
23.1	Consent of Independent Registered Public Accounting Firm.

26

31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.	Financial statements from the annual report on Form 10-K of Helmerich & Payne, Inc. for the fiscal year ended September 30, 2010, filed on November 24, 2010, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Shareholders' Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements tagged as blocks of text.

*

Management or Compensatory Plan or Arrangement.

27

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized:

HELMERICH & PAYNE, INC.
By	/s/ HANS HELMERICH Hans Helmerich, President and Chief Executive Officer Date: November 24, 2010

        Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated:

By	/s/ WILLIAM L. ARMSTRONG William L. Armstrong, Director Date: November 24, 2010	By	/s/ RANDY A. FOUTCH Randy A. Foutch, Director November 24, 2010
By	/s/ HANS HELMERICH Hans Helmerich, Director & CEO Date: November 24, 2010	By	/s/ W. H. HELMERICH, III W. H. Helmerich, III, Director Date: November 24, 2010
By	/s/ PAULA MARSHALL Paula Marshall, Director Date: November 24, 2010	By	/s/ FRANCIS ROONEY Francis Rooney, Director Date: November 24, 2010
By	/s/ EDWARD B. RUST, JR. Edward B. Rust, Jr., Director Date: November 24, 2010	By	/s/ JOHN D. ZEGLIS John D. Zeglis, Director Date: November 24, 2010
By	/s/ JUAN PABLO TARDIO Juan Pablo Tardio (Principal Financial Officer) Date: November 24, 2010	By	/s/ GORDON K. HELM Gordon K. Helm (Principal Accounting Officer) Date: November 24, 2010

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Exhibit Index

        The following documents are included as exhibits to this Annual Report on Form 10-K. Exhibits incorporated herein are duly noted as such.

Exhibit No.		Description
	3.1	Amended and Restated Certificate of Incorporation of Helmerich & Payne, Inc. is incorporated by reference to Exhibit 3.1 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221.
	3.2	Amended and Restated By-Laws of the Company are incorporated herein by reference to Exhibit 3.1 of the Company's Form 8-K filed on October 11, 2007, SEC File No. 001-04221.
	4.1	Rights Agreement dated as of January 8, 1996, between the Company and The Liberty National Bank and Trust Company of Oklahoma City, N.A. is incorporated herein by reference to the Company's Form 8-A, dated January 18, 1996, SEC File No. 001-04221.
	4.2	Amendment to Rights Agreement dated December 8, 2005, between the Company and UMB Bank, N.A. is incorporated herein by reference to Exhibit 4 of the Company's Form 8-K filed on December 12, 2005, SEC File No. 001-04221.
	*10.1	Consulting Services Agreement between W. H. Helmerich, III and the Company dated March 30, 1990, is incorporated herein by reference to Exhibit 10.3 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221.
	*10.2	Amendment to Consulting Services Agreement between W. H. Helmerich, III and the Company dated December 26, 1990, is incorporated herein by reference to Exhibit 10.2 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221.
	*10.3	Second Amendment to Consulting Services Agreement between W. H. Helmerich, III and the Company dated September 11, 2006, is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed September 13, 2006, SEC File No. 001-04221.
	*10.4	Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated herein by reference to Appendix "A" of the Company's Proxy Statement on Schedule 14A filed on January 27, 1997.
	*10.5	Form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 99.2 to the Company's Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997.
	*10.6	Form of Restricted Stock Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated by reference to Exhibit 10.12 to the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1997, SEC File No. 001-04221.
	*10.7	Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Appendix "A" of the Company's Proxy Statement on Schedule 14A filed on January 26, 2001.
	*10.8	Form of Agreements for Helmerich & Payne, Inc. 2000 Stock Incentive Plan being (i) Restricted Stock Award Agreement, (ii) Incentive Stock Option Agreement and (iii) Nonqualified Stock Option Agreement are incorporated by reference to Exhibit 99.2 to the Company's Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001.
	*10.9	Form of Director Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.
	*10.10	Form of Change of Control Agreement for Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.

29

Exhibit No.		Description
	10.11	Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various insurance companies is incorporated herein by reference to Exhibit 10.20 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2002, SEC File No. 001-04221.
	10.12	Credit Agreement dated December 18, 2006, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 20, 2006, SEC File No. 001-04221.
	10.13	Note Purchase Agreement dated as of June 15, 2009, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various Note purchasers is incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed July 21, 2009, SEC File No. 001-04221.
	10.14	Office Lease dated May 30, 2003, between K/B Fund IV and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.18 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2003, SEC File No. 001-04221.
	10.15	First Amendment to Lease between ASP, Inc. and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 29, 2008.
	*10.16	Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
	*10.17	Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan is incorporated herein by reference to Appendix "A" to the Company's Proxy Statement on Schedule 14A filed January 26, 2006.
	*10.18	Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on December 8, 2009, SEC File No. 001-04221.
	*10.19	Form of Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executives: Nonqualified Stock Option Agreement, Incentive Stock Option Agreement, and Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.3 of the Company's Form 8-K filed on December 8, 2009, SEC File No. 001-04221.
	*10.20	Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executive officers are incorporated herein by reference to Exhibit 10.4 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
	*10.21	Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executive officers are incorporated herein by reference to Exhibit 10.5 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
	10.22	Fabrication Contract between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 7, 2006, SEC File No. 001-04221.
	10.23	Contract dated July 18, 2007, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to the Company's Form 8-K filed July 7, 2007, SEC File No. 001-04221.

30

Exhibit No.		Description
	10.24	Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.33 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221.
	10.25	Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.34 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221.
	*10.26	Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
	*10.27	Supplemental Savings Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
	*10.28	Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
	13.	The Company's Annual Report to Stockholders for fiscal 2010.
	21.	List of Subsidiaries of the Company.
	23.1	Consent of Independent Registered Public Accounting Firm.
	31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101.	Financial statements from the annual report on Form 10-K of Helmerich & Payne, Inc. for the fiscal year ended September 30, 2010, filed on November 24, 2010, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Shareholders' Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements tagged as blocks of text.

*

Management or Compensatory Plan or Arrangement.

31

EX-13

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Exhibit 13

Helmerich & Payne, Inc.

Helmerich & Payne, Inc. is the holding Company for
Helmerich & Payne International Drilling Co., an international
drilling contractor with land and offshore operations in the
United States, South America, Mexico, Trinidad, Africa
and the Middle East. Holdings also include commercial real
estate properties in the Tulsa, Oklahoma area, and an
energy-weighted portfolio of securities valued at approximately
$326 million as of September 30, 2010.

FINANCIAL HIGHLIGHTS

Years Ended September 30,	2010		2009		2008
		(in thousands, except per share amounts)
Operating Revenues		$1,875,162		$1,843,740		$1,869,371
Net Income		156,312		353,545		461,738
Diluted Earnings per Share		1.45		3.31		4.32
Dividends Paid per Share		.210		.200		.185
Capital Expenditures		329,572		876,839		697,906
Total Assets		4,265,370		4,161,024		3,588,045

To the Co-owners
of Helmerich & Payne, Inc.:

         Two thousand and ten was a year of transition and recovery; let me take the opportunity to reflect on some of the milestones that stand out. First, Venezuela was certainly a disappointing episode for the Company this year but, while perhaps receiving more than its fair share of attention, it is now behind us and we have moved forward.

         The industry fought its way back from a dramatic "once in 30 year" free fall that started in the early Fall of 2008 and bottomed in June of 2009. In terms of utilization, margins, operating income and returns, we outpaced our land drilling peers during the recovery that unfolded in the second half of 2009 and continued through our fiscal year 2010. Industry-wide activity steadily improved through the year, as the U.S. land count currently stands at 80 percent of the number of rigs that were running in October of 2008. For the Company's rig count, we have exceeded that percentage. During 2010, we reactivated nearly 90 rigs, our largest single-year effort, and the Company recently crossed the threshold of having 190 rigs operating in the U.S. This surpassed our previous record during the last cyclical peak and achieves the highest level of activity in the U.S. in the Company's history. In addition to better utilization, we outpaced our peers by maintaining significantly higher premiums in average rig revenue and margins during all parts of the cycle.

         Another milestone worthy of mention is our new build effort in 2010. In a year where natural gas prices have fallen in half, the Company has been able to secure 23 new FlexRig orders since last March, all long-term contracts with favorable returns. These new orders help us maintain our market leadership in the AC powered land rig market where three-quarters of our U.S. fleet is AC powered compared to one-third for the nearest competitor. Our experience gives us a simple, but profound advantage that enables us to build rigs for a lower cost and achieve higher returns than our peers. That experience represents over 560 rig years of running AC powered technology in the field and captures learnings from more than ten years of our own design and integrated manufacturing efforts.

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         In November, we rolled our 100^th FlexRig3 off the line. The FlexRig3 is the flagship of our fleet, and we marked the event with a celebration at our Greens Port assembly facility in Houston, Texas. When we read so much about the diminished level of manufacturing in our country, it's nice to have the opportunity to recognize the efforts of people who have built over 200 FlexRigs in that facility. The 100^th FlexRig3 on display contained multiple feature enhancements and improvements compared to the first Flex3 assembled in 2002. These improvements come from "eating your own cooking" and a Company-wide focus, from our design and engineering effort through our field operations, to constantly improve and drive innovations that enhance performance.

         The Company had two milestone retirements in 2010: Doug Fears, Executive Vice President and Chief Financial Officer of the Company for over 22 years, and Alan Orr, Executive Vice President, Drilling Technology and Development, who spearheaded the FlexRig design effort and had 35 years of service.

         Finally, the Company celebrated its 90^th anniversary in 2010. Relatedly, we want to recognize my dad, Walt Helmerich, for his 60^th year of involvement with H&P. He started work fresh out of Harvard Business School in 1950 and continues today as the Company's Chairman. We are thankful for his leadership and are enormously indebted to him and to the many other loyal employees, past and present, who have built the Company's reputation the old-fashioned way: brick by brick, precept upon precept. Our job going forward is to vigorously defend and advance a powerful combination: Being the world's oldest and most experienced land contract driller and, at the same time, the most innovative and forward thinking. That is the charge we embrace heading into 2011.

	Sincerely,
	Hans Helmerich President
November 24, 2010

3

Financial & Operating Review

HELMERICH & PAYNE, INC.

Years Ended September 30,			2010		2009		2008
SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*†
Operating Revenues				$1,875,162		$1,843,740		$1,869,371
Operating Costs, excluding depreciation				1,071,959		944,780		987,838
Depreciation**				262,658		227,535		195,343
General and Administrative Expense				81,479		58,822		56,429
Operating Income (Loss)				451,796		608,875		640,084
Interest and Dividend Income				1,811		2,755		3,524
Gain on Sale of Investment Securities				—		—		21,994
Interest Expense				17,158		13,590		18,721
Income (Loss) from Continuing Operations				286,081		380,546		420,258
Net Income				156,312		353,545		461,738
Diluted Earnings Per Common Share:
	Income (Loss) from Continuing Operations			2.66		3.56		3.93
	Net Income			1.45		3.31		4.32
*$000's omitted, except per share data †All data excludes discontinued operations except net income. **2004 includes an asset impairment of $51,516 and depreciation of $88,075
SUMMARY FINANCIAL DATA*
Cash**				$      63,020		$      96,142		$      77,549
Working Capital**				417,888		157,103		274,519
Investments				320,712		356,404		199,266
Property, Plant, and Equipment, Net**				3,275,020		3,194,273		2,605,384
Total Assets				4,265,370		4,161,024		3,588,045
Long-term Debt				360,000		420,000		475,000
Shareholders' Equity				2,807,465		2,683,009		2,265,474
Capital Expenditures				329,572		876,839		697,906
*$000's omitted ** Excludes discontinued operations.
Rig Fleet Summary
Drilling Rigs –
	U. S. Land – FlexRigs			182		163		146
	U. S. Land – Highly Mobile			11		11		12
	U. S. Land – Conventional			27		27		27
	Offshore Platform			9		9		9
	International Land†			28		33		19
		Total Rig Fleet		257		243		213
Rig Utilization Percentage –
	U. S. Land – FlexRigs			87		76		100
	U. S. Land – Highly Mobile			0		29		83
	U. S. Land – Conventional			17		39		80
	U. S. Land – All Rigs			73		68		96
	Offshore Platform			80		89		75
	International Land†			71		70		72
†Excludes discontinued operations.

4

2007		2006		2005		2004			2003		2002		2001		2000
	$1,502,380		$1,140,219		$   733,902		$   532,759			$   472,407		$   472,865		$   479,132		$   348,495
	788,967		606,945		435,057		375,600			322,553		319,330		295,021		223,945
	137,187		93,363		88,483		139,591			76,748		56,208		46,134		69,329
	47,401		51,873		41,015		37,661			41,003		36,563		28,180		23,306
	586,506		395,341		182,355		(14,698	)		35,845		61,946		113,890		32,465
	4,143		9,688		5,772		1,622			2,467		3,624		9,128		18,144
	65,458		19,866		26,969		25,418			5,529		24,820		1,189		13,295
	9,591		6,499		12,416		12,541			12,357		993		1,715		2,715
	415,924		269,852		120,666		(1,016	)		16,417		55,017		71,046		36,882
	449,261		293,858		127,606		4,359			17,873		63,517		144,254		82,300
	3.95		2.54		1.16		(0.01	)		0.17		0.54		0.70		0.36
	4.27		2.77		1.23		0.04			0.17		0.63		1.42		0.82

$      67,445	$      32,193	$   284,460	$      63,785	$      29,763	$      45,699	$   127,395	$   106,171
209,766	126,540	378,496	157,266	82,712	87,584	201,549	165,513
223,360	218,309	178,452	161,532	158,770	150,175	203,271	307,425
2,068,812	1,399,974	897,504	913,338	983,026	824,815	565,195	489,722
2,885,369	2,134,712	1,663,350	1,406,844	1,417,770	1,227,313	1,300,121	1,200,854
445,000	175,000	200,000	200,000	200,000	100,000	50,000	50,000
1,815,516	1,381,892	1,079,238	914,110	917,251	895,170	1,026,477	955,703
885,583	521,847	78,677	86,057	233,850	298,295	152,123	62,224
118	73	50	48	43	26	13	6
12	12	12	11	11	11	11	10
27	28	29	28	29	29	25	22
9	9	11	11	12	12	10	10
16	16	14	19	21	19	20	22
182	138	116	117	116	97	79	70
100	100	100	99	97	96	100	99
93	100	99	91	89	97	89	95
87	95	82	67	58	70	99	77
97	99	94	87	81	84	97	85
65	69	53	48	51	83	98	94
89	95	80	47	42	59	69	60

5

Management's Discussion & Analysis of Financial Condition and Results of Operations

Helmerich & Payne, Inc.

RISK FACTORS AND FORWARD-LOOKING STATEMENTS

The following discussion should be read in conjunction with Part I of our Form 10-K as well as the Consolidated Financial Statements and related notes thereto. Our future operating results may be affected by various trends and factors, which are beyond our control. These include, among other factors, fluctuations in oil and natural gas prices, unexpected expiration or termination of drilling contracts, currency exchange gains and losses, expropriation of real and personal property, changes in general economic conditions, disruptions to the global credit markets, rapid or unexpected changes in technologies, risks of foreign operations, uninsured risks, changes in domestic and foreign policies, laws and regulations and uncertain business conditions that affect our businesses. Accordingly, past results and trends should not be used by investors to anticipate future results or trends.

With the exception of historical information, the matters discussed in Management's Discussion & Analysis of Financial Condition and Results of Operations include forward-looking statements. These forward-looking statements are based on various assumptions. We caution that, while we believe such assumptions to be reasonable and make them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. We are including this cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by us or persons acting on our behalf. The factors identified in this cautionary statement and those factors discussed under Risk Factors beginning on page 5 of our Form 10-K are important factors (but not necessarily all important factors) that could cause actual

6

results to differ materially from those expressed in any forward-looking statement made by us or persons acting on our behalf. We undertake no duty to update or revise our forward-looking statements based on changes of internal estimates or expectations or otherwise.

EXECUTIVE SUMMARY

Helmerich & Payne, Inc. is primarily a contract drilling company which owned and operated a total of 257 drilling rigs at September 30, 2010. Our contract drilling segments include the U.S. Land segment in which we had 220 rigs, the Offshore segment in which we had 9 offshore platform rigs, and the International Land segment in which we had 28 rigs at September 30, 2010. After experiencing a very significant decline in rig utilization and spot pricing in the U.S. land market during the prior year, we experienced a partial and encouraging recovery during 2010. A confluence of events in the U.S. contributed to this recovery, including increased levels of drilling to hold acreage by production, operator access to capital through several favorable exploration and production joint venture agreements, and the shift of operators' drilling budgets from natural gas to crude oil and liquids-rich projects. With some exceptions, international markets in general also recovered during fiscal 2010, allowing us to generate strong results from continuing operations as compared to the prior year. Activity in our Offshore segment remained relatively strong and was not significantly impacted by the deepwater drilling moratorium in the Gulf of Mexico. Drilling continues to become more challenging and technologically focused, requiring more highly capable rigs which are expected to be in short supply as demand improves. We are well positioned to meet the long-term needs of our customers and to compete successfully for opportunities in any improving market.

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As further discussed in Note 2 of the Consolidated Financial Statements, our Venezuelan subsidiary was classified as discontinued operations on June 30, 2010, after the announced "forceful acquisition" of our drilling assets in that country by the Venezuelan government. The subsidiary was previously classified as an operating segment within our International Land segment. Accordingly, we reclassified the financial statements and related disclosures for all periods presented. These reclassifications had no impact on net income, total assets or total shareholders' equity. Unless otherwise indicated, the following discussion pertains only to our continuing operations. All historical statements and statistical data have been restated to exclude discontinued operations. Unless otherwise indicated, references to 2010, 2009 and 2008 in the following discussion are referring to our fiscal year 2010, 2009 and 2008.

