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, 2009
	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 (§ 232.405 of this chapter) 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, 2009 the aggregate market value of the voting stock held by non-affiliates was $2,319,845,079

         Number of shares of common stock outstanding at November 19, 2009: 105,553,595

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, 2009	Parts I and II
	(2)    Proxy Statement for Annual Meeting of Stockholders to be held March 3, 2010	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 6, 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, 2009
TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		1
Item 1A.	Risk Factors		6
Item 1B.	Unresolved Staff Comments		11
Item 2.	Properties		11
Item 3.	Legal Proceedings		17
Item 4.	Submission of Matters to a Vote of Security Holders		17
	Executive Officers of the Company		18
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		19
Item 6.	Selected Financial Data		19
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		19
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		20
Item 8.	Financial Statements and Supplementary Data		20
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		20
Item 9A.	Controls and Procedures		20
Item 9B.	Other Information		23
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		24
Item 11.	Executive Compensation		24
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		24
Item 13.	Certain Relationships and Related Transactions, and Director Independence		24
Item 14.	Principal Accountant Fees and Services		24
PART IV
Item 15.	Exhibits and Financial Statement Schedules		25
SIGNATURES			29

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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, 2009

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, and North Dakota. Offshore drilling operations are conducted in the Gulf of Mexico, and offshore of California, Trinidad and Equatorial Guinea. Our international land segment operated in six international locations during fiscal 2009: Venezuela, Ecuador, Colombia, Argentina, Mexico and Tunisia.

        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 a centralized finance division, which handles all accounting, information technology, budgeting, insurance, cash management and related activities.

        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 technology currently used with the FlexRig. 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.

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 the Venezuelan state petroleum company and major international oil companies.

        In fiscal 2009, we received approximately 59 percent of our consolidated operating revenues from our ten largest contract drilling customers. Devon Energy Production Co. LP, Occidental Oil and Gas Corporation and BP plc (respectively, "Devon", "Oxy" and "BP"), including their affiliates, are our three largest contract drilling customers. We perform drilling services for Devon in U.S. land operations, and for Oxy and BP on a world-wide basis. Revenues from drilling services performed for Devon, Oxy and BP in fiscal 2009 accounted for approximately 12 percent, 10 percent and 9 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 six 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 six rigs were designated as FlexRig1 rigs. Subsequently, we built and completed 12 new FlexRig2 rigs. In 2001, we announced that we would build an additional 25 new FlexRigs. These new rigs, known as "FlexRig3 rigs", were the next generation of FlexRigs 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. All 25 of these FlexRig3s were completed by June of 2003. Subsequently, we constructed seven more FlexRig3s which were completed by March of 2004.

        From March 2005 through November 2008, we announced commitments with exploration and production companies to build a cumulative total of 140 new FlexRigs under fixed term contracts to perform drilling services on a daywork basis. Of the 140 FlexRigs, 57 are FlexRig3s and 83 are FlexRig4s (described below). We completed 133 of the 140 rigs through fiscal 2009 and have seven remaining new FlexRigs to complete by the end of the third quarter of fiscal 2010. The total estimated construction cost of all 140 rigs, including tubular and other ancillary equipment, is currently $2.2 billion.

        While the new FlexRig4s are similar to our existing 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 new environmental and safety design. This new 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 2009, all drilling services were performed on a "daywork" contract basis, 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

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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 for at least the last ten years. We believe that under current market conditions, "footage" and "turnkey" contract rates do not adequately compensate contractors 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, 2009, we had 107 rigs under fixed-term contracts. While the original duration for these current fixed-term contracts are for twelve-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, 2009 and 2008 was $2,528 million and $3,374 million, respectively. The decrease in our backlog from 2008 to 2009 is primarily due to expiration and early termination of long-term contracts. Approximately 63.0 percent of the total September 30, 2009 backlog is not reasonably expected to be filled in fiscal 2010. 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, 2009 and 2008, and the percentage of the September 30, 2009 backlog not reasonably expected to be filled in fiscal 2010:

	Total Backlog Revenue
					Percentage Not Reasonably Expected to be Filled in Fiscal 2010
Reportable Segment	9/30/2009		9/30/2008
	(in millions)
U.S. Land	$	2,016	$	2,876	61.1%
Offshore		169		199	74.6%
International		343		299	68.5%
	$	2,528	$	3,374