RESULTS OF OPERATIONS

All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net income for 2010 was $156.3 million ($1.45 per share), compared with $353.5 million ($3.31 per share) for 2009 and $461.7 million ($4.32 per share) for 2008. Included in our net income for 2008 were after-tax gains from the sale of investment securities of $13.5 million ($0.13 per share). Net income also includes after-tax gains from the sale of assets of $3.3 million ($0.03 per share) in 2010, $3.4 million ($0.03 per share) in 2009 and $8.3 million ($0.08 per share) in 2008. Included in net income in 2009 and 2008 are after-tax gains of $0.3 million and $6.5 million ($0.06 per share), respectively, from involuntary conversion of long-lived assets that sustained significant damage as a result of Hurricane Katrina in 2005. Also included in net income is our portion of income from an equity affiliate, Atwood Oceanics, Inc. ("Atwood"), of $0.09 per share in 2009 and $0.16 per

8

share in 2008. Effective April 1, 2009, we determined we no longer had the ability to exercise significant influence over operating and financial policies at Atwood and discontinued accounting for Atwood using the equity method. The investment in Atwood is now recorded at fair value with changes included as a component of other comprehensive income.

Consolidated operating revenues were $1,875.2 million in 2010, $1,843.7 million in 2009, and $1,869.4 million in 2008. In 2009, as oil and natural gas prices declined and uncertainty in the capital markets increased, customers reduced spending on exploration and development drilling causing a reduction in rig utilization. Our U.S. land rig utilization was 73 percent in 2010, 68 percent in 2009 and 96 percent in 2008. The average number of U.S. land rigs available was 207 rigs in 2010, 194 rigs in 2009 and 171 rigs in 2008. Revenue in the Offshore segment remained steady in 2010 and 2009 after increasing in 2009 from 2008. Rig utilization for offshore rigs was 80 percent in 2010, compared to 89 percent in 2009 and 75 percent in 2008. International rig revenues increased in 2010 after staying relatively level in 2009 from 2008. Rig utilization in our International Land segment was 71 percent in 2010, 70 percent in 2009 and 72 percent in 2008.

We did not sell any investment securities in 2010 or 2009, but recorded gains of $22.0 million in 2008 from the sale of investment securities. Interest and dividend income was $1.8 million, $2.8 million and $3.5 million in 2010, 2009 and 2008, respectively.

Direct operating costs in 2010 were $1,072.0 million or 57 percent of operating revenues, compared with $944.8 million or 51 percent

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of operating revenues in 2009 and $987.8 million or 53 percent of operating revenues in 2008.

Depreciation expense was $262.7 million in 2010, $227.5 million in 2009 and $195.3 million in 2008. Included in depreciation are abandonments of equipment of $4.2 million in 2010, $5.3 million in 2009, and $13.3 million in 2008. Depreciation expense, exclusive of the abandonments, increased over the three-year period as we placed into service 23 new rigs in 2010, 25 in 2009 and 29 in 2008. Depreciation expense in 2011 is expected to increase from 2010 from new rigs placed into service during 2010 and additional rigs placed into service during 2011. (See Liquidity and Capital Resources.)

As conditions warrant, management performs an analysis of the industry market conditions impacting its long-lived assets in each drilling segment. Based on this analysis, management determines if any impairment is required. In 2010, 2009 and 2008, no impairment was recorded.

General and administrative expenses totaled $81.5 million in 2010, $58.8 million in 2009, and $56.4 million in 2008. The $22.7 million increase in 2010 from 2009 is partially due to an increase in stock-based compensation of $7.5 million. The increase in stock-based compensation is comprised of additional expense of $4.9 million resulting from a change in our Long-Term Incentive Plan which permitted continued equity vesting after retirement, and $2.6 million expense resulting from options granted in 2010 having a higher grant price and value than options amortized at September 30, 2009. Also contributing to increased general and administrative expenses in 2010 were additional pension expense of $2.2 million and an increase of $10.3 million from increases in employee salaries,

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an increase in the number of employees and an increase in bonus accruals.

Interest expense was $17.2 million in 2010, $13.6 million in 2009, and $18.7 million in 2008. Interest expense is primarily attributable to the fixed-rate debt outstanding and advances on the senior credit facility. Interest expense increased in 2010 from 2009 primarily as a result of borrowings under a fixed rate credit facility obtained in July 2009. Capitalized interest was $6.4 million, $6.6 million and $4.7 million in 2010, 2009 and 2008, respectively. All of the capitalized interest is attributable to our rig construction program.

The provision for income taxes totaled $152.2 million in 2010, $227.9 million in 2009, and $242.6 million in 2008. The effective income tax rate decreased to 35 percent in 2010 from 38 percent in 2009 and 2008. Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets is based on management's judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future. (See Note 4 of the Consolidated Financial Statements for additional income tax disclosures.)

On May 21, 2008, we acquired a private limited partnership, TerraVici Drilling Solutions ("TerraVici") in a transaction accounted for under the purchase method of accounting. Under the purchase

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method of accounting, the assets and liabilities of TerraVici were recorded as of the acquisition date, at their respective fair values, and consolidated with our financial statements. The operations for TerraVici are included with all other non-reportable business segments.

TerraVici is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. We acquired TerraVici to complement technology currently used with FlexRigs. The process of drilling has become increasingly challenging as preferred well types deviate from simple vertical drilling. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer.

We paid a total purchase price of $12.2 million, including acquisition related fees of $1.2 million. In conjunction with the acquisition, we recorded an in-process research and development ("IPR&D") charge of $11.1 million in 2008. The IPR&D represented rotary steerable system ("RSS") tools under development by TerraVici at the date of acquisition that had not yet achieved technological feasibility and would have no future alternative use. The $11.1 million estimated fair value of the IPR&D was derived using the multi-period excess-earnings method. The terms of the transaction provide for future contingency payments of up to $11 million based on specific commerciality milestones and certain earn-out provisions based on future earnings being met. Pursuant to the satisfaction of a performance milestone, we paid $4.0 million subsequent to September 30, 2010. This additional payment will be accounted for as goodwill.

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During 2010, 2009 and 2008, we incurred $12.3 million, $9.7 million and $1.8 million, respectively, of research and development expenses related to ongoing development of the RSS. We anticipate research and development expenses to continue during 2011.

In 2010 and 2009, we had a net loss from discontinued operations of $129.8 million and $27.0 million, respectively, compared to net income from discontinued operations in 2008 of $41.5 million. We determined that, as of the beginning of the second quarter of fiscal 2009 and forward, services to our customer in Venezuela, Petroleos de Venezuela, S.A. ("PDVSA"), no longer met the revenue recognition criteria as collectability became uncertain. The ability to collect accounts receivable in U.S. dollars from PDVSA deteriorated to the point that, during the second quarter of fiscal 2009, we decided to discontinue work as contracts expired. All of our eleven rigs in Venezuela were active at the end of 2008 and one rig remained active at the end of 2009, but became idle during the first quarter of 2010. As a result of the change in revenue recognition, $57.9 million of revenue was not recorded during 2009 and only cash collected of $13.5 million was recorded as revenue in 2010. Contributing to the net loss in 2010 was approximately $70.2 million loss from derecognizing our Venezuelan property and equipment and inventory as a result of the seizing of our assets by the Venezuelan government. Accounts receivable, payables and other deferred charges and credits, netting to approximately $9.5 million, were also written off because the related future cash inflows and outflows associated with them were no longer expected to occur. At September 30, 2010, we had approximately $31.3 million (U.S. currency equivalent) cash balances in Venezuela. Our Venezuelan subsidiary has had, since July 22, 2008, an outstanding application

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with the Venezuelan government requesting approval to remit approximately $14.2 million as a dividend to its U.S. based parent, converting bolivar fuerte cash balances to U.S. dollars. Because of the seizure of our assets by the Venezuelan government and our inability to obtain approval of the dividend, we also impaired approximately $21.1 million cash as of September 30, 2010. On January 8, 2010, the Venezuelan government devalued its currency and, as a result, we recorded an exchange loss of approximately $20.4 million which is included in discontinued operations for 2010.

We are currently evaluating various remedies, including any recourse we may have against PDVSA or related parties, any remuneration or reimbursement that we might collect from PDVSA or related parties, and any other sources of recovery for our losses. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No gain contingencies are recognized in our Consolidated Financial Statements.

The following tables summarize operations by reportable operating segment.

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COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2010 AND 2009

	2010			2009			% Change
U.S. LAND OPERATIONS		(in thousands, except operating statistics)
Operating revenues		$1,412,495			$1,441,164		(2.0	)%
Direct operating expenses		772,766			663,385		16.5
General and administrative expense		23,799			16,812		41.6
Depreciation		211,652			187,259		13.0
Segment operating income		$   404,278			$   573,708		(29.5	)
Operating Statistics:
Revenue days		55,051			48,055		14.6	%
Average rig revenue per day		$      23,909			$      28,194		(15.2	)
Average rig expense per day		$      12,288			$      12,009		2.3
Average rig margin per day	$	11,621		$	16,185		(28.2	)
Number of rigs at end of period		220			201		9.5
Rig utilization		73	%		68	%	7.4

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $96,304 and $86,297 for 2010 and 2009, respectively.
Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2010.
Rig utilization excludes seven FlexRigs completed and ready for delivery at September 30, 2009.

Operating income in the U.S. Land segment decreased to $404.3 million in 2010 from $573.7 million in 2009. Included in U.S. land revenues for 2010 and 2009 is approximately $41.2 million and $169.4 million, respectively, from early termination revenue and revenue from customers that requested delivery delays for new FlexRigs. Excluding early termination related revenue and customer requested delivery delay revenue for new FlexRigs, the average revenue per day for 2010 decreased by $1,509 to $23,161 from $24,670 in 2009, as a result of lower average dayrates in 2010 compared to 2009.

Direct operating expenses increased 17 percent in 2010 from 2009, and the expense as a percentage of revenue increased to 55 percent in 2010 from 46 percent in 2009. However, the average rig expense per day increased by only $279 during 2010, primarily as a result of costs incurred to reactivate idle rigs.

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Rig utilization increased to 73 percent in 2010 from 68 percent in 2009. The total number of rigs at September 30, 2010 was 220 compared to 201 rigs at September 30, 2009. The net increase is due to 14 new FlexRigs having been completed and placed into service, one transferred to the International Land segment with a customer commitment, and six transferred from the International Land segment. Subsequent to September 30, 2010, we classified two conventional rigs as held for sale.

Depreciation includes charges for abandoned equipment of $3.5 million and $4.9 million in 2010 and 2009, respectively. Excluding the abandonment amounts, depreciation in 2010 increased 14 percent from 2009 due to the increase in available rigs.

We expect to complete and deliver another 16 new FlexRigs by the end of the third fiscal quarter of 2011. Like those completed in fiscal 2010, each of these new rigs is committed to work for an exploration and production company under a fixed term contract, performing drilling services on a daywork contract basis. As a result of the new FlexRigs added in 2010 and additional rigs scheduled for completion in 2011, we anticipate depreciation expense to continue to increase in fiscal 2011.

During 2009, the economic recession, including the decrease in oil and natural gas prices and deterioration in the credit markets, had an effect on customer spending. As a result, the industry's active land drilling rig count in the U.S. land market declined by over fifty percent from the fall of 2008 to the summer of 2009. Since June 2009, the industry's U.S. land rig count has been experiencing a steady recovery but the rig count still remains about 20 percent below the peak level reported during the fall of 2008. At

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September 30, 2010, 185 out of 220 existing rigs in the U.S. Land segment were generating revenue. Of the 185 rigs generating revenue, 127 were under fixed term contracts, and 58 were working in the spot market. At November 18, 2010, the number of existing rigs under fixed term contracts in the segment increased to 132 and the number of rigs working in the spot market remained at 58. Only one of the rigs under a fixed term contract was under a customer requested delivery delay. Delayed FlexRigs do not generate revenue days and are not considered for purposes of calculating and reporting utilization rates.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2010 AND 2009

	2010			2009			% Change
OFFSHORE OPERATIONS		(in thousands, except operating statistics)
Operating revenues		$202,734			$204,702		(1.0	)%
Direct operating expenses		131,325			133,442		(1.6	)
General and administrative expense		5,821			4,095		42.1
Depreciation		12,519			11,872		5.4
Segment operating income	$	53,069		$	55,293		(4.0	)
Operating Statistics:
Revenue days		2,642			2,938		(10.1	)%
Average rig revenue per day		$  47,534			$  48,677		(2.3	)
Average rig expense per day		$  24,653			$  27,373		(9.9	)
Average rig margin per day		$  22,881			$  21,304		7.4
Number of rigs at end of period		9			9		—
Rig utilization		80	%		89	%	(10.1	)

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $37,594 and $34,125 for 2010 and 2009, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense.

Segment operating income in our Offshore segment decreased by four percent in 2010 from 2009 primarily due to reduced activity. Segment operating income was not significantly impacted during 2010 as a result of the government imposed deepwater drilling moratorium.

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Currently, we have seven of our nine platform rigs working. The rig located offshore Trinidad was placed on standby during the fourth fiscal quarter of 2010 but is expected to commence operations for a new customer by the first fiscal quarter of 2011.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2010 AND 2009

	2010			2009			% Change
INTERNATIONAL LAND OPERATIONS		(in thousands, except operating statistics)
Operating revenues	$	247,179		$	187,099		32.1	%
Direct operating expenses		166,021			146,565		13.3
General and administrative expense		2,949			2,301		28.2
Depreciation		29,938			19,278		55.3
Segment operating income	$	48,271		$	18,955		154.7
Operating Statistics:
Revenue days		7,254			4,807		50.9	%
Average rig revenue per day	$	32,451		$	35,618		(8.9	)
Average rig expense per day	$	21,142		$	26,528		(20.3	)
Average rig margin per day	$	11,309		$	9,090		24.4
Number of rigs at end of period		28			33		(15.2	)
Rig utilization		71	%		70	%	1.4

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $11,779 and $15,884 for 2010 and 2009, respectively. Also excluded are the effects of currency revaluation expense.
Rig utilization at September 30, 2009 excludes one FlexRig completed and ready for delivery and two FlexRigs delivered waiting on customer location.

The International Land segment had operating income of $48.3 million for 2010 compared to $19.0 million for 2009, primarily due to an increase in revenue days.

Rig utilization for international land operations increased to 71 percent in 2010 from 70 percent in 2009. The total number of rigs at September 30, 2010 was 28 compared to 33 rigs at September 30, 2009. The decrease was due to six rigs transferred to the U.S. Land segment and one rig transferred to the International Land segment. Five of the six rigs had been in the International Land

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segment for prospective bidding purposes and came back to the U.S. under contract. The rig transferred to the International Land segment was in transit to a customer location at September 30, 2010. Two FlexRigs completed in 2009 and one FlexRig completed in 2008 were placed into service during 2010.

Direct operating expenses increased primarily due to an increase in activity. However, the average rig expense per day decreased in 2010 from 2009 as revenue days increased and labor and stacking expenses related to rigs that became idle were reduced.

Subsequent to September 30, 2010, two rigs were transferred to the U.S. Land segment with one of those under contract. Three international rigs have received release notifications and are expected to return to the U.S. Land segment late in the first quarter and early second quarter of fiscal 2011.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2009 AND 2008

	2009			2008			% Change
U.S. LAND OPERATIONS		(in thousands, except operating statistics)
Operating revenues	$	1,441,164		$	1,542,038		(6.5	)%
Direct operating expenses		663,385			756,828		(12.3	)
General and administrative expense		16,812			17,599		(4.5	)
Depreciation		187,259			161,893		15.7
Segment operating income		$   573,708			$   605,718		(5.3	)
Operating Statistics:
Revenue days		48,055			59,804		(19.6	)%
Average rig revenue per day		$      28,194			$      24,522		15.0
Average rig expense per day		$      12,009			$      11,393		5.4
Average rig margin per day		$      16,185			$      13,129		23.3
Number of rigs at end of period		201			185		8.6
Rig utilization		68	%		96	%	(29.2	)

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $86,297 and $75,519 for 2009 and 2008, respectively.
Rig utilization excludes seven FlexRigs completed and ready for delivery at September 30, 2009.

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Operating income in the U.S. Land segment decreased to $573.7 million in 2009 from $605.7 million in 2008. Included in U.S. land revenues for 2009 was approximately $169.4 million from early termination revenue and revenue from customers that requested delivery delays for new FlexRigs. The average revenue per day for 2009 increased $3,672 of which $3,524 was attributable to the early termination related revenue and customer requested delivery delay revenue for new FlexRigs.

During 2009, we received 37 early termination notices from customers corresponding to the new rig build program. All 37 rigs released had been deployed to the field prior to fiscal 2008.

Direct operating expenses decreased 12.3 percent from 2008 to 2009, and the expense as a percentage of revenue declined to 46 percent in 2009 from 49 percent in 2008. The average rig expense per day, however, increased during 2009 due to fixed expenses incurred on idle rigs including property taxes and insurance as well as labor and other expenses associated with stacking rigs.

Rig utilization decreased to 68 percent in 2009 from 96 percent in 2008. The total number of rigs at September 30, 2009 was 201 compared to 185 rigs at September 30, 2008. The net increase was due to 22 new FlexRigs having been completed and placed into service, 7 rigs completed and ready for service, 7 transferred to the International Land segment with customer commitments, 5 transferred to the International Land segment to be used for bidding prospective work, and 1 rig removed and held for sale. Depreciation included charges for abandoned equipment of $4.9 million and $13.2 million in 2009 and 2008, respectively. Excluding the

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abandonment amounts, depreciation in 2009 increased 23 percent from 2008 due to the increase in available rigs.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2009 AND 2008

	2009			2008			% Change
OFFSHORE OPERATIONS		(in thousands, except operating statistics)
Operating revenues		$204,702			$154,452		32.5	%
Direct operating expenses		133,442			104,454		27.8
General and administrative expense		4,095			4,452		(8.0	)
Depreciation		11,872			12,152		(2.3	)
Segment operating income		$  55,293			$  33,394		65.6
Operating Statistics:
Revenue days		2,938			2,442		20.3	%
Average rig revenue per day		$  48,677			$  47,743		2.0
Average rig expense per day	$	27,373		$	29,655		(7.7	)
Average rig margin per day		$  21,304			$  18,088		17.8
Number of rigs at end of period		9			9		—
Rig utilization		89	%		75	%	18.7

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $34,125 and $16,330 for 2009 and 2008, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense.