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U.S. LAND DRILLING

        At the end of September 2009, 2008 and 2007, we had 201, 185 and 157, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2009 increased by a net of 16 rigs from the end of fiscal 2008. The increase is due to 22 new FlexRigs having been completed and placed into service, 7 rigs completed and ready for service, 12 transferred to international operations and 1 rig removed as held for sale. Our U.S. land operations contributed approximately 76 percent ($1,441.2 million) of our consolidated operating revenues during fiscal 2009, compared with approximately 76 percent ($1,542.0 million) of consolidated operating revenues during fiscal 2008 and approximately 72 percent ($1,174.9 million) of consolidated operating revenues during fiscal 2007. Rig utilization in fiscal 2009 was approximately 68 percent, down from approximately 96 percent in fiscal 2008 and 97 percent in 2007. Our fleet of FlexRigs maintained an average utilization of approximately 76 percent during fiscal 2009 while our conventional and highly mobile rigs had an average utilization rate of approximately 36 percent. A rig is considered to be utilized when it is operated or being mobilized or demobilized under contract. At the close of fiscal 2009, 111 land rigs were working out of 201 available rigs.

OFFSHORE DRILLING

        Our offshore operations contributed approximately 11 percent ($204.7 million) in fiscal 2009 of our consolidated operating revenue compared to 8 percent in both fiscal years 2008 and 2007 ($154.5 million in fiscal 2008 and $123.1 million in fiscal 2007). Rig utilization in fiscal 2009 was approximately 89 percent, up from approximately 75 percent in fiscal 2008 and 65 percent in fiscal 2007. At the end of fiscal 2009, we had seven of our nine offshore platform rigs under contract and continued to work under management contracts for three customer-owned rigs. The management contract for one rig located offshore Equatorial Guinea terminated in early fiscal 2008 but we have continued under 30-day extensions. Currently, we are negotiating a new contract in Equatorial Guinea and expect returning to a full dayrate in fiscal 2010. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 36 percent of offshore revenues during fiscal 2009.

INTERNATIONAL LAND DRILLING

General

        Our international land operations contributed approximately 13 percent ($237.4 million) of our consolidated operating revenues during fiscal 2009, compared with approximately 16 percent ($328.2 million) of consolidated operating revenues during fiscal 2008 and 20 percent ($320.3 million) in fiscal 2007. Rig utilization in fiscal 2009 was 68 percent, 82 percent in fiscal 2008 and 90 percent in fiscal 2007.

Venezuela

        We worked exclusively for the Venezuelan state petroleum company, PDVSA and a PDVSA-owned affiliate, during fiscal 2009 and revenues from this work accounted for approximately 21 percent of international operating revenues. Revenues recognized from Venezuelan drilling operations contributed approximately 3 percent ($50.3 million) of our consolidated operating revenues in fiscal 2009 compared to 8 percent in both fiscal years 2008 and 2007 ($167.2 million in fiscal 2008 and $127.3 million in fiscal 2007). We determined that as of the beginning of the second quarter of fiscal 2009 and forward, PDVSA no longer met the revenue recognition criteria as collectability became uncertain. As a result of this change, revenue of $57.9 million was not recorded in fiscal 2009. As a result of the uncertainty regarding the timing of collection of accounts receivables in U.S. dollars from PDVSA, during the second fiscal quarter of 2009, we decided to discontinue work as contracts expire. All of our eleven rigs were active in Venezuela at the end of 2008. At the end of fiscal 2009, one rig remained active and has since become idle. As a result, rig utilization in Venezuela decreased to approximately 64 percent in fiscal 2009 compared to approximately 97 percent during fiscal 2008 and approximately 92 percent in fiscal 2007. We will continue to pursue future drilling opportunities in Venezuela, but we do not expect to commit to new contracts until additional progress is made on pending accounts receivable and converting local currency to U.S. dollars. For additional information, see Item 1A. Risk Factors.

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Colombia

        At the end of fiscal 2009, we had six rigs in Colombia. Our utilization rate was approximately 88 percent during fiscal 2009, approximately 87 percent during fiscal 2008 and approximately 100 percent during fiscal 2007. Revenues generated by Colombian drilling operations contributed approximately 4 percent ($77.3 million) of our consolidated operating revenues during fiscal 2009, compared with approximately 2 percent in both fiscal years 2008 and 2007 ($42.4 million in fiscal 2008 and $26.8 million in fiscal 2007). Revenues from drilling services performed for our largest customer in Colombia totaled approximately 2 percent of consolidated operating revenues and approximately 20 percent of international operating revenues during fiscal 2009. The Colombian drilling contracts are primarily with large international or national oil companies.

Ecuador

        At the end of fiscal 2009, we had four rigs in Ecuador. The utilization rate in Ecuador was 100 percent in fiscal 2009, compared to 59 percent in fiscal 2008 and 89 percent in fiscal 2007. Revenues generated by Ecuadorian drilling operation contributed approximately 3 percent ($52.3 million in fiscal 2009 and $55.1 million in fiscal 2008) of our consolidated operating revenues for both fiscal years 2009 and 2008 compared to 6 percent ($93.9 million) of our consolidated operating revenues during fiscal 2007. Revenues from drilling services performed for the largest customer in Ecuador totaled approximately 2 percent of consolidated operating revenues and approximately 17 percent of international operating revenues during fiscal 2009. The Ecuadorian drilling contracts are primarily with large international or national oil companies.