Segment operating income in our Offshore segment increased 66 percent in 2009 from 2008 due to increased activity and a rig beginning work in Trinidad during 2008.

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COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2009 AND 2008

	2009			2008			% Change
INTERNATIONAL LAND OPERATIONS		(in thousands, except operating statistics)
Operating revenues		$187,099			$161,072			16.2	%
Direct operating expenses		146,565			125,660			16.6
General and administrative expense		2,301			3,344			(31.2	)
Depreciation		19,278			14,191			35.8
Segment operating income		$  18,955			$  17,877			6.0
Operating Statistics:
Revenue days		4,807			4,120			16.7	%
Average rig revenue per day		$  35,618			$  34,964			1.9
Average rig expense per day		$  26,528			$  25,949			2.2
Average rig margin per day		$     9,090			$     9,015			0.8
Number of rigs at end of period		33			19			73.7
Rig utilization		70	%		72	%		(2.8	)

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $15,884 and $17,019 for 2009 and 2008, respectively. Also excluded are the effects of currency revaluation expense.
Rig utilization at September 30, 2009 excludes one FlexRig completed and ready for delivery and two FlexRigs delivered waiting on customer location. Rig utilization at September 30, 2008 excludes four FlexRigs completed and ready for delivery.

Segment operating income for our International Land segment increased six percent in 2009 from 2008. The total number of rigs at September 30, 2009 was 33 compared to 19 rigs at September 30, 2008. During 2009, 12 rigs were transferred to the International Land segment from the U.S. Land segment. Of those twelve, seven were under contract with the remaining five used for bidding prospective work. Those five were subsequently returned to the U.S. Land segment. Five new FlexRigs were placed into service during 2009 with two of them completed in 2008 and two completed in 2009. The fifth FlexRig was completed during 2008 and was under contract at the end of 2009 waiting to be sent to a location to be determined by the operator.

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LIQUIDITY AND CAPITAL RESOURCES

Our capital spending was $329.6 million in 2010, $876.8 million in 2009 and $697.9 million in 2008. Net cash provided from operating activities was $462.3 million in 2010, $895.9 million in 2009 and $588.6 million in 2008. Our 2011 capital spending level will be primarily driven by our new build construction program as it adapts to market demand for incremental FlexRigs during the year. Given the number of customer commitments that we already have for new FlexRigs to be completed in 2011, and the level of rig component orders that are required to ensure our ability to effectively respond to additional new FlexRig demand, our current capital spending estimate for 2011 is approximately $600 million.

Historically, we have financed operations primarily through internally generated cash flows. In periods when internally generated cash flows are not sufficient to meet liquidity needs, we will either borrow from available credit sources or, if market conditions are favorable, sell portfolio securities. Likewise, if we are generating excess cash flows, we may invest in short-term investments. In 2009, we purchased $12.5 million of short-term investments. The $12.5 million short-term investment matured in 2010.

We manage a portfolio of marketable securities that, at the close of fiscal 2010, had a market value of $320.7 million. Our investments in Atwood and Schlumberger, Ltd. made up 93 percent of the portfolio's market value on September 30, 2010. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding our investments in limited

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partnerships carried at cost, the portfolio is recorded at fair value on our balance sheet.

We generated cash proceeds from the sale of portfolio securities of $25.5 million in 2008. We did not sell any portfolio securities in 2010 or 2009.

In 2008, proceeds were primarily from the sale of 170,000 shares of Schlumberger, Ltd. and all other available-for-sale securities we owned. Proceeds were primarily used to fund capital expenditures.

Our proceeds from asset sales totaled $7.9 million in 2010, $8.1 million in 2009 and $22.5 million in 2008. In 2008, two international land rigs were sold generating $13.0 million in proceeds. Income from asset sales in 2008 totaled $13.0 million. The rigs sold in 2008 were idle at the time of the sales and, with our emphasis on FlexRig technology, we took advantage of the opportunity to sell older rigs. In each year we also had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business.

In 2009 and 2008, we received insurance proceeds of approximately $0.2 million and $5.3 million, respectively, for damages sustained to our offshore Rig 201 during Hurricane Katrina. During the fourth quarter of fiscal 2007, our Rig 178 was lost when the well it was drilling had a blowout. During 2009 and 2008, we received gross insurance proceeds of approximately $0.3 million and $8.7 million, respectively, in connection with the loss of Rig 178. We recorded a net gain from involuntary conversion of approximately $0.5 million

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in 2009 and $10.2 million in 2008. The proceeds, shown in the Consolidated Statements of Cash Flows under investing activities, were used to rebuild Rig 201 and replace Rig 178. The costs for both rigs were capitalized with Rig 201 returning to work in the fourth fiscal quarter of 2007 and the replacement rig returning to work in 2008. We have settled both claims and no additional insurance proceeds are expected.

We have $150 million of intermediate-term unsecured debt obligations with staged maturities of $75 million in August, 2012 and $75 million in August, 2014. The annual average interest rate through maturity will be 6.53 percent. The terms of the debt obligations require that we maintain a minimum ratio of debt to total capitalization of less than 55 percent. The note purchase agreement also contains additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality.

We have $200 million senior unsecured fixed-rate notes that mature over a period from July 2012 to July 2016. Interest on the notes is paid semi-annually based on an annual rate of 6.10 percent. We will make five equal annual principal repayments of $40 million starting on July 21, 2012. Financial covenants require that we maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00. The note purchase agreement also contains additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality.

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We have an agreement with a multi-bank syndicate for a five-year, $400 million senior unsecured credit facility expiring December 2011. We have the option to borrow at the prime rate for maturities of less than 30 days but anticipate the majority of all of the borrowings over the remaining life of the facility will accrue interest at a spread over the London Interbank Bank Offered Rate (LIBOR). We pay a commitment fee based on the unused balance of the facility. The spread over LIBOR and the commitment fee are determined according to a scale based on the ratio of our total debt to total capitalization. The LIBOR spread ranges from .30 percent to .45 percent depending on the ratio. Based on the ratio at the close of the 2010 fiscal year, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. The advances bear an interest rate of 0.61 percent. At September 30, 2010, we had two letters of credit totaling $21.9 million under the facility and had borrowed $10 million against the facility with $368.1 million remaining available to borrow. Subsequent to September 30, 2010, we paid the $10 million outstanding balance and had $378.1 million available to borrow.

Financial covenants in the facility require that we maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The facility contains additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2010, we were in compliance with all debt covenants.

In January 2010, a $105 million unsecured line of credit that matured was paid in full using operating cash flow and borrowings under the $400 million facility. At the same time, an interest rate

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swap with the same maturity and a notional amount of $105 million expired.

At September 30, 2010, we had 142 existing rigs with contracts under fixed terms with original term durations ranging from six months to seven years, with some expiring in fiscal 2011. The contracts provide for termination at the election of the customer, with an early termination payment to be paid if a contract is terminated prior to the expiration of the fixed term. While most of our customers are primarily major oil companies and large independent oil companies, a risk exists that a customer, especially a smaller independent oil company, may become unable to meet its obligations and may exercise its early termination election in the future and not be able to pay the early termination fee. Although not expected at this time, our future revenue and operating results would be negatively impacted if this were to happen.

Our operating cash requirements and estimated capital expenditures, including completion of the remaining rig construction, for fiscal 2011 will be funded through current cash, cash provided from operating activities, funds available under the current credit facility, funds available under any new credit facility and, possibly, sales of available-for-sale securities.

The current ratio was 2.9 at September 30, 2010 and 1.6 at September 30, 2009. The long-term debt to total capitalization ratio was 11 percent and 14 percent at September 30, 2010 and 2009, respectively. The decrease is due to equity increasing, primarily from earnings, and a decrease in long-term debt.

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During 2010, we paid dividends of $.21 per share, or a total of $22.3 million, representing the 38th consecutive year of dividend increases.

STOCK PORTFOLIO HELD

September 30, 2010	Number of Shares		Cost Basis		Market Value
		(in thousands, except share amounts)
Atwood Oceanics, Inc.		8,000,000	$	121,498	$	243,600
Schlumberger, Ltd.		967,500		7,685		59,608
Other				12,369		22,507
Total				$141,552		$325,715

MATERIAL COMMITMENTS

We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations as of September 30, 2010, are summarized in the table below in thousands:

	Payments due by year
Contractual Obligations	Total		2011		2012		2013		2014		2015		After 2015
Long-term debt and estimated interest (a)		$435,065		$22,026		$146,304		$54,205		$126,159		$44,406		$41,965
Operating leases (b)		27,754		7,204		4,742		3,633		2,154		2,038		7,983
Purchase obligations (b)		68,837		68,837		—		—		—		—		—
Total Contractual Obligations		$531,656		$98,067		$151,046		$57,838		$128,313		$46,444		$49,948

(a)    The estimated future interest payments on our variable-rate credit facilities were based on the interest rate and principal balance at September 30, 2010. Interest on fixed-rate debt was estimated based on principal maturities. See Note 3 "Debt" to our Consolidated Financial Statements.
(b)    See Note 15 "Commitments and Contingencies" to our Consolidated Financial Statements.

The above table does not include obligations for our pension plan or amounts recorded for uncertain tax positions.

In 2010, we contributed $3.4 million to the pension plan. Based on current information available from plan actuaries, we estimate contributing at least $0.6 million in 2011 to meet the minimum

28

contribution required by law. We expect to make additional contributions to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond 2011 are difficult to estimate due to multiple variables involved.

At September 30, 2010, we had $8.8 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in Note 4 to the Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Consolidated Financial Statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. These estimates and assumptions are evaluated on an on-going basis. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies and estimates used in our financial statements. Other significant accounting policies are summarized in Note 1 to the Consolidated Financial Statements.

Property, Plant and Equipment Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed as incurred. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We account for the

29

depreciation of property, plant and equipment using the straight-line method over the estimated useful lives of the assets considering the estimated salvage value of the property, plant and equipment. Both the estimated useful lives and salvage values require the use of management estimates. Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation. Management believes that these estimates have been materially accurate in the past. For the years presented in this report, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.

Impairment of Long-lived Assets Management assesses the potential impairment of our long-lived assets whenever events or changes in conditions indicate that the carrying value of an asset may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, and/or overall changes in general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair market value of the asset. The fair value of drilling rigs is determined based on quoted market prices, if available; otherwise, it is determined based upon estimated discounted future cash flows. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig's

30

marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics due to lower industry utilization. Use of different assumptions could result in an impairment charge different from that reported.

Fair Value of Financial Instruments Fair value is defined as an exit price, which is the price that would be received upon sale of an asset or paid upon transfer of a liability in an orderly transaction between market participants at the measurement date. The degree of judgment utilized in measuring the fair value of assets and liabilities generally correlates to the level of pricing observability. Financial assets and liabilities with readily available, actively quoted prices or for which fair value can be measured from actively quoted prices in active markets generally have more pricing observability and require less judgment in measuring fair value. Conversely, financial assets and liabilities that are rarely traded or not quoted have less price observability and are generally measured at fair value using valuation models that require more judgment. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency of the asset, liability or market and the nature of the asset or liability. The carrying amounts reported in the statement of financial position for current assets and current liabilities qualifying as financial instruments approximate fair value because of the short-term nature of the instruments. Marketable securities are carried at fair value which is generally determined by quoted market prices. We have categorized financial assets and liabilities measured at fair value into a three-level hierarchy in accordance with Accounting Standards Codification ("ASC") 820. (See Note 8 of the Consolidated Financial Statements for fair value disclosures.)

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Self-Insurance Accruals We self-insure a significant portion of expected losses relating to worker's compensation, general liability, employer's liability, and auto liabilities. Generally, deductibles are $1 million or $2 million per occurrence depending on whether a claim occurs inside or outside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates for incurred outstanding liabilities for worker's compensation, general liability claims and for claims that are incurred but not reported are recorded. Estimates are based on historic experience and statistical methods that we believe are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

Our wholly-owned captive insurance company, White Eagle Assurance Company, provides a portion of our physical damage insurance for company-owned drilling rigs and reinsures international casualty deductibles. With the exception of "named windstorm" risk in the Gulf of Mexico, we insure rig and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self-insure a $1 million per occurrence deductible, as well as 10 percent of the estimated replacement cost of offshore rigs and 30 percent of the estimated replacement cost for land rigs and equipment. We have two insurance policies covering six offshore platform rigs for "named windstorm" risk in the Gulf of Mexico. The first policy covers four rigs and has a $55 million insurance limit over a $20 million deductible. We have been indemnified by a customer for $17 million of this deductible. The second policy covers two rigs and has a $40 million limit and a $3.5 million deductible.

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We maintain certain other insurance coverage with deductibles as high as $5 million. Excess insurance is purchased over these coverage amounts to limit our exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred and, using adjuster's estimates, our historical loss experience or estimation methods that are believed to be reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development, and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense and related liabilities. We self insure a number of other risks including loss of earnings and business interruption.

Pension Costs and Obligations Our pension benefit costs and obligations are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan assets. Our discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was lowered from 5.42 percent to 4.48 percent as of September 30, 2010 to reflect changes in the market conditions for high-quality fixed-income investments. The expected return on plan assets is determined based on historical portfolio results and future expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated

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from future periods. We anticipate pension expense to be approximately $2.7 million in 2011 which is comparable to 2010.

Stock-Based Compensation Historically, we have granted stock-based awards to key employees and non-employee directors as part of their compensation. We estimate the fair value of all stock option awards as of the date of grant by applying the Black-Scholes option-pricing model. The application of this valuation model involves assumptions, some of which are judgmental and highly sensitive. These assumptions include, among others, the expected stock price volatility, the expected life of the stock options and the risk-free interest rate. Expected volatilities were estimated using the historical volatility of our stock based upon the expected term of the option. We consider information in determining the grant date fair value that would have indicated that future volatility would be expected to be significantly different than historical volatility. The expected term of the option was derived from historical data and represents the period of time that options are estimated to be outstanding. The risk-free interest rate for periods within the estimated life of the option was based on the U.S. Treasury Strip rate in effect at the time of the grant. The fair value of each award is amortized on a straight-line basis over the vesting period for awards granted to employees. Stock-based awards granted to non-employee directors are expensed immediately upon grant.

The fair value of restricted stock is determined based on the average of the high and low price of our common stock on the date of grant. We amortize the fair value of restricted stock awards to compensation expense on a straight-line basis over the vesting period. At September 30, 2010, unrecognized compensation cost related to

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unvested restricted stock was $4.7 million. The cost is expected to be recognized over a weighted-average period of 1.7 years.

Revenue Recognition Revenues and expenses for daywork contracts are recognized daily as the work progresses. For certain contracts, payments are received that are contractually designated for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Other lump-sum payments received from customers relating to specific contracts are deferred and amortized to income as services are performed. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

NEW ACCOUNTING STANDARDS

Effective October 1, 2009, we adopted the guidance contained in ASC 260, Earnings per Share, that clarifies that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities. An entity must include participating securities in its calculation of basic and diluted earnings per share pursuant to the two-class method pursuant to ASC 260. All prior-period earnings per share data presented has been adjusted retrospectively to conform to the provisions of ASC 260. The impact of the adoption is shown in Note 7 of the Consolidated Financial Statements.

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In December 2008, the Financial Accounting Standards Board ("FASB") issued revisions to ASC Topic 715, Compensation—Retirement Benefits. The new guidance expands disclosure by requiring more information about how investment allocation decisions are made, more information about major categories of plan assets, including concentration of risk and fair-value measurements, and the fair-value techniques and inputs used to measure plan assets. The disclosure requirements have been adopted in our annual financial statements for the year ended September 30, 2010, on a prospective basis. The adoption had no material impact on the Consolidated Financial Statements.

On October 1, 2009, we implemented the previously deferred provisions of ASC 820, Fair Value Measurements and Disclosures, for nonfinancial assets and liabilities recorded at fair value, as required. Additionally, we adopted Accounting Standards Update ("ASU") No. 2009-05, Measuring Liabilities at Fair Value which provided amendments to ASC 820, Fair Value Measurements and Disclosure, for the fair value measurement of liabilities when a quoted price in an active market is not available. The adoption of these pronouncements had no impact on the Consolidated Financial Statements.

In October 2009, the FASB issued ASU 2009-13, Multiple-Deliverable Revenue Arrangements—a consensus of the FASB Emerging Issues Task Force (Topic 605), which amends the revenue guidance under ASC 605. This update requires entities to allocate revenue in an arrangement using estimated selling prices of the delivered goods and services based on a selling price hierarchy. This guidance eliminates the residual method of revenue allocation and requires revenue to be allocated using the relative selling price method. ASU No. 2009-13 is effective for fiscal years beginning on or after

36

June 15, 2010 and may be applied prospectively for arrangements entered into after the effective date or retrospectively for all periods presented. The adoption is effective for us no later than the beginning of fiscal 2011. We do not expect the provision of ASU 2009-13 to have a material effect on our Consolidated Financial Statements.

On January 21, 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements. The disclosure requirements requiring reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy was adopted on December 15, 2009 with no impact on the Consolidated Financial Statements. Effective for fiscal years beginning after December 15, 2010, a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments, will be required. We currently believe the adoption related to Level 3 financial instruments will have no impact on the Consolidated Financial Statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Foreign Currency Exchange Rate Risk We have operations in several South American countries, Trinidad, Mexico, Africa and the Middle East. With the exception of Argentina, our exposure to currency valuation losses is usually immaterial due to the fact that virtually all invoice billings and receipts in other countries are in U.S. dollars. The exchange rate between the U.S. dollar and the Argentine peso stayed within a narrow range for seven years and then devalued 27 percent during 2009, resulting in the recording of a $2.2 million

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currency loss. In 2010, a devaluation loss of $0.8 million was recorded from a 2.6 percent devaluation of the Argentine peso to the U.S. dollar.

We are not operating in any country that is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period. All of our foreign subsidiaries use the U.S. dollar as the functional currency and local currency monetary assets are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. As such, if a foreign economy is considered highly inflationary, there would be no impact on the Consolidated Financial Statements.

Commodity Price Risk The demand for contract drilling services is a result of exploration and production companies spending money to explore and develop drilling prospects in search of crude oil and natural gas. Their appetite for such spending is driven by their cash flow and financial strength, which is very dependent on, among other things, crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including supply and demand, worldwide economic conditions, and geopolitical factors. Crude oil and natural gas prices have been volatile and very difficult to predict. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining future spending levels. This volatility has led many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices.

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In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets, as experienced in 2008 and 2009, can make it difficult for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in a reduction in customer spending and the demand for drilling services. This reduction in spending could have a material adverse effect on our business, financial condition or operations.

We attempt to secure favorable prices through advanced ordering and purchasing for drilling rig components. While these materials have generally been available at acceptable prices, there is no assurance the prices will not vary significantly in the future. Any fluctuations in market conditions causing increased prices in materials and supplies could impact future operating costs adversely.

Interest Rate Risk Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our commercial banks. Our current risk due to interest fluctuation was minimal at September 30, 2010 due to the amount of our fixed-rate debt being approximately 97 percent of total debt.

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The following tables provide information as of September 30, 2010 and 2009 about our interest rate risk sensitive instruments:

INTEREST RATE RISK AS OF SEPTEMBER 30, 2010 (dollars in thousands)

		2011		2012			2013			2014			2015			After 2015			Total			Fair Value 9/30/10
Fixed-Rate Debt		$	—	$	115,000		$	40,000		$	115,000		$	40,000		$	40,000		$	350,000		$	382,852
	Average Interest Rate		—		6.4	%		6.1	%		6.5	%		6.1	%		6.1	%		6.3	%
Variable Rate Debt		$	—		$  10,000			$       —			$         —			$       —			$       —			$  10,000			$  10,000
	Average Interest Rate (a)																			(a	)

(a)    Advances bear interest rate of .61%

INTEREST RATE RISK AS OF SEPTEMBER 30, 2009 (dollars in thousands)

		2010		2011		2012			2013			2014			After 2014			Total			Fair Value 9/30/09
Fixed-Rate Debt			$         —		$         —		$115,000			$40,000			$115,000			$80,000			$350,000			$380,925
	Average Interest Rate		—		—		6.4	%		6.1	%		6.5	%		6.1	%		6.3	%
Variable Rate Debt			$       —		$       —		$  70,000			$       —			$       —			$       —			$  70,000			$  70,000
	Average Interest Rate (a)																		(a	)

(a)  Advances bear interest rate of .60%

Equity Price Risk On September 30, 2010, we had a portfolio of securities with a total fair value of $325.7 million. The total fair value of the portfolio of securities was $359.5 million at September 30, 2009. Our investments in Atwood and Schlumberger, Ltd. made up 93 percent of the portfolio's fair value at September 30, 2010. Although we sold portions of our positions in Schlumberger, Ltd. in 2008, we make no specific plans to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the fair value of our holdings. Except for our investments in limited partnerships carried at cost, the portfolio is recorded at fair value on the balance sheet with changes in unrealized after-tax value reflected in the equity section of the balance sheet. At November 18, 2010, the total fair value of the portfolio of securities had increased

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to approximately $396.8 million with an estimated after-tax value of $258.4 million. Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements.

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Report of Independent
Registered Public Accounting Firm

The Board of Directors and Shareholders
Helmerich & Payne, Inc.

We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2010 and 2009, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helmerich & Payne, Inc. at September 30, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2010, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, effective October 1, 2007, the Company adopted the requirements for accounting for uncertainty in income taxes.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helmerich & Payne Inc.'s internal control over financial reporting as of September 30, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 24, 2010 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
November 24, 2010

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Consolidated Statements of Income

Years Ended September 30,			2010			2009			2008
			(in thousands, except per share amounts)
OPERATING REVENUES
	Drilling – U.S. Land			$1,412,495			$1,441,164			$1,542,038
	Drilling – Offshore			202,734			204,702			154,452
	Drilling – International Land			247,179			187,099			161,072
	Other			12,754			10,775			11,809
				1,875,162			1,843,740			1,869,371
OPERATING COSTS AND EXPENSES
	Operating costs, excluding depreciation			1,071,959			944,780			987,838
	Depreciation			262,658			227,535			195,343
	Research and development			12,262			9,671			1,833
	Acquired in-process research and development			—			—			11,129
	General and administrative			81,479			58,822			56,429
	Gain from involuntary conversion of long-lived assets			—			(541	)		(10,236	)
	Income from asset sales			(4,992	)		(5,402	)		(13,049	)
				1,423,366			1,234,865			1,229,287
Operating income from continuing operations				451,796			608,875			640,084
Other income (expense)
	Interest and dividend income			1,811			2,755			3,524
	Interest expense			(17,158	)		(13,590	)		(18,721	)
	Gain on sale of investment securities			—			—			21,994
	Other			1,787			245			(1,396	)
				(13,560	)		(10,590	)		5,401
Income from continuing operations before income taxes and equity in income of affiliate				438,236			598,285			645,485
Income tax provision				152,155			227,850			242,593
Equity in income of affiliate net of income taxes				—			10,111			17,366
Income from continuing operations				286,081			380,546			420,258
Income (loss) from discontinued operations before income taxes				(125,944	)		(22,470	)		54,444
Income tax provision				3,825			4,531			12,964
Income (loss) from discontinued operations				(129,769	)		(27,001	)		41,480
NET INCOME				$    156,312			$   353,545			$   461,738
Basic earnings per common share:
	Income from continuing operations		$	2.70		$	3.61		$	4.02
	Income (loss) from discontinued operations		$	(1.23	)	$	(0.26	)	$	0.40
		Net income	$	1.47		$	3.35		$	4.42
Diluted earnings per common share:
	Income from continuing operations		$	2.66		$	3.56		$	3.93
	Income (loss) from discontinued operations		$	(1.21	)	$	(0.25	)	$	0.39
		Net income	$	1.45		$	3.31		$	4.32
Weighted average shares outstanding (in thousands):
	Basic			105,711			105,364			104,284
	Diluted			107,404			106,608			106,583

The accompanying notes are an integral part of these statements.

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Consolidated Balance Sheets

ASSETS

September 30,			2010		2009
				(in thousands)
CURRENT ASSETS:
	Cash and cash equivalents			$      63,020		$      96,142
	Short-term investments			—		12,500
	Accounts receivable, less reserve of $830 in 2010 and $659 in 2009			457,659		233,949
	Inventories			43,402		39,544
	Deferred income taxes			14,282		6,373
	Assets held for sale			—		1,023
	Prepaid expenses and other			64,171		52,495
	Current assets of discontinued operations			10,270		80,906
		Total current assets		652,804		522,932
INVESTMENTS				320,712		356,404
PROPERTY, PLANT AND EQUIPMENT, at cost:
	Contract drilling equipment			4,285,277		3,901,967
	Construction in progress			154,595		232,055
	Real estate properties			61,735		61,114
	Other			182,087		169,099
				4,683,694		4,364,235
	Less – Accumulated depreciation			1,408,674		1,169,962
		Net property, plant and equipment		3,275,020		3,194,273
NONCURRENT ASSETS:
	Other assets			16,834		15,781
	Noncurrent assets of discontinued operations			—		71,634
		Total noncurrent assets		16,834		87,415
TOTAL ASSETS			$	4,265,370	$	4,161,024

The accompanying notes are an integral part of these statements.

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LIABILITIES AND SHAREHOLDERS' EQUITY

September 30,			2010		2009
				(in thousands, except share data and per share amounts)
CURRENT LIABILITIES:
	Accounts payable			$      80,534		$      68,173
	Accrued liabilities			144,112		111,750
	Short-term debt			—		105,000
	Current liabilities of discontinued operations			7,992		16,983
		Total current liabilities		232,638		301,906
NONCURRENT LIABILITIES:
	Long-term debt			360,000		420,000
	Deferred income taxes			771,383		672,358
	Other			91,606		73,546
	Noncurrent liabilities of discontinued operations			2,278		10,205
		Total noncurrent liabilities		1,225,267		1,176,109
SHAREHOLDERS' EQUITY:
	Common stock, $.10 par value, 160,000,000 shares authorized, 107,057,904 shares issued as of September 30, 2010 and 2009 and 105,819,161 and 105,486,218 shares outstanding as of September 30, 2010 and 2009, respectively			10,706		10,706
	Preferred stock, no par value, 1,000,000 shares authorized, no shares issued			—		—
	Additional paid-in capital			191,900		176,039
	Retained earnings			2,547,917		2,414,942
	Accumulated other comprehensive income			84,107		112,451
				2,834,630		2,714,138
	Less treasury stock, 1,238,743 shares in 2010 and 1,571,686 shares in 2009, at cost			27,165		31,129
		Total shareholders' equity		2,807,465		2,683,009
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY				$4,265,370		$4,161,024

The accompanying notes are an integral part of these statements.

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Consolidated Statements of Shareholders' Equity

			Common Stock				Additional Paid-In Capital						Accumulated Other Comprehensive Income (Loss)			Treasury Stock
										Retained Earnings
			Shares		Amount											Shares			Amount			Total
				(in thousands, except per share amounts)
Balance, September 30, 2007				107,058		$10,706		$143,146			$1,645,766			$75,885			3,573			$(59,987	)		$1,815,516
Adjustment to initially apply ASC 740-10-30-5											(5,048	)											(5,048	)
Comprehensive Income:
	Net income										461,738												461,738
	Other comprehensive loss:
		Unrealized losses on available-for-sale securities, net												(30,863	)								(30,863	)
		Amortization of net periodic benefit costs – net of actuarial gain												(6,615	)								(6,615	)
	Total other comprehensive loss																						(37,478	)
Total comprehensive income																							424,260
Capital adjustment of equity investee								1,669															1,669
Dividends declared ($.185 per share)											(19,938	)											(19,938	)
Exercise of stock options								(9,740	)								(1,735	)		24,277			14,537
Tax benefit of stock-based awards, including excess tax benefits of $24.9 million								27,022															27,022
Treasury stock issued for vested restricted stock								(56	)								(3	)		56			—
Stock-based compensation								7,456															7,456
Balance, September 30, 2008				107,058		10,706		169,497			2,082,518			38,407			1,835			(35,654	)		2,265,474
Comprehensive Income:
	Net income										353,545												353,545
	Other comprehensive loss:
		Unrealized gains on available-for-sale securities, net												88,519									88,519
		Amortization of net periodic benefit costs – net of actuarial gain												(14,475	)								(14,475	)
	Total other comprehensive gain																						74,044
Total comprehensive income																							427,589
Capital adjustment of equity investee								174															174
Dividends declared ($.20 per share)											(21,121	)											(21,121	)
Exercise of stock options								(1,978	)								(197	)		3,250			1,272
Tax benefit of stock-based awards, including excess tax benefits of $1.2 million								1,273															1,273
Treasury stock issued for vested restricted stock								(1,275	)								(66	)		1,275			—
Stock-based compensation								8,348															8,348
Balance, September 30, 2009				107,058		10,706		176,039			2,414,942			112,451			1,572			(31,129	)		2,683,009
Comprehensive Income:
	Net income										156,312												156,312
	Other comprehensive loss:
		Unrealized losses on available-for-sale securities, net												(22,885	)								(22,885	)
		Amortization of net periodic benefit costs – net of actuarial gain												(5,459	)								(5,459	)
	Total other comprehensive loss																						(28,344	)
Total comprehensive income																							127,968
Dividends declared ($.22 per share)											(23,337	)											(23,337	)
Exercise of stock options								(2,721	)								(263	)		2,519			(202	)
Tax benefit of stock-based awards, including excess tax benefits of $3.9 million								4,172															4,172
Treasury stock issued for vested restricted stock								(1,445	)								(70	)		1,445			—
Stock-based compensation								15,855															15,855
Balance, September 30, 2010				107,058	$	10,706	$	191,900		$	2,547,917		$	84,107			1,239		$	(27,165	)	$	2,807,465

The accompanying notes are an integral part of these statements.

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Consolidated Statements of Cash Flows

Years Ended September 30,					2010			2009			2008
						(in thousands)
OPERATING ACTIVITIES:
	Net income					$     156,312			$    353,545			$    461,738
	Adjustment for (income) loss from discontinued operations					129,769			27,001			(41,480	)
	Income from continuing operations					286,081			380,546			420,258
	Adjustments to reconcile net income     to net cash provided by operating activities:
		Depreciation				262,658			227,535			195,343
		Provision for bad debt				206			(645	)		704
		Equity in income of affiliate before income taxes				—			(16,308	)		(28,009	)
		Stock-based compensation				15,855			8,348			7,456
		Gain on sale of investment securities				—			—			(21,864	)
		Gain from involuntary conversion of long-lived assets				—			(541	)		(10,236	)
		Income from asset sales				(4,992	)		(5,402	)		(13,049	)
		Acquired in-process research and development				—			—			11,129
		Deferred income tax expense				105,691			158,153			117,998
		Other				79			(244	)		754
		Change in assets and liabilities:
			Accounts receivable			(223,916	)		156,863			(107,949	)
			Inventories			(3,858	)		(10,981	)		(3,534	)
			Prepaid expenses and other			(12,800	)		(9,442	)		(23,640	)
			Accounts payable			16,760			(24,996	)		(15,643	)
			Accrued liabilities			14,031			2,672			29,203
			Deferred income taxes			2,453			8,234			12,317
			Other noncurrent liabilities			8,402			(1,525	)		5,916
	Net cash provided by operating activities from continuing operations					466,650			872,267			577,154
	Net cash provided by (used in) operating activities from discontinued operations					(4,362	)		23,672			11,480
				Net cash provided by operating activities		462,288			895,939			588,634
INVESTING ACTIVITIES:
	Capital expenditures					(329,572	)		(876,839	)		(697,906	)
	Acquisition of business, net of cash acquired					—			(16	)		(12,041	)
	Proceeds from asset sales					7,867			8,069			22,470
	Insurance proceeds from involuntary conversion					—			541			13,926
	Purchase of short-term investments					(16	)		(12,500	)		—
	Proceeds from sale of investments					12,516			—			25,507
	Net cash used in investing activities from continuing operations					(309,205	)		(880,745	)		(648,044	)
	Net cash used in investing activities from discontinued operations					(55	)		(3,284	)		(7,291	)
				Net cash used in investing activities		(309,260	)		(884,029	)		(655,335	)
FINANCING ACTIVITIES:
	Increase (decrease) in notes payable					—			(1,733	)		1,733
	Decrease in long-term debt					—			(25,000	)		—
	Proceeds from line of credit					895,000			3,840,000			3,550,000
	Payments on line of credit					(1,060,000	)		(3,790,000	)		(3,495,000	)
	Increase (decrease) in bank overdraft					(2,038	)		2,038			—
	Dividends paid					(22,254	)		(21,111	)		(19,333	)
	Exercise of stock options					(202	)		1,272			14,537
	Excess tax benefit from stock-based compensation					3,344			1,217			24,868
				Net cash provided by (used in) financing activities		(186,150	)		6,683			76,805
Net increase (decrease) in cash and cash equivalents						(33,122	)		18,593			10,104
Cash and cash equivalents, beginning of period						96,142			77,549			67,445
Cash and cash equivalents, end of period					$	63,020		$	96,142		$	77,549

The accompanying notes are an integral part of these statements.

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Notes to Consolidated Financial Statements

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Helmerich & Payne, Inc. and its wholly-owned subsidiaries. Fiscal years of our foreign operations end on August 31 to facilitate reporting of consolidated results. There were no significant intervening events which materially affected the financial statements.

BASIS OF PRESENTATION

We classified the Venezuelan operation, an operating segment within the International Land segment, as a discontinued operation in the third quarter of fiscal 2010, as more fully described in Note 2. Accordingly, the assets and liabilities of this business, along with its results of operations, have been reclassified for all periods presented. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates only to our continuing operations.

The adoption of the guidance contained in Accounting Standards Codification ("ASC") 260, Earnings per Share, discussed in Note 7 changed the calculation of basic earnings per share requiring restricted stock grants that have previously been included in our diluted weighted-average shares to be included in basic weighted-average shares. Earnings per share for the fiscal years ended September 30, 2009 and 2008 have been recalculated to conform to the current year presentation.

FOREIGN CURRENCIES

The functional currency for all our foreign subsidiaries is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the year. Gains and losses from remeasurement of foreign currency financial statements and foreign currency translations into U.S. dollars are included in direct operating costs. Aggregate foreign currency remeasurement and transaction losses included in direct operating costs totaled $0.5 million, $3.0 million and $1.6 million in fiscal 2010, 2009 and 2008, respectively.

USE OF ESTIMATES

The preparation of our financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

RECENTLY ADOPTED ACCOUNTING STANDARDS

Effective October 1, 2009, we adopted the guidance contained in ASC 260, Earnings per Share. ASC 260 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and therefore need to be included in the earnings allocation in calculating earnings per share under

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the two-class method described in ASC 260. The calculation of earnings per share is more fully described in Note 7.