Argentina

        At the end of fiscal 2009, we had nine rigs in Argentina. Our utilization rate was approximately 52 percent during fiscal 2009, approximately 88 percent during fiscal 2008 and approximately 100 percent during fiscal 2007. Revenues generated by Argentine drilling operations contributed approximately 2 percent of our consolidated operating revenues during fiscal 2009, 2008 and 2007 ($42.1 million, $44.4 million and $39.3 million, respectively). Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 1 percent of consolidated operating revenues and approximately 11 percent of international operating revenues during fiscal 2009. 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 2009 we had one rig in Tunisia, six rigs in Mexico, one rig en route to Africa and five rigs being used for prospective bidding purposes internationally. One new FlexRig was completed and ready for international delivery at September 30, 2009. The new rig is under contract with the location for work to be determined by the operator.

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 77 through 80 of our Annual Report (Exhibit 13 to this Form 10-K).

EMPLOYEES

        We had 4,250 employees within the United States (13 of which were part-time employees) and 1,134 employees in international operations as of September 30, 2009.

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 82 of our Annual Report (Exhibit 13 to this Form 10-K).

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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.

A sluggish global economy may affect our business.

        As a result of recent volatility in oil and natural gas prices and substantial uncertainty in the capital markets due to the global economic recession and 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 continued reduced demand for drilling rigs. These conditions could have a material adverse effect on our business.

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.

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 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. 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.

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 the current global economic environment may affect the customer's ability to pay the early termination payment.

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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 have two insurance policies covering six offshore platform rigs for "named wind storm" 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. Rig property insurance coverage expires in May 2010. No insurance is carried against loss of earnings or business interruption. 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.

        We have insurance coverage for comprehensive general liability, automobile liability, worker's compensation and employer's liability. Generally, casualty deductibles are $1 million or $2 million per occurrence, depending on whether a claim occurs inside or outside of the United States. We maintain certain other insurance coverages with deductibles as high as $5 million. 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 2010 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.

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.

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

7

        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.

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.

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. 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.

        Venezuela continues to experience significant political, economic and social instability. In the event that extended labor strikes occur or turmoil increases, we could experience shortages in labor and/or materials and supplies necessary to operate some or all of our Venezuelan drilling rigs, which could have a material adverse effect on our business, financial condition and results of operations.

        During the mid-1970s, the Venezuelan government nationalized the exploration and production business. At the present time it appears the Venezuelan government will not nationalize the contract drilling business. Any such nationalization could result in the loss of all or a portion of our assets and business in Venezuela.

        Although we attempt to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2009, approximately 13 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2009, approximately 93 percent of the international operating revenues were from operations in South America and approximately 57 percent of South American operating revenues were from Venezuela and Colombia.

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

General

        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 are more

8

frequently requesting that a greater proportion of these payments be made in local currencies. Based upon current information, we believe that exposure to potential losses from currency devaluation is immaterial in Colombia, Mexico, Equatorial Guinea, Trinidad and Tunisia. In those countries, all receivables and payments are currently in U.S. dollars. Cash balances are kept at an insignificant level which assists in reducing exposure.

Argentina

        In 2002, Argentina suffered a 60 percent devaluation of the peso. We invoice in U.S. dollars and are paid in pesos equivalent to the dollar invoice. Our Argentine subsidiary remits the dollars to the parent by exchanging pesos through the Argentine Central Bank. 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 fiscal 2009, which resulted in our recording of a $2.2 million currency loss.

Venezuela

        We are exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar fuerte (Bsf) net working capital (current assets minus current liabilities) balances, which at fiscal year end 2009 was approximately $71.4 million U.S. dollar equivalent. While we are unable to predict the potential magnitude and timing of future devaluation in Venezuela, if current activity levels continue and if a 10 percent to 100 percent devaluation were to occur, we could experience potential currency devaluation losses ranging from approximately $6.6 million to $35.7 million.

        While the collection of the receivables is difficult and time consuming due to PDVSA policies and procedures, at this time we have no reason to believe the amounts owed will not be paid. Historically, PDVSA payments on accounts receivable have, by traditional business measurements, been slower than those of our other customers. However, the failure of PDVSA to make payments on outstanding receivables, or a continued increase in its delay in making payments could have a material adverse effect on our business, financial condition and results of operations.

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.