In December 2008, the Financial Accounting Standards Board ("FASB") issued revisions to ASC Topic 715, Compensation—Retirement Benefits. The new guidance expands disclosure by requiring more information about how investment allocation decisions are made, more information about major categories of assets, including concentration of risk and fair-value measurements, and the fair-value techniques and inputs used to measure plan assets. The disclosure requirements have been adopted for our annual financial statements for the year ended September 30, 2010, on a prospective basis. The adoption had no material impact on the Consolidated Financial Statements.

On October 1, 2009, we implemented the previously deferred provisions of ASC 820, Fair Value Measurements and Disclosures, for nonfinancial assets and liabilities recorded at fair value, as required. Additionally, we adopted Accounting Standards Update ("ASU") No. 2009-05, Measuring Liabilities at Fair Value, which provided amendments to ASC 820 for the fair value measurements of liabilities when a quoted price in an active market is not available. On December 15, 2009, we adopted the disclosure requirements in ASU 2009-06, Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements, requiring that information be provided about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy described in Note 8. The adoption of these pronouncements had no impact on the Consolidated Financial Statements.

CASH AND CASH EQUIVALENTS

Cash equivalents consist of investments in short-term, highly liquid securities having original maturities of three months or less. The carrying values of these assets approximate their fair values. We primarily utilize a cash management system with a series of separate accounts consisting of lockbox accounts for receiving cash, concentration accounts, and several "zero-balance" disbursement accounts for funding payroll and accounts payable. As a result of our cash management system, checks issued, but not presented to the banks for payment, may create negative book cash balances. Checks outstanding in excess of related book cash balances are included in accounts payable where applicable and included as a financing activity in the Consolidated Statements of Cash Flows.

RESTRICTED CASH AND CASH EQUIVALENTS

We had restricted cash and cash equivalents of $14.8 million and $13.9 million at September 30, 2010 and 2009, respectively. Restricted cash is primarily for the purpose of potential insurance claims in our wholly-owned captive insurance company. Of the total at September 30, 2010, $2.0 million is from the initial capitalization of the captive company and management has elected to restrict an additional $12.8 million. The restricted amounts are primarily invested in short-term money market securities.

The restricted cash and cash equivalents are reflected in the balance sheet as follows (in thousands):

September 30,	2010		2009
Other current assets		$12,848		$11,890
Other assets		$  2,000		$  2,000

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INVENTORIES AND SUPPLIES

Inventories and supplies are primarily replacement parts and supplies held for use in our drilling operations. Inventories and supplies are valued at the lower of cost (moving average or actual) or market value.

INVESTMENTS

We maintain investments in equity securities of unaffiliated companies. The cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold.

We regularly review investment securities for impairment based on criteria that include the extent to which the investment's carrying value exceeds its related fair value, the duration of the market decline and the financial strength and specific prospects of the issuer of the security. Unrealized losses that are other than temporary are recognized in earnings.

Investments in companies owned from 20 to 50 percent are accounted for using the equity method by recognizing our proportionate share of the income or loss of the investee. Effective April 1, 2009, Atwood Oceanics, Inc. ("Atwood") was accounted for as an available-for-sale investment, as we determined that we no longer had the ability to exercise significant influence over operating and financial policies at Atwood and discontinued accounting for Atwood using the equity method. The investment in Atwood is now recorded at fair value with changes deferred as a component of other comprehensive income. We have no other equity method investments.

DERIVATIVE FINANCIAL INSTRUMENTS

We are exposed to market risk in the normal course of business operations due to ongoing investing and financing activities. The risk of loss can be assessed from the perspective of adverse changes in fair values, cash flows and future earnings. ASC 815, Derivatives and Hedging, requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. We have not historically entered into derivative financial instruments for trading purposes or for speculation. For further disclosure regarding an interest rate swap, refer to Note 3.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost less accumulated depreciation. Substantially all property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets (contract drilling equipment, 4-15 years; real estate buildings and equipment, 10-45 years; and other, 2-23 years). Depreciation in the Consolidated Statements of Income includes abandonments of $4.2 million, $5.3 million and $13.3 million for fiscal 2010, 2009 and 2008, respectively. The cost of maintenance and repairs is charged to direct operating cost, while betterments and refurbishments are capitalized.

We lease office space and equipment for use in operations. Leases are evaluated at inception or at any subsequent material modification and, depending on the lease terms, are classified as either capital leases or operating leases as appropriate under ASC 840, Leases. We do not have significant capital leases.

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CAPITALIZATION OF INTEREST

We capitalize interest on major projects during construction. Interest is capitalized based on the average interest rate on related debt. Capitalized interest for fiscal 2010, 2009 and 2008 was $6.4 million, $6.6 million, and $4.7 million, respectively.

VALUATION OF LONG-LIVED ASSETS

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Changes that could prompt such an assessment include a significant decline in revenue or cash margin per day, extended periods of low rig utilization, changes in market demand for a specific asset, obsolescence, completion of specific contracts, and/or overall general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value down to the estimated fair value of the asset. The fair value of drilling rigs is determined based on quoted market prices, if available; otherwise, it is determined based upon estimated discounted future cash flows. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig's marketability, any cash investment required to make a rig marketable, suitability of rig size and make up to existing platforms, and competitive dynamics due to lower industry utilization.

ACQUISITIONS

We account for acquired businesses using the purchase method of accounting which requires that the assets acquired and liabilities assumed be recorded at the date of acquisition at their respective fair values. Any excess of the purchase price over the estimated fair values of the net assets acquired is recorded as goodwill. Amounts allocated to acquired in-process research and development are expensed at the date of acquisition. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact results of operations. Accordingly, for significant items, assistance from third party valuation specialists is typically obtained. The valuations are based on information available near the acquisition date and are based on expectations and assumptions that have been deemed reasonable by management.

SELF INSURANCE ACCRUALS

We have accrued a liability for estimated worker's compensation and other casualty claims incurred. The liability for other benefits to former or inactive employees after employment but before retirement is not material.

DRILLING REVENUES

Contract drilling revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized on a straight-line basis over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements received for out-of-pocket expenses are recorded as revenues and direct costs.

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Reimbursements for fiscal 2010, 2009 and 2008 were $145.7 million, $136.3 million and $108.9 million, respectively. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

RENT REVENUES

We enter into leases with tenants in our rental properties consisting primarily of retail and multi-tenant warehouse space. The lease terms of tenants occupying space in the retail centers and warehouse buildings range from one to eleven years. Minimum rents are recognized on a straight-line basis over the term of the related leases. Overage and percentage rents are based on tenants' sales volume. Recoveries from tenants for property taxes and operating expenses are recognized in other operating revenues in the Consolidated Statements of Income. Our rent revenues are as follows:

Years Ended September 30,	2010		2009		2008
		(in thousands)
Minimum rents		$8,613		$8,803		$9,469
Overage and percentage rents		$1,241		$1,414		$1,582

At September 30, 2010, minimum future rental income to be received on noncancelable operating leases was as follows (in thousands):

Fiscal Year		Amount
2011			$  7,390
2012			5,492
2013			3,973
2014			2,879
2015			2,335
Thereafter			3,061
	Total		$25,130

Leasehold improvement allowances are capitalized and amortized over the lease term.

At September 30, 2010 and 2009, the cost and accumulated depreciation for real estate properties were as follows (in thousands):

September 30,	2010			2009
Real estate properties		$61,735			$61,114
Accumulated depreciation		(39,030	)		(37,786	)
		$22,705			$23,328

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INCOME TAXES

Current income tax expense is the amount of income taxes expected to be payable for the current year. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities.

We provide for uncertain tax positions when such tax positions do not meet the recognition thresholds or measurement standards prescribed in ASC 740, Income Taxes, which was adopted effective October 1, 2007, and is more fully discussed in Note 4. Amounts for uncertain tax positions are adjusted in periods when new information becomes available or when positions are effectively settled. We recognize accrued interest related to unrecognized tax benefits in interest expense and penalties in other expense in the Consolidated Statements of Income.

On October 1, 2007, we adopted the requirements regarding the accounting for income tax benefits of dividends on share-based payment awards. As a result of the adoption, we recognized a realized income tax benefit associated with dividends or dividend equivalents paid on nonvested equity-classified employee share-based payment awards that were charged to retained earnings as an increase to additional paid-in capital. The adoption did not have a material impact on our financial position, results of operations or cash flows.

EARNINGS PER SHARE

Basic net income per share is computed utilizing the two-class method and is calculated based on weighted-average number of common shares outstanding during the periods presented. Diluted net income per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options and nonvested restricted stock.

STOCK-BASED COMPENSATION

We record compensation expense associated with stock options in accordance with ASC 718, Compensation—Stock Compensation. Compensation expense is determined using a fair-value-based measurement method for all awards granted. In computing the impact, the fair value of each option is estimated on the date of grant based on the Black-Scholes options-pricing model utilizing certain assumptions for a risk free interest rate, volatility, dividend yield and expected remaining term of the awards. The assumptions used in calculating the fair value of share-based payment awards represent management's best estimates, but these estimates involve inherent uncertainties and the application of management judgment. Stock-based compensation is recognized on a straight-line basis over the requisite service periods of the stock awards, which is generally the vesting period. Compensation expense related to stock options is recorded as a component of general and administrative expenses in the Consolidated Statements of Income.

TREASURY STOCK

Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to additional paid-in capital using the average-cost method.

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NEW ACCOUNTING STANDARDS

In October 2009, the FASB issued ASU 2009-13, Multiple-Deliverable Revenue Arrangements—a consensus of the FASB Emerging Issues Task Force (Topic 605), which amends the revenue guidance under ASC 605. This update requires entities to allocate revenue in an arrangement using estimated selling prices of the delivered goods and services based on a selling price hierarchy. This guidance eliminates the residual method of revenue allocation and requires revenue to be allocated using the relative selling price method. ASU No. 2009-13 is effective for fiscal years beginning on or after June 15, 2010 and may be applied prospectively for arrangements entered into after the effective date or retrospectively for all periods presented. The adoption is effective for us no later than the beginning of fiscal 2011. We do not expect the provision of ASU 2009-13 to have a material effect on our Consolidated Financial Statements.

On January 21, 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements. The disclosure requirements requiring reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy was adopted on December 15, 2009 with no impact on the Consolidated Financial Statements. Effective for fiscal years beginning after December 15, 2010, a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments, will be required. We currently believe the adoption related to Level 3 financial instruments will have no impact on the Consolidated Financial Statements.

NOTE 2 DISCONTINUED OPERATIONS

On June 30, 2010, the Official Gazette of Venezuela published the Decree of Venezuelan President Hugo Chavez, which authorized the "forceful acquisition" of eleven rigs owned by our Venezuelan subsidiary. The Decree also authorized the seizure of "all the personal and real property and other improvements" used by our Venezuelan subsidiary in its drilling operations. The seizing of our assets became effective June 30, 2010, and met the criteria established for recognition as discontinued operations under accounting standards for presentation of financial statements. Therefore, operations from the Venezuelan subsidiary, an operating segment within the International Land segment, have been classified as discontinued operations in our September 30, 2010, Consolidated Financial Statements. All historical statements have been reclassified to conform to this presentation.

Our revenue in Venezuela was from providing drilling services to Petroleos de Venezuela, S.A. ("PDVSA"), the Venezuelan state-owned petroleum company. We determined, as of the beginning of the second quarter of fiscal 2009 and forward, that the revenue recognition criteria in Venezuela was no longer met as collectability of revenue was not reasonably assured, primarily due to the uncertainty of the timing of collections. However, up until the time of the seizing of our assets, we continued to receive payments from PDVSA and were in discussions with PDVSA officials regarding payments and the possibility of contract negotiations to put our rigs back to work.

As a result of the seizing of our assets in the third quarter of fiscal 2010, we derecognized our Venezuela property and equipment, $65.0 million, and warehouse inventory, $5.2 million, resulting in a loss of approximately $70.2 million. Accounts receivable, payables and other deferred charges and credits, netting to

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approximately $9.5 million, were also written off because the related future cash inflows and outflows associated with them were no longer expected to occur. At September 30, 2010, we had approximately $31.3 million (U.S. currency equivalent) cash balances in Venezuela. Our Venezuelan subsidiary has had, since July 22, 2008, an outstanding application with the Venezuelan government requesting approval to remit approximately $14.2 million as a dividend to its U.S. based parent, converting bolivar fuerte (Bsf) cash balances to U.S. dollars. Because of the seizure of our assets by the Venezuelan government and our inability to obtain approval of the dividend, we also impaired approximately $21.1 million cash as of September 30, 2010. The remaining cash was classified as restricted cash, a current asset from discontinued operations, to meet remaining in-country current obligations.

Summarized operating results from discontinued operations are as follows:

Years Ended September 30,	2010			2009			2008
Revenue	$	13,534		$	50,298		$	167,172
Income (loss) before income taxes		(125,944	)		(22,470	)		54,444
Income tax expense		(3,825	)		(4,531	)		(12,964	)
Income (loss) from discontinued operations	$	(129,769	)	$	(27,001	)	$	41,480

Significant categories of assets and liabilities from discontinued operations are as follows:

September 30,	2010		2009
Cash and cash equivalents	$	—	$	45,344
Accounts receivable		—		12,841
Other current assets		10,270		22,721
Total current assets		10,270		80,906
Property, plant and equipment, net		—		71,634
Total assets	$	10,270	$	152,540
Total current liabilities	$	7,992	$	16,983
Total noncurrent liabilities		2,278		10,205
Total liabilities	$	10,270	$	27,188

Liabilities consist of municipal and income taxes payable and social obligations due within the country of Venezuela.

On January 8, 2010, the Venezuelan government devalued its currency. The official exchange rate was devalued from 2.15 Bsf to each U.S. dollar to 4.30 Bsf. As a result of the devaluation, we recorded an exchange loss of approximately $20.4 million during fiscal 2010. The devaluation is included in discontinued operations.

Effective January 1, 2010, Venezuela was designated hyper-inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period. All of our foreign subsidiaries use the U.S.

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dollar as the functional currency and local currency monetary assets are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. As such, the designation of Venezuela as hyper-inflationary had no impact on our Consolidated Financial Statements.

NOTE 3 DEBT

At September 30, 2010 and 2009, we had $360 million and $420 million, respectively, in unsecured long-term debt outstanding at rates and maturities shown in the following table (in thousands):

		September 30,
		2010		2009
Unsecured intermediate debt issued August 15, 2002:
	Series C, due August 15, 2012, 6.46%		$  75,000		$  75,000
	Series D, due August 15, 2014, 6.56%		75,000		75,000
Unsecured senior notes issued July 21, 2009:
	Due July 21, 2012, 6.10%		40,000		40,000
	Due July 21, 2013, 6.10%		40,000		40,000
	Due July 21, 2014, 6.10%		40,000		40,000
	Due July 21, 2015, 6.10%		40,000		40,000
	Due July 21, 2016, 6.10%		40,000		40,000
Unsecured senior credit facility due December 18, 2011, .61%			10,000		70,000
			$360,000		$420,000
Less long-term debt due within one year			—		—
Long-term debt		$	360,000	$	420,000

The intermediate unsecured debt outstanding at September 30, 2010 matures over a period from August 2012 to August 2014 and carries a weighted-average interest rate of 6.53 percent, which is paid semi-annually. The terms require that we maintain a minimum ratio of debt to total capitalization of less than 55 percent. The debt is held by various entities, including $3 million held by a company affiliated with one of our Board members.

We have $200 million senior unsecured fixed-rate notes that mature over a period from July 2012 to July 2016. Interest on the notes is paid semi-annually based on an annual rate of 6.10 percent. We will make five equal annual principal repayments of $40 million starting on July 21, 2012. Financial covenants require us to maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00. The note purchase agreement also contains additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality.

We have an agreement with a multi-bank syndicate for a $400 million senior unsecured credit facility maturing December 2011. While we have the option to borrow at the prime rate for maturities of less than 30 days, we anticipate that the majority of all the borrowings over the life of the facility will accrue interest at a spread

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over the London Interbank Bank Offered Rate (LIBOR). We pay a commitment fee based on the unused balance of the facility. The spread over LIBOR as well as the commitment fee is determined according to a scale based on a ratio of our total debt to total capitalization. The LIBOR spread ranges from .30 percent to .45 percent depending on the ratio. At September 30, 2010, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. At September 30, 2010, we had two letters of credit totaling $21.9 million under the facility and had $10 million borrowed against the facility with $368.1 million available to borrow. The advances bear an interest rate of 0.61 percent at September 30, 2010. Subsequent to September 30, 2010, we paid the $10 million outstanding balance and had $378.1 million available to borrow.

Financial covenants in the facility require we maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The facility contains additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2010, we were in compliance with all debt covenants.

In January 2010, a $105 million unsecured line of credit that matured was paid in full using operating cash flow and borrowings under the $400 million facility. At the same time, an interest rate swap with the same maturity and a notional amount of $105 million expired.

At September 30, 2010, aggregate maturities of long-term debt are as follows (in thousands):

Years ending September 30,
2011	$          —
2012	125,000
2013	40,000
2014	115,000
2015	40,000
Thereafter	40,000
	$360,000

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NOTE 4 INCOME TAXES

The components of the provision for income taxes are as follows:

Years Ended September 30,		2010			2009		2008
			(in thousands)
Current:
	Federal		$  31,312			$  45,780		$  97,871
	Foreign		13,215			13,442		15,232
	State		1,937			8,889		10,813
			46,464			68,111		123,916
Deferred:
	Federal		100,206			148,367		110,077
	Foreign		7,846			2,865		(788	)
	State		(2,361	)		8,507		9,388
			105,691			159,739		118,677
Total provision			$152,155			$227,850		$242,593

The amounts of domestic and foreign income before income taxes and equity in income of affiliate are as follows:

Years Ended September 30,	2010		2009		2008
		(in thousands)
Domestic		$389,383		$571,028		$627,344
Foreign		48,853		27,257		18,141
		$438,236		$598,285		$645,485

Deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets is based on management's judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future.