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 $70 million borrowed and two letters of credit totaling $21.9 million outstanding against the facility at September 30, 2009. As of November 20, 2009, borrowings under the facility had declined to $40 million. 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.

9

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, 2009, we had a portfolio of securities with a total fair value of $360 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 19, 2009, the fair value of the portfolio had increased to approximately $387 million.

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 2009, we received approximately 59 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 31 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 would have a material adverse effect on our business, financial condition and results of operations.

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 find qualified individuals. Although to date our operations have not been materially affected by competition for personnel, an inability to obtain a sufficient number of qualified personnel could materially impact our business, financial condition and results of operations.

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.

10

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 2009 fiscal year and that remain unresolved.

Item 2.    PROPERTIES

CONTRACT DRILLING

        The following table sets forth certain information concerning our U.S. drilling rigs as of September 30, 2009:

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
OKLAHOMA		168	18,000	SCR (FlexRig1)	1,500
MISSISSIPPI		169	18,000	SCR (FlexRig1)	1,500
NORTH DAKOTA		179	18,000	SCR (FlexRig2)	1,500
NORTH DAKOTA		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
LOUISIANA		184	18,000	SCR (FlexRig2)	1,500
TEXAS		185	18,000	SCR (FlexRig2)	1,500
OKLAHOMA		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
TEXAS		213	18,000	AC (FlexRig3)	1,500
TEXAS		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
TEXAS		219	18,000	AC (FlexRig3)	1,500
LOUISIANA		221	18,000	AC (FlexRig3)	1,500
TEXAS		222	18,000	AC (FlexRig3)	1,500
TEXAS		223	18,000	AC (FlexRig3)	1,500
OKLAHOMA		225	18,000	AC (FlexRig3)	1,500
TEXAS		226	18,000	AC (FlexRig3)	1,500
TEXAS		227	18,000	AC (FlexRig3)	1,500
TEXAS		229	18,000	AC (FlexRig3)	1,500
TEXAS		233	18,000	AC (FlexRig3)	1,500
CALIFORNIA		236	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		246	18,000	AC (FlexRig3)	1,500

11

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
TEXAS		247	18,000	AC (FlexRig3)	1,500
TEXAS		248	18,000	AC (FlexRig3)	1,500
TEXAS		249	18,000	AC (FlexRig3)	1,500
OKLAHOMA		250	18,000	AC (FlexRig3)	1,500
OKLAHOMA		251	18,000	AC (FlexRig3)	1,500
LOUISIANA		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
TEXAS		269	18,000	AC (FlexRig3)	1,500
COLORADO		271	14,000	AC (FlexRig4)	1,500
COLORADO		272	14,000	AC (FlexRig4)	1,500
COLORADO		273	14,000	AC (FlexRig4)	1,500
COLORADO		274	14,000	AC (FlexRig4)	1,500
COLORADO		275	14,000	AC (FlexRig4)	1,500
COLORADO		276	14,000	AC (FlexRig4)	1,500
COLORADO		277	14,000	AC (FlexRig4)	1,500
COLORADO		278	14,000	AC (FlexRig4)	1,500
COLORADO		279	14,000	AC (FlexRig4)	1,500
COLORADO		280	14,000	AC (FlexRig4)	1,500
NEW MEXICO		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
WYOMING		284	14,000	AC (FlexRig4)	1,500
WYOMING		285	14,000	AC (FlexRig4)	1,500
WYOMING		286	14,000	AC (FlexRig4)	1,500
WYOMING		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
COLORADO		291	8,000	AC (FlexRig4)	1,150
COLORADO		292	8,000	AC (FlexRig4)	1,150
TEXAS		293	14,000	AC (FlexRig4)	1,500
TEXAS		294	14,000	AC (FlexRig4)	1,500
TEXAS		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
TEXAS		300	14,000	AC (FlexRig4)	1,500
TEXAS		301	8,000	AC (FlexRig4)	1,150
TEXAS		302	8,000	AC (FlexRig4)	1,150
TEXAS		303	8,000	AC (FlexRig4)	1,150

12

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
TEXAS		304	8,000	AC (FlexRig4)	1,150
TEXAS		305	8,000	AC (FlexRig4)	1,150
TEXAS		306	8,000	AC (FlexRig4)	1,150
WYOMING		307	14,000	AC (FlexRig4)	1,500
WYOMING		308	14,000	AC (FlexRig4)	1,500
WYOMING		309	14,000	AC (FlexRig4)	1,500
WYOMING		310	14,000	AC (FlexRig4)	1,500
WYOMING		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
WYOMING		315	14,000	AC (FlexRig4)	1,500
COLORADO		316	14,000	AC (FlexRig4)	1,500
TEXAS		317	14,000	AC (FlexRig4)	1,500
COLORADO		318	14,000	AC (FlexRig4)	1,500
COLORADO		319	14,000	AC (FlexRig4)	1,500
COLORADO		320	14,000	AC (FlexRig4)	1,500
COLORADO		321	14,000	AC (FlexRig4)	1,500
COLORADO		322	14,000	AC (FlexRig4)	1,500
WYOMING		323	14,000	AC (FlexRig4)	1,500
COLORADO		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
TEXAS		330	14,000	AC (FlexRig4)	1,500
TEXAS		331	14,000	AC (FlexRig4)	1,500
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
OKLAHOMA		343	14,000	AC (FlexRig4)	1,500
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
COLORADO		351	8,000	AC (FlexRig4)	1,150
COLORADO		352	8,000	AC (FlexRig4)	1,150
NEW MEXICO		370	18,000	AC (FlexRig3)	1,500
MISSISSIPPI		371	18,000	AC (FlexRig3)	1,500
TEXAS		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
LOUISIANA		382	18,000	AC (FlexRig3)	1,500
TEXAS		383	18,000	AC (FlexRig3)	1,500

13

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
TEXAS		384	18,000	AC (FlexRig3)	1,500
PENNSYLVANIA		385	18,000	AC (FlexRig3)	1,500
TEXAS		387	18,000	AC (FlexRig3)	1,500
MISSISSIPPI		388	18,000	AC (FlexRig3)	1,500
TEXAS		389	18,000	AC (FlexRig3)	1,500
LOUISIANA		391	18,000	AC (FlexRig3)	1,500
LOUISIANA		394	18,000	AC (FlexRig3)	1,500
LOUISIANA		395	18,000	AC (FlexRig3)	1,500
LOUISIANA		397	18,000	AC (FlexRig3)	1,500
LOUISIANA		398	18,000	AC (FlexRig3)	1,500
TEXAS		417	18,000	AC (FlexRig3)	1,500
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

14

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
OFFSHORE PLATFORM RIGS
TRINIDAD		203	20,000	Self-Erecting	2,500
GULF OF MEXICO		205	20,000	Self-Erecting	2,000
LOUISIANA		206	20,000	Self-Erecting	1,500
GULF OF MEXICO		100	30,000	Conventional	3,000
GULF OF MEXICO		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

        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,
		2005			2006			2007			2008			2009
U.S. Land Rigs
	Number of rigs at end of period		91			113			157			185			201
	Average rig utilization rate during period (1)		94	%		99	%		97	%		96	%		68	%
U.S. Offshore Platform Rigs
	Number of rigs at end of period		11			9			9			9			9
	Average rig utilization rate during period (1)		53	%		69	%		65	%		75	%		89	%

(1)

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

15

        The following table sets forth certain information concerning our international drilling rigs as of September 30, 2009:

Location	Rig		Optimum Depth (Feet)	Rig Type	Drawworks: Horsepower
Africa*		228	18,000	AC (FlexRig3)	1,500
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
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		245	18,000	AC (FlexRig3)	1,500
Mexico		253	18,000	AC (FlexRig3)	1,500
Texas#		339	8,000	AC (FlexRig4)	1,150
Texas^		220	18,000	AC (FlexRig3)	1,500
Texas^		224	18,000	AC (FlexRig3)	1,500
Texas^		232	18,000	AC (FlexRig3)	1,500
Texas^		235	18,000	AC (FlexRig3)	1,500
Texas^		238	18,000	AC (FlexRig3)	1,500
Tunisia		242	18,000	AC (FlexRig3)	1,500
Venezuela		113	30,000	SCR	3,000
Venezuela		115	30,000	SCR	3,000
Venezuela		116	30,000	SCR	3,000
Venezuela		127	30,000	SCR	3,000
Venezuela		128	30,000	SCR	3,000
Venezuela		129	30,000	SCR	3,000
Venezuela		135	30,000	SCR	3,000
Venezuela		150	30,000	SCR	3,000
Venezuela		153	30,000	SCR	3,000
Venezuela		160	26,000	SCR	2,000
Venezuela		174	30,000	SCR	3,000

*

En route to drilling location in Africa at September 30, 2009

#

Rig under contract with location to be determined by operator

^

Rig being used for prospective bidding purposes

16

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

	Years ended September 30,
	2005			2006			2007			2008			2009
Number of rigs at end of period		26			27			27			30			44
Average rig utilization rate during period (1)(2)		77	%		90	%		90	%		82	%		68	%

(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 27 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

        In our prior filings with the Securities and Exchange Commission ("SEC"), we disclosed that in connection with our Foreign Corrupt Practices Act training, questions were raised about the legality of certain past payments by one of our subsidiaries in connection with the passage of materials through customs in Latin America. In consultation with the Audit and the Nominating and Corporate Governance Committees of the Board of Directors, we engaged outside counsel and outside accountants to review these payments, other transactions of the subsidiary, and transactions at certain of our other operations in Latin America. We voluntarily reported this matter and the results of our investigations to the SEC and the Department of Justice ("DOJ") to inform them of this matter. On July 30, 2009, the SEC and the DOJ publicly announced the settlement of the matter.