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The components of our net deferred tax liabilities are as follows:

September 30,			2010		2009
				(in thousands)
Deferred tax liabilities:
	Property, plant and equipment		$	703,404	$	591,074
	Available-for-sale securities			107,917		123,763
	Equity investments			—		—
	Other			136		166
		Total deferred tax liabilities		811,457		715,003
Deferred tax assets:
	Pension reserves			15,549		12,901
	Self-insurance reserves			4,249		3,740
	Net operating loss and foreign tax credit carryforwards			45,343		48,107
	Financial accruals			31,102		25,829
	Other			3,456		3,939
		Total deferred tax assets		99,699		94,516
	Valuation allowance			45,343		48,107
		Net deferred tax assets		54,356		46,409
Net deferred tax liabilities			$	757,101	$	668,594

The change in our net deferred tax assets and liabilities is impacted by foreign currency remeasurement.

As of September 30, 2010, we had state and foreign net operating loss carryforwards for income tax purposes of $3.3 million and $16.0 million, respectively, and foreign tax credit carryforwards of approximately $39.6 million which will expire in years 2011 through 2018. The valuation allowance is primarily attributable to state and foreign net operating loss carryforwards and foreign tax credit carryforwards which more likely than not will not be utilized.

Effective income tax rates as compared to the U.S Federal income tax rate are as follows:

Years Ended September 30,	2010			2009			2008
U.S. Federal income tax rate		35	%		35	%		35	%
Effect of foreign taxes		1			1			1
State income taxes		(1	)		2			2
Effective income tax rate		35	%		38	%		38	%

Effective October 1, 2007, we adopted the guidance in ASC 740, Income Taxes, issued by the FASB in July 2006 that clarified the accounting for uncertainty in income taxes recognized in an entity's financial statements and prescribed a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a tax return. Under ASC 740, the impact of an uncertain income tax position must be recognized in the financial statements at the largest amount that is more likely than not

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to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has less than a 50 percent likelihood of being sustained. The cumulative effect of adoption resulted in a decrease of approximately $5.0 million in retained earnings.

We recognize accrued interest related to unrecognized tax benefits in interest expense, and penalties in other expense in the Consolidated Statements of Income. As of September 30, 2010 and 2009, we had accrued interest and penalties of $3.2 million and $1.7 million, respectively.

A reconciliation of the change in our gross unrecognized tax benefits for the fiscal year ended September 30, 2010 and 2009 is as follows (in thousands):

September 30,	2010		2009
Unrecognized tax benefits at October 1,	$	5,244	$	5,692
Gross decreases – tax positions in prior periods		—		(731	)
Gross increases – tax positions in prior periods		177		—
Gross increases – current period effect of tax positions		128		283
Unrecognized tax benefits at September 30	$	5,549	$	5,244

As of September 30, 2010 and September 30, 2009, our liability for unrecognized tax benefits was $5.6 million and $5.2 million, respectively, which would affect the effective tax rate if recognized. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in our Consolidated Balance Sheets.

It is reasonably possible that the amount of the unrecognized tax benefits with respect to certain unrecognized tax positions will increase or decrease during the next 12 months. However, we do not expect the change to have a material effect on results of operations or financial position.

We file a consolidated U.S. federal income tax return, as well as income tax returns in various states and foreign jurisdictions. The tax years that remain open to examination by U.S. federal and state jurisdictions include fiscal years 2006 through 2009. Audits in foreign jurisdictions are generally complete through fiscal year 2001.

NOTE 5 SHAREHOLDERS' EQUITY

On September 30, 2010, we had 105,819,161 outstanding common stock purchase rights ("Rights") pursuant to the terms of the Rights Agreement dated January 8, 1996, as amended by Amendment No. 1 dated December 8, 2005. As adjusted for the two-for-one stock splits in fiscals 1998 and 2006, and as long as the Rights are not separately transferable, one-half Right attaches to each share of our common stock. Under the terms of the Rights Agreement each Right entitles the holder thereof to purchase one full unit consisting of one one-thousandth of a share of Series A Junior Participating Preferred Stock ("Preferred Stock"), without par value, at a price of $250 per unit. The exercise price and the number of units of Preferred Stock issuable on exercise of the Rights are subject to adjustment in certain cases to prevent dilution. The Rights will be

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attached to the common stock certificates and are not exercisable or transferable apart from the common stock, until ten business days after a person acquires 15 percent or more of the outstanding common stock or ten business days following the commencement of a tender offer or exchange offer that would result in a person owning 15 percent or more of the outstanding common stock. In the event we are acquired in a merger or certain other business combination transactions (including one in which we are the surviving corporation), or more than 50 percent of our assets or earning power is sold or transferred, each holder of a Right shall have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the exercise price of the Right. The Rights are redeemable under certain circumstances at $0.01 per Right and will expire, unless earlier redeemed, on January 31, 2016.

NOTE 6 STOCK-BASED COMPENSATION

We have one plan providing for common-stock based awards to employees and to non-employee Directors. The plan permits the granting of various types of awards including stock options and restricted stock awards. Restricted stock may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than market price of the underlying stock on the date of grant. Stock options expire ten years after the grant date. We have the right to satisfy option exercises from treasury shares and from authorized but unissued shares.

On December 1, 2009, we amended the forms of agreement under the plan for awards of nonqualified stock options, incentive stock options and restricted stock. We also amended existing stock option and restricted stock award agreements. The amendments provide for continued vesting (and accelerated vesting upon death) of restricted stock and stock options effective upon a participant becoming retirement eligible. A participant meets the definition of retirement eligible if the participant attains age 55 and has 15 or more years of continuous service as a full-time employee. The amendments apply retroactively. As a result of the continued vesting provisions, we incurred additional compensation cost of approximately $4.9 million in fiscal 2010.

A summary of compensation cost for stock-based payment arrangements recognized in general and administrative expense in fiscal 2010, 2009 and 2008 is as follows (in thousands):

September 30,		2010		2009		2008
Compensation expense
	Stock options	$	11,475	$	6,899	$	6,210
	Restricted stock		4,380		1,449		1,246
		$	15,855	$	8,348	$	7,456

Benefits of tax deductions in excess of recognized compensation cost of $3.3 million, $1.2 million and $24.9 million are reported as a financing cash flow in the Consolidated Statements of Cash Flows for fiscal 2010, 2009 and 2008, respectively.

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STOCK OPTIONS

Vesting requirements for stock options are determined by the Human Resources Committee of our Board of Directors. Options currently outstanding began vesting one year after the grant date with 25 percent of the options vesting for four consecutive years.

We use the Black-Scholes formula to estimate the fair value of stock options granted to employees. The fair value of the options is amortized to compensation expense on a straight-line basis over the requisite service periods of the stock awards, which are generally the vesting periods. The weighted-average fair value calculations for options granted within the fiscal period are based on the following weighted-average assumptions set forth in the table below. Options that were granted in prior periods are based on assumptions prevailing at the date of grant.

	2010			2009			2008
Risk-free interest rate		2.3	%		1.7	%		3.3	%
Expected stock volatility		49.9	%		43.3	%		31.1	%
Dividend yield		0.5	%		0.9	%		0.5	%
Expected term (in years)		5.8			5.8			4.8

Risk-Free Interest Rate.    The risk-free interest rate is based on U.S. Treasury securities for the expected term of the option.

Expected Volatility Rate.    Expected volatilities are based on the daily closing price of our stock based upon historical experience over a period which approximates the expected term of the option.

Expected Dividend Yield.    The dividend yield is based on our current dividend yield.

Expected Term.    The expected term of the options granted represents the period of time that they are expected to be outstanding. We estimate the expected term of options granted based on historical experience with grants and exercises.

Based on these calculations, the weighted-average fair value per option granted to acquire a share of common stock was $17.64, $8.16 and $10.81 per share for fiscal 2010, 2009 and 2008, respectively.

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The following summary reflects the stock option activity for our common stock and related information for fiscal 2010, 2009 and 2008 (shares in thousands):

	2010				2009				2008
	Options			Weighted-Average Exercise Price	Options			Weighted-Average Exercise Price	Options			Weighted-Average Exercise Price
Outstanding at October 1,		5,401		$20.55		4,819		$20.02		6,032		$15.80
Granted		570		38.02		865		21.07		742		35.11
Exercised		(397	)	13.63		(267	)	12.18		(1,845	)	11.87
Forfeited/Expired		(2	)	38.02		(16	)	26.91		(110	)	27.31
Outstanding on September 30,		5,572		$22.82		5,401		$20.55		4,819		$20.02
Exercisable on September 30,		3,888		$19.68		3,599		$17.42		3,206		$15.07
Shares available to grant		7,614				1,656				2,511

The following table summarizes information about stock options at September 30, 2010 (shares in thousands):

	Outstanding Stock Options				Exercisable Stock Options
Range of Exercise Prices	Options		Weighted-Average Remaining Life	Weighted-Average Exercise Price	Options		Weighted-Average Exercise Price
$11.3318 to $16.010		2,348	2.6	$13.50		2,348	$13.50
$21.0500 to $27.440		1,475	7.3	$23.56		691	$25.03
$30.2300 to $38.015		1,749	7.3	$34.72		849	$32.43
$11.3318 to $38.015		5,572	5.3	$22.82		3,888	$19.68

At September 30, 2010, the weighted-average remaining life of exercisable stock options was 4.1 years and the aggregate intrinsic value was $80.8 million with a weighted-average exercise price of $19.68 per share.

The number of options vested or expected to vest at September 30, 2010 was 5,498,304 with an aggregate intrinsic value of $97.5 million and a weighted-average exercise price of $22.73 per share.

As of September 30, 2010, the unrecognized compensation cost related to the stock options was $10.0 million. That cost is expected to be recognized over a weighted-average period of 2.6 years.

The total intrinsic value of options exercised during fiscal 2010, 2009 and 2008 was $11.3 million, $4.9 million, and $21.9 million, respectively.

The grant date fair value of shares vested during fiscal 2010, 2009 and 2008 was $7.0 million, $6.3 million and $5.8 million, respectively.

RESTRICTED STOCK

Restricted stock awards consist of our common stock and are time vested over three to six years. We recognize compensation expense on a straight-line basis over the vesting period. The fair value of restricted stock awards is determined based on the average of the high and low price of our shares on the grant date.

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As of September 30, 2010, there was $4.7 million of total unrecognized compensation cost related to unvested restricted stock awards. That cost is expected to be recognized over a weighted-average period of 1.7 years.

A summary of the status of our restricted stock awards as of September 30, 2010, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2010, 2009 and 2008 is as follows (share amounts in thousands):

	2010				2009				2008
	Shares			Weighted-Average Grant Date Fair Value per Share	Shares			Weighted-Average Grant Date Fair Value per Share	Shares			Weighted-Average Grant Date Fair Value per Share
Outstanding at October 1,		177		$30.06		243		$29.92		240		$29.27
Granted		182		38.02		—		—		22		35.11
Vested		(70	)	29.36		(66	)	29.52		(3	)	16.01
Forfeited/Expired		—		—		—		—		(16	)	30.24
Outstanding on September 30,		289		$35.23		177		$30.06		243		$29.92

NOTE 7 EARNINGS PER SHARE

ASC 260, Earnings per Share, requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share. We have granted and expect to continue to grant restricted stock grants to employees and non-employee directors that contain non-forfeitable rights to dividends. Such grants are considered participating securities under ASC 260. As such, we are required to include these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method. Restricted stock grants have previously been included in our dilutive earnings per share calculation using the treasury stock method. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Earnings per share have been recalculated for prior periods to conform to the current year presentation. As a result, the number of shares used to compute earnings per share changed. For the year ended September 30, 2009, basic and diluted earnings per share decreased $0.01 due to the adoption. For the year ended September 30, 2008, basic and diluted earnings per share decreased $0.01 and $0.02, respectively, due to the adoption.

Basic net income per share is computed utilizing the two-class method and is calculated based on weighted-average number of common shares outstanding during the periods presented.

Diluted net income per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options and nonvested restricted stock.

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The following table sets forth the computation of basic and diluted earnings per share:

September 30,			2010			2009			2008
			(in thousands)
Numerator:
	Income from continuing operations		$	286,081		$	380,546		$	420,258
	Income (loss) from discontinued operations			(129,769	)		(27,001	)		41,480
	Net income			156,312			353,545			461,738
Adjustment for basic earnings per share
	Earnings allocated to unvested shareholders			(404	)		(617	)		(1,121	)
Numerator for basic earnings per share:
	From continuing operations			285,677			379,929			419,137
	From discontinued operations			(129,769	)		(27,001	)		41,480
				155,908			352,928			460,617
Adjustment for diluted earnings per share:
	Effect of reallocating undistributed earnings of unvested shareholders			6			6			23
Numerator for diluted earnings per share:
	From continuing operations			285,683			379,935			419,160
	From discontinued operations			(129,769	)		(27,001	)		41,480
			$	155,914		$	352,934		$	460,640
Denominator:
	Denominator for basic earnings per share – weighted-average shares			105,711			105,364			104,284
	Effect of dilutive shares from stock options and restricted stock			1,693			1,244			2,299
	Denominator for diluted earnings per share – adjusted weighted-average shares			107,404			106,608			106,583
Basic earnings per common shares:
	Income from continuing operations		$	2.70		$	3.61		$	4.02
	Income (loss) from discontinued operations			(1.23	)		(0.26	)		0.40
		Net income	$	1.47		$	3.35		$	4.42
Diluted earnings per common shares:
	Income from continuing operations		$	2.66		$	3.56		$	3.93
	Income (loss) from discontinued operations			(1.21	)		(0.25	)		0.39
		Net income	$	1.45		$	3.31		$	4.32

The following shares attributable to outstanding equity awards were excluded from the calculation of diluted earnings per share because their inclusion would have been anti-dilutive:

	2010		2009		2008
	(in thousands, except per share amounts)
Shares excluded from calculation of diluted earnings per share		554		1,206		—
Weighted-average price per share	$	38.02	$	33.12	$	—

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NOTE 8 FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENT

The estimated fair value of our available-for-sale securities is primarily based on market quotes. The following is a summary of available-for-sale securities, which excludes investments in limited partnerships carried at cost and assets held in a Non-qualified Supplemental Savings Plan:

		Cost	Gross Unrealized Gains	Gross Unrealized Losses	Estimated Fair Value
		(in thousands)
Equity Securities:
	September 30, 2010	$129,183	$174,025	$—	$303,208
	September 30, 2009	129,183	210,640	$—	339,823

On an on-going basis, we evaluate the marketable equity securities to determine if a decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge is recorded and a new cost basis established. We review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value.

During the year ended September 30, 2008, marketable equity available-for-sale securities with a fair value at the date of sale of $25.5 million were sold. For the same year, the gross realized gain on such sales of available-for-sale securities totaled $22.0 million. The cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold. We had no sales of marketable equity available-for-sale securities in fiscal years 2010 and 2009.

The investments in the limited partnerships carried at cost were approximately $12.4 million at September 30, 2010 and 2009. The estimated fair value of the limited partnerships was $22.5 million and $19.7 million at September 30, 2010 and 2009, respectively.

The assets held in a Non-qualified Supplemental Savings Plan are carried at fair market value which totaled $5.1 million and $4.2 million at September 30, 2010 and 2009, respectively.

The majority of cash equivalents are invested in taxable and non-taxable money-market mutual funds. The carrying amount of cash and cash equivalents approximates fair value due to the short maturity of those investments.

At September 30, 2009, our short-term investments consisted of a bank certificate of deposit with an original maturity greater than three months. The certificate matured in the second quarter of fiscal 2010. Interest earned is included in interest and dividend income on the Consolidated Statements of Income. The carrying amount of the certificate of deposit approximated fair value.

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The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2010 and 2009.

ASC 820 defines fair value as "the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date". ASC 820 establishes a fair value hierarchy to prioritize the inputs used in valuation techniques into three levels as follows:

•

Level 1 – Observable inputs that reflect quoted prices in active markets for identical assets or liabilities in active markets.

•

Level 2 – Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

•

Level 3 – Valuations based on inputs that are unobservable and not corroborated by market data.

At September 30, 2010, our financial assets utilizing Level 1 inputs include cash equivalents, equity securities with active markets and money market funds we have elected to classify as restricted assets that are included in other current assets and other assets. Also included is cash denominated in a foreign currency we have elected to classify as restricted that is included in current assets of discontinued operations and limited to remaining liabilities of discontinued operations. For these items, quoted current market prices are readily available.

At September 30, 2010, Level 2 inputs include bank certificates of deposit, which are included in current assets.

Currently, we do not have any financial instruments utilizing Level 3 inputs.

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The following table summarizes our assets and liabilities measured at fair value on a recurring basis presented in our Consolidated Balance Sheets as of September 30, 2010:

		Total Measured at Fair Value	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
		(in thousands)
Assets:
	Cash and cash equivalents	$  63,020	$  63,020	$—	$—
	Investments	303,208	303,208	—	—
	Other current assets	23,118	22,868	250	—
	Other assets	2,000	2,000	—	—
Total assets measured at fair value		$391,346	$391,096	$250	$—

The following information presents the supplemental fair value information about long-term fixed-rate debt at September 30, 2010 and September 30, 2009.

September 30,	2010		2009
		(in thousands)
Carrying value of long-term fixed-rate debt	$	350.0	$	350.0
Fair value of long-term fixed-rate debt	$	382.9	$	380.9

The fair value for fixed-rate debt was estimated using discounted cash flows and interest rates currently being offered on credits with similar maturities and credit profiles. The outstanding line of credit and short-term debt bear interest at market rates and the cost of borrowings, if any, would approximate fair value. The debt was valued using a Level 2 input.