        In connection with the SEC settlement, we agreed to cease and desist from committing or causing any violations of the books and records and internal controls provisions of sections 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and agreed to pay $375,681.22 in disgorgement and prejudgment interest to the SEC. In addition, we entered into a non-prosecution agreement with the DOJ in which the DOJ agreed not to prosecute the Company or our subsidiaries or affiliates and we agreed to pay a civil penalty of $1,000,000 to the DOJ. In connection with the settlements, we agreed to take additional remedial action to further enhance our compliance programs. There were no criminal charges involved in the settlements and we took disciplinary action with respect to certain employees involved in the matter, including in some cases, termination of employment. Both settlements recognize our voluntary disclosure, cooperation with both agencies, and our proactive remedial efforts.

        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.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        None.

17

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, 86	Chairman of the Board since 1960; Director since 1949
Hans Helmerich, 51	President and Chief Executive Officer since 1989; Director since 1987
Douglas E. Fears, 60	Executive Vice President and Chief Financial Officer since June 2008; Vice President and Chief Financial Officer since 1988
Steven R. Mackey, 58	Executive Vice President, Secretary and General Counsel since June 2008; Secretary since 1990; Vice President and General Counsel since 1988
John W. Lindsay, 48	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
M. Alan Orr, 58	Executive Vice President, Engineering and Development of Helmerich & Payne International Drilling Co. since 2006; Vice President and Chief Engineer of Helmerich & Payne International Drilling Co. since 1992
Gordon K. Helm, 56	Vice President and Controller. Vice President since 2008; Controller since 1993

18

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:

	2008				2009
Quarter	High		Low		High		Low
First	$	40.60	$	29.49	$	43.27	$	17.01
Second		47.89		32.86		28.93		19.50
Third		77.24		45.57		37.19		21.76
Fourth		75.38		39.33		41.08		26.64

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

	Paid per Share				Total Payment
	Fiscal				Fiscal
Quarter	2008		2009		2008		2009
First	$	.045	$	.050	$	4,678,511	$	5,273,254
Second		.045		.050		4,685,576		5,274,814
Third		.045		.050		4,706,051		5,281,430
Fourth		.050		.050		5,272,654		5,281,580

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

        As of November 19, 2009, there were 663 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 81 of our Annual Report (Exhibit 13 to this Form 10-K). All per share amounts have been adjusted as a result of a two-for-one stock split effective June 26, 2006.

Five-year Summary of Selected Financial Data

		2005		2006		2007		2008		2009
		(in thousands except per share amounts)
Operating revenues		$	800,726	$	1,224,813	$	1,629,658	$	2,036,543	$	1,894,038
Income from continuing operations			127,606		293,858		449,261		461,738		353,545
Income from continuing operations per common share:
	Basic		1.25		2.81		4.35		4.43		3.36
	Diluted		1.23		2.77		4.27		4.34		3.32
Total assets			1,663,350		2,134,712		2,885,369		3,588,045		4,161,024
Long-term debt			200,000		175,000		445,000		475,000		420,000
Cash dividends declared per common share			0.165		0.1725		0.18		0.185		0.20

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."

19

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 6 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		36
•       Credit Risk		38
•       Commodity Price Risk		39
•       Interest Rate Risk		40
•       Equity Price Risk		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 81 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.

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, 2009. 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

20

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, 2009.

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.

        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 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

* * *

21

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, 2009, 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, 2009, 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 as of September 30, 2009 and 2008 and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2009 of Helmerich & Payne, Inc. and our report dated November 24, 2009 expressed an unqualified opinion thereon.

	/S/ Ernst & Young LLP
Tulsa, Oklahoma November 24, 2009

22

Item 9B.    OTHER INFORMATION

        None.

23

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," "Committees," "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 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009. 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 2009" and "Compensation Committee Interlocks and Insider Participation" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009.

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 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009.

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 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009.

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 3, 2010, to be filed with the Commission not later than 120 days after September 30, 2009.

24

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, 2009, 2008 and 2007			43
		Consolidated Balance Sheets at September 30, 2009 and 2008			44-45
		Consolidated Statements of Shareholders' Equity for the Years Ended September 30, 2009, 2008 and 2007			46
		Consolidated Statements of Cash Flows for the Years Ended September 30, 2009, 2008 and 2007			47
		Notes to Consolidated Financial Statements			48-81
	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.