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NOTE 9 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of other comprehensive income (loss) for the years ended September 30, 2010, 2009 and 2008 were as follows (in thousands):

Years Ended September 30,	2010			2009			2008
Unrealized appreciation (depreciation) on securities, net of tax of $(13,730), $54,254 and $(10,558)	$	(22,885	)	$	88,519		$	(17,227	)
Reclassification of realized gains in net income, net of tax of $0, $0 and $(8,358)		—			—			(13,636	)
Amortization of net periodic benefit costs—net of actuarial gain, net of tax of $(3,276), $(8,872) and $(4,054).		(5,459	)		(14,475	)		(6,615	)
	$	(28,344	)	$	74,044		$	(37,478	)

The components of accumulated other comprehensive income (loss) at September 30, 2010 and 2009, net of applicable tax effects, were as follows (in thousands):

September 30,	2010			2009
Unrealized appreciation on securities	$	107,712		$	130,597
Unrecognized actuarial loss and prior service cost		(23,605	)		(18,146	)
	$	84,107		$	112,451

NOTE 10 ACQUISITION OF TERRAVICI DRILLING SOLUTIONS

On May 21, 2008, we acquired a private limited partnership, TerraVici Drilling Solutions ('TerraVici') in a transaction accounted for under the purchase method of accounting. Under the purchase method of accounting, the assets acquired and liabilities assumed of TerraVici are recorded as of the acquisition date, at their respective fair values, and included in our Consolidated Financial Statements from the date of acquisition. TerraVici is included with all other non-reportable business segments.

TerraVici is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. We acquired TerraVici to complement technology currently used with the FlexRig. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer.

In-process research and development ("IPR&D") represents rotary steerable system tools under development by TerraVici at the date of acquisition that had not yet achieved technological feasibility, and would have no future alternative use. Accordingly, the purchase price allocated to IPR&D was expensed immediately subsequent to the acquisition. This charge is being amortized over 15 years for tax purposes. The $11.1 million estimated fair value of IPR&D was derived using the multi-period excess-earnings method.

Pursuant to the satisfaction of a performance milestone, we paid $4.0 million subsequent to September 30, 2010. This additional payment will be accounted for as goodwill.

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NOTE 11 EMPLOYEE BENEFIT PLANS

We maintain a domestic noncontributory defined benefit pension plan covering certain U.S. employees who meet certain age and service requirements. In July 2003, we revised the Helmerich & Payne, Inc. Employee Retirement Plan ("Pension Plan") to close the Pension Plan to new participants effective October 1, 2003, and reduce benefit accruals for current participants through September 30, 2006, at which time benefit accruals were discontinued and the Pension Plan was frozen.

The following table provides a reconciliation of the changes in the pension benefit obligations and fair value of Pension Plan assets over the two-year period ended September 30, 2010 and a statement of the funded status as of September 30, 2010 and 2009 (in thousands):

		2010			2009
Accumulated Benefit Obligation		$	102,097		$	89,996
Changes in Projected Benefit Obligations
Projected benefit obligation at beginning of year		$	89,996		$	69,475
	Interest cost		4,825			4,988
	Actuarial gain (loss)		11,482			18,977
	Benefits paid		(4,206	)		(3,444	)
Projected benefit obligation at end of year		$	102,097		$	89,996
Change in plan assets
Fair value of plan assets at beginning of year		$	57,181		$	59,605
	Actual return on plan assets		5,005			270
	Employer contribution		3,408			750
	Benefits paid		(4,206	)		(3,444	)
Fair value of plan assets at end of year		$	61,388		$	57,181
Funded status of the plan at end of year		$	(40,709	)	$	(32,815	)

September 30,		2010			2009
Amounts Recognized in the Consolidated Balance Sheets (in thousands):
	Accrued liabilities	$	(181	)	$	(40	)
	Noncurrent liabilities-other		(40,528	)		(32,775	)
	Net amount recognized	$	(40,709	)	$	(32,815	)
The amounts recognized in Accumulated Other Comprehensive Income at September 30, 2010 and 2009, and not yet reflected in net periodic benefit cost, are as follows (in thousands):
Net actuarial gain (loss)		$	(38,001	)	$	(29,267	)
Prior service cost			(2	)		(1	)
Total		$	(38,003	)	$	(29,268	)

The amount recognized in Accumulated Other Comprehensive Income and not yet reflected in periodic benefit cost expected to be amortized in next year's periodic benefit cost is a net actuarial loss of $3.0 million.

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The weighted average assumptions used for the pension calculations were as follows:

Years Ended September 30,	2010		2009		2008
Discount rate for net periodic benefit costs		5.42%		7.25%		6.25%
Discount rate for year-end obligations		4.48%		5.42%		7.25%
Expected return on plan assets		8.00%		8.00%		8.00%

We contributed $3.4 million to the Pension Plan in fiscal 2010 to fund distributions in lieu of liquidating pension assets. We estimate contributing at least $0.6 million in fiscal 2011 to meet the minimum contribution required by law and expect to make additional contributions to continue funding distributions. Additional contributions will be made if needed to fund unexpected distributions.

Components of the net periodic pension expense (benefit) were as follows (in thousands):

Years Ended September 30,	2010			2009			2008
Interest cost	$	4,825		$	4,988		$	4,919
Expected return on plan assets		(4,552	)		(4,643	)		(5,990	)
Amortization of prior service cost		—			(1	)		—
Recognized net actuarial loss		2,295			3			9
Net pension expense (benefit)	$	2,568		$	347		$	(1,062	)

The following table reflects the expected benefits to be paid from the Pension Plan in each of the next five fiscal years, and in the aggregate for the five years thereafter (in thousands).

Years Ended September 30,
2011		2012		2013		2014		2015		2016-2020	Total
$	4,907	$	6,035	$	5,707	$	5,613	$	6,901	$36,170	$	65,333

Included in the Pension Plan is an unfunded supplemental executive retirement plan.

INVESTMENT STRATEGY AND ASSET ALLOCATION

Our investment policy and strategies are established with a long-term view in mind. The investment strategy is intended to help pay the cost of the Plan while providing adequate security to meet the benefits promised under the Plan. We maintain a diversified asset mix to minimize the risk of a material loss to the portfolio value that might occur from devaluation of any one investment. In determining the appropriate asset mix, our financial strength and ability to fund potential shortfalls are considered. Plan assets are invested in portfolios of diversified public-market equity securities and fixed income securities. The plan holds no securities of the Company.

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the Plans' investment portfolio after analyzing historical experience and future expectations of the return and volatility of various asset classes.

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The target allocation for 2011 and the asset allocation for the Pension Plan at the end of fiscal 2010 and 2009, by asset category, follows:

		Target Allocation			Percentage of Plan Assets At September 30,
Asset Category		2011			2010			2009
U.S. equities			56	%		53	%		57	%
International equities			14			15			15
Fixed income			25			31			27
Real estate and other			5			1			1
	Total		100	%		100	%		100	%

PLAN ASSETS

The fair value of Plan assets at September 30, 2010, summarized by level within the fair value hierarchy described in Note 8, are as follows (in thousands):

			Total		Level 1		Level 2		Level 3
Short-term investments			$	63	$	63	$	—	$	—
Mutual funds:
	Domestic stock funds			17,858		17,858		—		—
	Bond funds			18,872		18,872		—		—
	International stock funds			8,956		8,956		—		—
		Total Mutual funds		45,686		45,686		—		—
Domestic common stock				13,710		13,710		—		—
Common collective trust				785		—		785		—
Foreign equity stock				869		869		—		—
Oil and gas properties				275		—		—		275
Total			$	61,388	$	60,328	$	785	$	275

The Plan's financial assets utilizing Level 1 inputs include publicly traded mutual funds, common stock and foreign equity stocks. These assets are valued based on quoted prices in active markets for identical securities. The Plan's financial assets utilizing Level 2 inputs include a common collective trust (Wells Fargo Short-term Investment Fund). The statements of net assets available for benefits present the fair value of the Wells Fargo Short-term Investment Fund. The Plan's interest in the trust is valued at Net Asset Value per information provided by the Plan's trustee. The Plan's financial instruments utilizing Level 3 inputs consist of oil and gas properties. The fair value of oil and gas properties is determined by Wells Fargo Bank, N.A., based upon actual revenue received for the previous twelve-month period and experience with similar assets.

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The following table sets forth a summary of changes in the fair value of the plan's Level 3 assets for the year ended September 30, 2010 (in thousands):

	Oil and gas properties
Balance, beginning of year	$	435
Unrealized losses relating to property still held at the reporting date		(160	)
Balance, end of year	$	275

DEFINED CONTRIBUTION PLAN

Substantially all employees on the United States payroll may elect to participate in the 401(k)/Thrift Plan by contributing a portion of their earnings. We contribute an amount equal to 100 percent of the first five percent of the participant's compensation subject to certain limitations. The annual expense incurred for this defined contribution plan was $14.2 million, $14.3 million, and $15.0 million in fiscal 2010, 2009 and 2008, respectively.

FOREIGN PLAN

We maintain an unfunded pension plan in one of our international subsidiaries. Pension expense was approximately $0.1 million, $0.4 million and $0.4 million in fiscal 2010, 2009 and 2008, respectively. The pension liability at September 30, 2010 and 2009 was $5.4 million and $5.0 million, respectively.

NOTE 12 SUPPLEMENTAL BALANCE SHEET INFORMATION

The following reflects the activity in our reserve for bad debt for 2010, 2009 and 2008:

September 30,		2010			2009			2008
			(in thousands)
Reserve for bad debt:
	Balance at October 1,	$	659		$	1,331		$	1,707
	Provision for (recovery of) bad debt		206			(645	)		704
	Write-off of bad debt		(35	)		(27	)		(1,080	)
	Balance at September 30,	$	830		$	659		$	1,331

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Accounts receivable, prepaid expenses, accrued liabilities, and long-term liabilities at September 30 consist of the following:

September 30,		2010		2009
			(in thousands)
Accounts receivable, net of reserve:
	Trade receivables	$	409,920	$	233,949
	Income tax		47,739		—
		$	457,659	$	233,949
Prepaid expenses and other:
	Prepaid value added tax	$	15,481	$	16,450
	Restricted cash		12,848		11,890
	Prepaid insurance		9,196		7,887
	Deferred mobilization		14,430		9,046
	Other		12,216		7,222
		$	64,171	$	52,495
Accrued liabilities:
	Taxes payable, other than income tax	$	44,934	$	37,654
	Accrued income taxes		—		14,201
	Self-insurance liabilities		4,135		2,626
	Payroll and employee benefits		33,392		13,449
	Accrued operating costs		23,436		2,150
	Deferred mobilization		13,522		6,063
	Deferred income		6,438		26,026
	Other		18,255		9,581
		$	144,112	$	111,750
Noncurrent liabilities—Other:
	Pension and other non-qualified retirement plans	$	51,690	$	42,422
	Deferred income		14,983		7,536
	Uncertain tax positions including interest and penalties		6,755		6,298
	Self-insurance liabilities		5,328		6,103
	Deferred mobilization		7,816		5,164
	Other		5,034		6,023
		$	91,606	$	73,546

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NOTE 13 SUPPLEMENTAL CASH FLOW INFORMATION

Years Ended September 30,	2010		2009		2008
		(in thousands)
Cash payments:
Interest paid, net of amounts capitalized	$	16,721	$	12,196	$	18,627
Income taxes paid	$	104,028	$	31,009	$	115,600

Capital expenditures on the Consolidated Statements of Cash Flows for the years ended September 30, 2010, 2009 and 2008 do not include additions which have been incurred but not paid for as of the end of the year. The following table reconciles total capital expenditures incurred to total capital expenditures in the Consolidated Statements of Cash Flows:

September 30,		2010			2009			2008
			(in thousands)
Capital expenditures incurred		$	345,264		$	819,798		$	737,809
	Additions incurred prior year but paid for in current year		9,816			66,857			26,954
Additions incurred but not paid for as of the end of the year			(25,508	)		(9,816	)		(66,857	)
Capital expenditures per Consolidated Statements of Cash Flows		$	329,572		$	876,839		$	697,906

NOTE 14 RISK FACTORS

CONCENTRATION OF CREDIT

Financial instruments which potentially subject us to concentrations of credit risk consist primarily of temporary cash investments, short-term investments and trade receivables. We place temporary cash investments in the U.S. with established financial institutions and invest in a diversified portfolio of highly rated, short-term money market instruments. Our trade receivables, primarily with established companies in the oil and gas industry, may impact credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. International sales also present various risks including governmental activities that may limit or disrupt markets and restrict the movement of funds. Most of our international sales, however, are to large international or government-owned national oil companies. We perform ongoing credit evaluations of customers and do not typically require collateral in support for trade receivables. We provide an allowance for doubtful accounts, when necessary, to cover estimated credit losses. Such an allowance is based on management's knowledge of customer accounts. Except as disclosed in Note 2, Discontinued Operations, no significant credit losses have been experienced in recent history.

VOLATILITY OF MARKET

Our operations can be materially affected by oil and gas prices. Oil and natural gas prices are volatile and have declined from the peak levels in June 2008. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining a customer's future spending levels. This volatility, along with the difficulty in predicting future prices can lead many exploration and production companies to base their capital spending on

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much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices.

In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets may cause difficulty for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in a reduction in customer spending and the demand for drilling services. This reduction in spending could have a material adverse effect on our operations.

SELF-INSURANCE

We self-insure a significant portion of expected losses relating to worker's compensation, general liability, and automobile liability. Insurance coverage has been purchased for individual claims that exceed $1 million or $2 million, depending on whether a claim occurs inside or outside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. We record estimates for incurred outstanding liabilities for worker's compensation, general liability claims and for claims that are incurred but not reported. Estimates are based on adjusters' estimates, historic experience and statistical methods that we believe are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development, and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

We have a wholly-owned captive insurance company, White Eagle Assurance Company, which provides a portion of our physical damage insurance for company-owned drilling rigs and reinsures international casualty deductibles. With the exception of "named wind storm" risk in the Gulf of Mexico, we insure rigs and related equipment at values that approximate the current replacement cost on the inception date of the policy.

INTERNATIONAL DRILLING OPERATIONS

International drilling operations may significantly contribute to our revenues and net operating income. There can be no assurance that we will be able to successfully conduct such operations, and a failure to do so may have an adverse effect on our financial position, results of operations, and cash flows. Also, the success of our international operations will be subject to numerous contingencies, some of which are beyond management's control. These contingencies include general and regional economic conditions, fluctuations in currency exchange rates, changes in international regulatory requirements and international employment issues, risk of expropriation of real and personal property, and the burden of complying with foreign laws. Additionally, in the event that extended labor strikes occur or a country experiences significant political, economic or social instability, we could experience shortages in labor and/or material and supplies necessary to operate some of our drilling rigs, thereby causing an adverse effect on our business, financial condition and results of operations.

We are not operating in any country that is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period. All of our foreign subsidiaries use the U.S. dollar as the functional currency and local currency monetary assets are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. As such, if a foreign economy is considered highly inflationary, there would be no impact on the Consolidated Financial Statements.

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NOTE 15 COMMITMENTS AND CONTINGENCIES

COMMITMENTS

Over the last six years, the Company entered into separate drilling contracts with many different customers to build and operate over 160 new FlexRigs. As of November 18, 2010, 12 new FlexRigs with customer commitments remained under construction. During construction, rig construction cost is included in construction in progress and then transferred to contract drilling equipment when the rig is placed in the field for service. Equipment, parts and supplies are ordered in advance to promote efficient construction progress. At September 30, 2010, we had purchase orders outstanding of approximately $68.8 million for the purchase of drilling equipment.

LEASES

We lease approximately 135,000 square feet of office space near downtown Tulsa, Oklahoma as well as other office space and equipment for use in operations. For operating leases that contain built-in pre-determined rent escalations, rent expense is recognized on a straight-line basis over the life of the lease. Leasehold improvements are capitalized and amortized over the lease term. Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of one year at September 30, 2010 are as follows:

Fiscal Year		Amount (in thousands)
2011		$  7,204
2012		4,742
2013		3,633
2014		2,154
2015		2,038
Thereafter		7,983
	Total	$27,754

Total rent expense was $5.4 million, $5.2 million and $4.2 million for fiscal 2010, 2009 and 2008, respectively.

CONTINGENCIES

A lawsuit was filed against us by a former customer for whom we performed drilling services with five rigs under term drilling contracts. The suit alleged, among other things, that we failed to perform drilling operations in accordance with good oilfield practice, breached express performance warranties, and made certain fraudulent representations regarding drilling performance. As a consequence, Plaintiff prayed for actual and punitive damages. The case was settled in the fourth quarter of fiscal 2010 for an immaterial amount.

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Various legal actions, the majority of which arise in the ordinary course of business, are pending. We maintain insurance against certain business risks subject to certain deductibles. None of these legal actions are expected to have a material adverse effect on our financial condition, cash flows or results of operations.

We are contingently liable to sureties in respect of bonds issued by the sureties in connection with certain commitments entered into by us in the normal course of business. We have agreed to indemnify the sureties for any payments made by them in respect of such bonds.

During the ordinary course of our business, contingencies arise resulting from an existing condition, situation, or set of circumstances involving an uncertainty as to the realization of a possible gain contingency. We account for gain contingencies in accordance with the provisions of ASC 450, Contingencies, and, therefore, we do not record gain contingencies and recognize income until realized. As discussed in Note 2, Discontinued Operations, property and equipment of our Venezuelan subsidiary was seized by the Venezuelan government on June 30, 2010. We are currently evaluating various remedies, including any recourse we may have against PDVSA or related parties, any remuneration or reimbursement that we might collect from PDVSA or related parties, and any other sources of recovery for our losses. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No gain contingencies are recognized in our Consolidated Financial Statements.

NOTE 16 SEGMENT INFORMATION

We operate principally in the contract drilling industry. Our contract drilling business includes the following reportable operating segments: U.S. Land, Offshore, and International Land. The contract drilling operations consist mainly of contracting Company-owned drilling equipment primarily to large oil and gas exploration companies. Our primary international areas of operation include Colombia, Ecuador, Argentina, Mexico, Tunisia, Bahrain and other South American countries. The International Land operations have similar services, have similar types of customers, operate in a consistent manner and have similar economic and regulatory characteristics. Therefore, we have aggregated our international operations into one reportable segment. Our Venezuelan operation, which was historically an operating segment within the International Land Segment, was discontinued in the third quarter of fiscal 2010. Consequently, its operating results are excluded from the segment data tables below for all periods presented. Each reportable segment is a strategic business unit which is managed separately. Other includes non-reportable operating segments. Revenues included in Other consist primarily of rental income. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

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We evaluate segment performance based on income or loss from operations (segment operating income) before income taxes which includes:

•

revenues from external and internal customers

•

direct operating costs

•

depreciation and

•

allocated general and administrative costs but excludes corporate costs for other depreciation, income from asset sales and other corporate income and expense.

General and administrative costs are allocated to the segments based primarily on specific identification and, to the extent that such identification is not practical, on other methods which we believe to be a reasonable reflection of the utilization of services provided.

Segment operating income for all segments is a non-GAAP financial measure of our performance, as it excludes certain general and administrative expenses, corporate depreciation, income from asset sales and other corporate income and expense. We consider segment operating income to be an important supplemental measure of operating performance for presenting trends in our core businesses. We use this measure to facilitate period-to-period comparisons in operating performance of our reportable segments in the aggregate by eliminating items that affect comparability between periods. We believe that segment operating income is useful to investors because it provides a means to evaluate the operating performance of the segments on an ongoing basis using criteria that are used by our internal decision makers. Additionally, it highlights operating trends and aids analytical comparisons. However, segment operating income has limitations and should not be used as an alternative to operating income or loss, a performance measure determined in accordance with GAAP, as it excludes certain costs that may affect our operating performance in future periods.

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Summarized financial information of our reportable segments for continuing operations for each of the years ended September 30, 2010, 2009 and 2008 is shown in the following table:

(in thousands)			External Sales		Inter- Segment			Total Sales			Segment Operating Income (Loss)			Depreciation		Total Assets		Additions to Long-Lived Assets
2010
Contract Drilling
	U.S. Land		$	1,412,495	$	—		$	1,412,495		$	404,278		$	211,652	$	3,257,382	$	305,206
	Offshore			202,734		—			202,734			53,069			12,519		132,342		9,982
	International     Land			247,179		—			247,179			48,271			29,938		411,339		23,865
				1,862,408		—			1,862,408			505,618			254,109		3,801,063		339,053
Other				12,754		814			13,568			(6,765	)		8,549		454,037		6,211
				1,875,162		814			1,875,976			498,853			262,658		4,255,100		345,264
Eliminations				—		(814	)		(814	)		—			—		—		—
		Total	$	1,875,162	$	—		$	1,875,162		$	498,853		$	262,658	$	4,255,100	$	345,264
2009
Contract Drilling
	U.S. Land		$	1,441,164	$	—		$	1,441,164		$	573,708		$	187,259	$	2,955,574	$	703,073
	Offshore			204,702		—			204,702			55,293			11,872		129,465		17,584
	International     Land			187,099		—			187,099			18,955			19,278		391,099		94,627
				1,832,965		—			1,832,965			647,956			218,409		3,476,138		815,284
Other				10,775		836			11,611			(7,032	)		9,126		532,346		4,514
				1,843,740		836			1,844,576			640,924			227,535		4,008,484		819,798
Eliminations				—		(836	)		(836	)		—			—		—		—
		Total	$	1,843,740	$	—		$	1,843,740		$	640,924		$	227,535	$	4,008,484	$	819,798
2008
Contract Drilling
	U.S. Land		$	1,542,038	$	—		$	1,542,038		$	605,718		$	161,893	$	2,655,595	$	682,310
	Offshore			154,452		—			154,452			33,394			12,152		152,497		14,614
	International     Land			161,072		—			161,072			17,877			14,191		202,255		33,967
				1,857,562		—			1,857,562			656,989			188,236		3,010,347		730,891
Other				11,809		878			12,687			(7,996	)		7,107		366,773		6,918
				1,869,371		878			1,870,249			648,993			195,343		3,377,120		737,809
Eliminations				—		(878	)		(878	)		—			—		—		—
		Total	$	1,869,371	$	—		$	1,869,371		$	648,993		$	195,343	$	3,377,120	$	737,809

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The following table reconciles segment operating income to income from continuing operations before income taxes and equity in income of affiliate as reported on the Consolidated Statements of Income (in thousands):

Years Ended September 30,			2010			2009			2008
Segment operating income				$498,853			$640,924			$648,993
Income from asset sales				4,992			5,402			13,049
Gain from involuntary conversion of long-lived assets				—			541			10,236
	Corporate general and administrative costs and corporate depreciation			(52,049	)		(37,992	)		(32,194	)
		Operating income		451,796			608,875			640,084
Other income (expense)
	Interest and dividend income			1,811			2,755			3,524
	Interest expense			(17,158	)		(13,590	)		(18,721	)
	Gain on sale of investment securities			—			—			21,994
	Other			1,787			245			(1,396	)
		Total unallocated amounts		(13,560	)		(10,590	)		5,401
Income from continuing operations before income taxes and equity in in income of affiliate				$438,236			$598,285			$645,485

The following table presents revenues from external customers and long-lived assets by country based on the location of service provided (in thousands):

Years Ended September 30,			2010		2009		2008
Revenues
	United States			$1,572,139		$1,613,940		$1,687,075
	Argentina			55,855		42,087		44,367
	Ecuador			52,115		52,250		55,100
	Colombia			57,533		77,322		42,439
	Other Foreign			137,520		58,141		40,390
		Total		$1,875,162		$1,843,740		$1,869,371
Long-Lived Assets
	United States		$	2,973,712	$	2,879,222	$	2,461,726
	Argentina			91,322		99,896		38,125
	Ecuador			27,772		26,022		25,560
	Colombia			59,798		62,942		41,889
	Other Foreign			122,416		126,191		38,084
		Total		$3,275,020		$3,194,273		$2,605,384

Long-lived assets are comprised of property, plant and equipment.

Revenues from one company doing business with the contract drilling business accounted for approximately 12.5 percent, 10.1 percent, and 3.7 percent of the total operating revenues during the years ended September 30, 2010, 2009 and 2008, respectively. Revenues from another company doing business with the contract drilling business accounted for approximately 10.6 percent, 12.4 percent, and 11.3 percent of total operating revenues during the years ended September 30, 2010, 2009 and 2008, respectively. Collectively,

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the receivables from these customers were approximately $85.1 million and $53.0 million at September 30, 2010 and 2009, respectively.

NOTE 17 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

(in thousands, except per share amounts)

2010		1st Quarter		2nd Quarter		3rd Quarter			4th Quarter
Operating revenues			$396,242		$436,579		$483,384			$558,957
Operating income			105,384		101,706		111,474			133,232
Income from continuing operations			63,802		74,105		64,883			83,291
Net income (loss)			63,235		46,747		(36,715	)		83,045
Basic earnings per common share:
	Income from continuing operations		0.61		0.70		0.61			0.78
	Net income (loss)		0.60		0.44		(0.35	)		0.78
Diluted earnings per common share:
	Income from continuing operations		0.60		0.68		0.61			0.77
	Net income (loss)		0.59		0.43		(0.34	)		0.77

2009		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
Operating revenues			$580,805		$520,300		$384,359		$358,276
Operating income			207,524		204,741		106,155		90,455
Income from continuing operations			133,551		123,998		68,021		54,976
Net income			145,275		103,738		53,044		51,488
Basic earnings per common share:
	Income from continuing operations		1.27		1.17		0.64		0.52
	Net income		1.38		0.98		0.50		0.49
Diluted earnings per common share:
	Income from continuing operations		1.25		1.17		0.64		0.51
	Net income		1.36		0.98		0.50		0.48

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding.

In the first quarter of fiscal 2010, net income includes an after-tax gain from the sale of assets of $0.7 million, $0.01 per share on a diluted basis.

In the second quarter of fiscal 2010, net income includes an after-tax gain from the sale of assets of $0.6 million, $0.01 per share on a diluted basis.

In the third quarter of fiscal 2010, net income includes an after-tax gain from the sale of assets of $1.5 million, $0.01 per share on a diluted basis.

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In the fourth quarter of fiscal 2010, net income includes an after-tax gain from the sale of assets of $0.5 million with no effect on diluted earnings per share.

In the first quarter of fiscal 2009, net income includes an after-tax gain from the sale of assets of $0.6 million, $0.01 per share on a diluted basis.

In the second quarter of fiscal 2009, net income includes an after-tax gain from the sale of assets of $1.3 million, $0.01 per share on a diluted basis.

In the third quarter of fiscal 2009, net income includes an after-tax gain from the sale of assets of $1.1 million, $0.01 per share on a diluted basis.

In the fourth quarter of fiscal 2009, net income includes an after-tax gain from the sale of assets of $0.4 million with no effect on diluted earnings per share.

NOTE 18 SUBSEQUENT EVENTS

We have evaluated events and transactions occurring after the balance sheet date through the date these consolidated financial statements were issued, and have determined we have no recognized subsequent events.

Subsequent to September 30, 2010, we classified two conventional rigs from our U.S. Land segment as held for sale.

83

Directors
     Officers

W. H. Helmerich, III Chairman of the Board Tulsa, Oklahoma Hans Helmerich President and Chief Executive Officer Tulsa, Oklahoma William L. Armstrong**(***) President Colorado Christian University Lakewood, Colorado Randy A. Foutch*(***) Chairman and Chief Executive Officer Laredo Petroleum, Inc. Tulsa, Oklahoma Paula Marshall**(***) Chief Executive Officer The Bama Companies, Inc. Tulsa, Oklahoma Hon. Francis Rooney*(***) Chief Executive Officer, Rooney Holdings, Inc. Former U.S. Ambassador to the Holy See, 2005-2008 Tulsa, Oklahoma Edward B. Rust, Jr.*(***) Chairman, President and Chief Executive Officer State Farm Mutual Automobile Insurance Company Bloomington, Illinois John D. Zeglis**(***) Chairman and Chief Executive Officer, Retired AT&T Wireless Services, Inc. Basking Ridge, New Jersey	W. H. Helmerich, III Chairman of the Board Hans Helmerich President and Chief Executive Officer John W. Lindsay Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. Steven R. Mackey Executive Vice President, Secretary, General Counsel & Chief Administrative Officer Juan Pablo Tardio Vice President and Chief Financial Officer Gordon K. Helm Vice President and Controller	Stockholders' Meeting The annual meeting of stockholders will be held on March 2, 2011. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 25, 2011. Stock Exchange Listing Helmerich & Payne, Inc. Common Stock is traded on the New York Stock Exchange with the ticker symbol "HP." The newspaper abbreviation most commonly used for financial reporting is "HelmP." Options on the Company's stock are also traded on the New York Stock Exchange. Stock Transfer Agent and Registrar As of November 18, 2010, there were 609 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent's records. Our transfer agent is responsible for our shareholder records, issuance of stock certificates, and distribution of our dividends and the IRS Form 1099. Your requests, as shareholders, concerning these matters are most efficiently answered by corresponding directly with the transfer agent at the following address:     Computershare Trust Company, N.A.     Investor Services     P.O. Box 43078     Providence, RI 02940-3078     Telephone: (800) 884-4225                        (781) 575-4706 Available Information Annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, earnings releases, and financial statements are made available free of charge on the investor relations section of the Company's website as soon as reasonably practicable after the Company electronically files such materials with, or furnishes it to, the SEC. Also located on the investor relations section of the Company's website are certain corporate governance documents, including the following: the charters of the committees of the Board of Directors; the Company's Corporate Governance Guidelines and Code of Business Conduct and Ethics; the Code of Ethics for Principal Executive Officer and Senior Financial Officers; the Related Person Transaction Policy; the Foreign Corrupt Practices Act Compliance Policy; certain Audit Committee Practices and a description of the means by which employees and other interested persons may communicate certain concerns to the Company's Board of Directors, including the communication of such concerns confidentially and anonymously via the Company's ethics hotline at 1-800-205-4913. Annual reports, quarterly reports, current reports, amendments to those reports, earnings releases, financial statements and the various corporate governance documents are also available free of charge upon written request.
* Member, Audit Committee ** Member, Human Resources Committee *** Member, Nominating and Corporate Governance Committee		Annual CEO Certification The annual CEO Certification required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual was provided to the New York Stock Exchange on or about April 5, 2010. Direct Inquiries To: Investor Relations Helmerich & Payne, Inc. 1437 South Boulder Avenue Tulsa, Oklahoma 74119 Telephone: (918) 742-5531 Internet Address: http://www.hpinc.com

84

 Helmerich & Payne, Inc. 

FORM 10-K, 2010       

HELMERICH & PAYNE, INC.

ANNUAL REPORT FOR 2010

HELMERICH & PAYNE, INC.
1437 SOUTH BOULDER AVENUE
TULSA, OKLAHOMA 74119

ANNUAL REPORT FOR 2010

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Exhibit 13

EX-21

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Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

Helmerich & Payne, Inc.

Subsidiaries of Helmerich & Payne, Inc.

White Eagle Assurance Company (Incorporated in Vermont)
Helmerich & Payne International Drilling Co. (Incorporated in Delaware)

Subsidiaries of Helmerich & Payne International Drilling Co.

Helmerich & Payne (Africa) Drilling Co. (Incorporated in Cayman Islands, British West Indies)
Helmerich & Payne (Colombia) Drilling Co. (Incorporated in Oklahoma)
Helmerich & Payne (Gabon) Drilling Co. (Incorporated in Cayman Islands, British West Indies)
Helmerich & Payne (Argentina) Drilling Co. (Incorporated in Oklahoma)
Helmerich & Payne (Boulder) Drilling Co. (Incorporated in Oklahoma)

Subsidiary of Helmerich & Payne (Boulder) Drilling Co.

Helmerich and Payne Mexico Drilling, S. De R.L. de C.V. (Incorporated in Mexico)
Helmerich & Payne (Boulder) Drilling Co. Limitada (Limited Liability Company — Incorporated in Chile)

Helmerich & Payne del Ecuador, Inc. (Incorporated in Oklahoma)
Helmerich & Payne de Venezuela, C.A. (Incorporated in Venezuela)
Helmerich & Payne Rasco, Inc. (Incorporated in Oklahoma)
H&P Finco (Incorporated in Cayman Islands, British West Indies)
H&P Invest Ltd. (Incorporated in Cayman Islands, British West Indies)
TerraVici Drilling Solutions, Inc. (Incorporated in Delaware)

The Space Center, Inc. (Incorporated in Oklahoma)
Helmerich & Payne Properties, Inc. (Incorporated in Oklahoma)
Utica Resources Co. (Incorporated in Oklahoma)
Utica Square Shopping Center, Inc. (Incorporated in Oklahoma)

Subsidiaries of Utica Square Shopping Center, Inc.

Fishercorp, Inc. (Incorporated in Oklahoma)

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Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

EX-23.1

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

        We consent to the incorporation by reference in this Annual Report (Form 10-K) of Helmerich & Payne, Inc. of our reports dated November 24, 2010, with respect to the consolidated financial statements of Helmerich & Payne, Inc., and the effectiveness of internal control over financial reporting of Helmerich & Payne, Inc., included in the 2010 Annual Report to Shareholders of Helmerich & Payne, Inc.

We consent to the incorporation by reference in the following Registration Statements:

(1)

Registration Statement (Form S-8 No. 333-34939) pertaining to the Helmerich & Payne, Inc. 1996 Stock Incentive Plan,



(2)

Registration Statement (Form S-8 No. 333-63124) pertaining to the Helmerich & Payne, Inc. 2000 Stock Incentive Plan, and



(3)

Registration Statement (Form S-8 No. 333-137144) pertaining to the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan;

of our report dated November 24, 2010, with respect to the consolidated financial statements of Helmerich & Payne, Inc. and the effectiveness of internal control over financial reporting of Helmerich & Payne, Inc. included in this Annual Report (Form 10-K) of Helmerich & Payne, Inc. for the year ended September 30, 2010.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
November 24, 2010

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

EX-31.1

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Exhibit 31.1

CERTIFICATION

        I, Hans Helmerich, certify that:

1.

I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 24, 2010
	/s/ HANS HELMERICH Hans Helmerich President and Chief Executive Officer

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Exhibit 31.1

CERTIFICATION

EX-31.2

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Exhibit 31.2

CERTIFICATION

        I, Juan Pablo Tardio, certify that:

1.

I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 24, 2010
	/s/ JUAN PABLO TARDIO Juan Pablo Tardio Vice President and Chief Financial Officer

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Exhibit 31.2

CERTIFICATION

EX-32

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Exhibit 32

Certification of CEO and CFO Pursuant to
18 U.S.C. Section 1350,
As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002

        In connection with the Annual Report of Helmerich & Payne, Inc. (the "Company") on Form 10-K for the period ended September 30, 2010 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Hans Helmerich, as President and Chief Executive Officer of the Company, and Juan Pablo Tardio, as Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that:

        (1)   The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

        (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ HANS HELMERICH
Hans Helmerich
President and
Chief Executive Officer
Date: November 24, 2010 /s/ JUAN PABLO TARDIO
Juan Pablo Tardio
Vice President and
Chief Financial Officer
Date: November 24, 2010

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Exhibit 32

Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002