25

*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	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.
10.14	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.
*10.15	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 6, 2007, SEC File No. 001-04221.
*10.16	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.
*10.17	Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.27 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221.

26

10.18	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.
10.19	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.
10.20	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.
10.21	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.
*10.22	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.
*10.23	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.
*10.24	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.
*10.25	Amended form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2005 Long-Term 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 March 31, 2009, SEC File No. 001-04221.
10.26	364-Day Credit Agreement dated January 21, 2009, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, is incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed January 22, 2009, SEC File No. 001-04221.
10.27	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.
13.	The Company's Annual Report to Shareholders for fiscal 2009.
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.

27

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, 2009, filed on November 25, 2009, 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.

28

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 25, 2009

        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 25, 2009	By	/s/ RANDY A. FOUTCH Randy A. Foutch, Director Date: November 25, 2009
By	/s/ HANS HELMERICH Hans Helmerich, Director & CEO Date: November 25, 2009	By	/s/ W. H. HELMERICH, III W. H. Helmerich, III, Director Date: November 25, 2009
By	/s/ PAULA MARSHALL Paula Marshall, Director Date: November 25, 2009	By	/s/ FRANCIS ROONEY Francis Rooney, Director Date: November 25, 2009
By	/s/ EDWARD B. RUST, JR. Edward B. Rust, Jr., Director Date: November 25, 2009	By	/s/ JOHN D. ZEGLIS John D. Zeglis, Director Date: November 25, 2009
By	/s/ DOUGLAS E. FEARS Douglas E. Fears (Principal Financial Officer) Date: November 25, 2009	By	/s/ GORDON K. HELM Gordon K. Helm (Principal Accounting Officer) Date: November 25, 2009

29

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.

30

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	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.
	10.14	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.
	*10.15	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 6, 2007, SEC File No. 001-04221.
	*10.16	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.
	*10.17	Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.27 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2006, SEC File No. 001-04221.
	10.18	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.
	10.19	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.
	10.20	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.
	10.21	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.
	*10.22	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.
	*10.23	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.
	*10.24	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.

31

Exhibit No.		Description
	*10.25	Amended form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2005 Long-Term 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 March 31, 2009, SEC File No. 001-04221.
	10.26	364-Day Credit Agreement dated January 21, 2009, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, is incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed January 22, 2009, SEC File No. 001-04221.
	10.27	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.
	13.	The Company's Annual Report to Shareholders for fiscal 2009.
	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, 2009, filed on November 25, 2009, 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 Compensation Plan or Arrangement.

32

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 and Africa.
Holdings also include commercial real estate properties in the
Tulsa, Oklahoma, area, and an energy-weighted portfolio of
securities valued at approximately $360 million as of
September 30, 2009.

FINANCIAL HIGHLIGHTS

Years Ended September 30,	2009		2008		2007
		(in thousands, except per share amounts)
Operating Revenues		$1,894,038		$2,036,543		$1,629,658
Net Income		353,545		461,738		449,261
Diluted Earnings per Share		3.32		4.34		4.27
Dividends Paid per Share		0.2000		.1850		.1800
Capital Expenditures		880,753		705,635		894,214
Total Assets		4,161,024		3,588,045		2,885,369

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

         A year ago at this time, we understood that 2009 would be a challenging year for the drilling business, but we were still somewhat dismayed by the rapidity and extent of a decline that rivaled what the industry experienced in the early 1980s. In our largest segment, U.S. Land, the utilization rate fell from an average of 97 percent in October to a low of about 50 percent in June, which was significantly higher than that of our peer group. Customers seeing both the collapse in commodity prices and the implosion of the credit markets took drastic measures to conserve cash flow and protect their balance sheets by cutting drilling programs to the bone. Consequently, the Company received termination notices on term contracts representing 37 U.S. Land new build rigs, each of which had begun work prior to fiscal 2008. The option for the early termination fee was built into each of our term contracts to provide our customers with the flexibility to change their plans in mid-stream while at the same time protecting the Company for the significant financial commitments it made to build new high efficiency rigs. Although our capital risk was mitigated, we would have much preferred to continue the contracts and keep our people intact and fully engaged.

         While we are encouraged by the improvement in the energy markets since the low point early last year, we remain cautious about current supply and demand dynamics and what they mean for natural gas pricing during 2010.

         Prospects for any sustained price improvement will depend on natural gas demand in 2010. Industrial demand was hammered this past year and the size of the rebound will be tied to achieving real economic recovery. Weather related demand, aided by a winter with above average heating days, could also play an important role. Longer term opportunities for improved natural gas demand are plentiful, including inroads into the transportation fuel market.

         Of course, on the supply side of the equation, caution abounds, especially in the short-term. In addition to the well known gas shale potential, all-time high gas inventory levels are currently buttressed by a sizeable backlog of uncompleted wells. Some estimate there are approximately 1,500 of these deferred wells in the U.S.

         Future LNG imports are an ongoing source of added supply potential with worldwide capacity having jumped by a third in the last two years. It is uncertain how much of this new capacity will land in the U.S.

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         While these concerns set up a possible "2^nd bottom," we believe the more likely outcome is that they act to somewhat flatten the curve and push it to the right. In many respects, avoiding some of the typical volatility even on the upside would be a good thing. Arguably, the worst thing for the industry would be another price spike.

         One silver lining of this past year was that lower utilization created opportunities for us to appeal to new customers, who may not have tried a FlexRig before for lack of availability. Six FlexRigs began working in Mexico under a Schlumberger Integrated Project Management contract and we also moved four rigs to the Marcellus in Pennsylvania, which is fast becoming a key natural gas basin in the lower 48. All told, we have initiated work with 25 first time FlexRig users and all of them had cheaper alternatives in terms of dayrates. Winning new customers speaks to a larger point of gaining market share in good times and bad. Not long ago, we were number five in terms of market share in U.S. Land Drilling. This calendar year, while we still don't have the largest fleet, we achieved the highest amount of drilled footage through October in the lower 48 land market. As we've gained market share, we have also maintained premium margins to our peer group, becoming the U.S. land drilling industry's most profitable contractor during our fiscal year.

         As the industry slowly recovers, we have no illusions about the environment we're faced with. Keeping our focus on the customer's need for efficiency and safety in the field will continue to drive our long-term success. Of course that success is earned every day, 24-7. It requires hard work, a focus on safety, and is often conducted under challenging conditions. As the Company begins its 90^th year as the industry's oldest land contractor, I am reminded that it is the strong values of our past, combined with a drive for innovation and improved performance that secures our future. In that spirit, I feel a deep sense of gratitude toward the H&P men and women whose commitment and loyalty continue to make that possible.

	Sincerely,
	Hans Helmerich President
November 25, 2009

3

Financial & Operating Review

Years Ended September 30,			2009		2008		2007
SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*†
Operating Revenues				$1,894,038		$2,036,543		$1,629,658
Operating Costs, excluding depreciation				1,011,558		1,086,666		862,254
Depreciation**				236,437		210,766		146,042
General and Administrative Expense				59,413		57,059		47,401
Operating Income (loss)				583,532		692,816		632,319
Interest and Dividend Income				4,965		5,038		4,234
Gain on Sale of Investment Securities				—		21,994		65,458
Interest Expense				13,490		18,689		10,126
Net Income from Continuing Operations				353,545		461,738		449,261
Net Income				353,545		461,738		449,261
Diluted Earnings Per Common Share:
	Net Income from Continuing Operations			3.32		4.34		4.27
	Net Income			3.32		4.34		4.27
*$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 $94,425
SUMMARY FINANCIAL DATA*
Cash**				$    141,486		$   121,513		$      89,215
Working Capital**				221,026		381,690		272,352
Investments				356,404		199,266		223,360
Property, Plant, and Equipment, Net**				3,265,907		2,682,251		2,152,616
Total Assets				4,161,024		3,588,045		2,885,369
Long-term Debt				420,000		475,000		445,000
Shareholders' Equity				2,683,009		2,265,474		1,815,516
Capital Expenditures				880,753		705,635		894,214
*$000's omitted ** Excludes discontinued operations.
RIG FLEET SUMMARY
Drilling Rigs –
	U. S. Land – FlexRigs			163		146		118
	U. S. Land – Highly Mobile			11		12		12
	U. S. Land – Conventional			27		27		27
	Offshore Platform			9		9		9
	International Land			44		30		27
		Total Rig Fleet		254		224		193
Rig Utilization Percentage –
	U. S. Land – FlexRigs			76		100		100
	U. S. Land – Highly Mobile			29		83		93
	U. S. Land – Conventional			39		80		87
	U. S. Land – All Rigs			68		96		97
	Offshore Platform			89		75		65
	International Land			68		82		90

4

2006		2005		2004			2003		2002		2001		2000		1999
	$1,224,813		$   800,726		$   589,056			$   504,223		$   523,418		$   528,187		$   383,898		$   430,475
	661,563		484,231		417,716			346,259		362,133		331,063		249,318		288,969
	101,583		96,274		145,941			82,513		61,447		49,532		77,317		70,092
	51,873		41,015		37,661			41,003		36,563		28,180		23,306		24,629
	417,286		192,756		(6,885	)		38,137		64,667		123,613		34,826		49,024
	9,834		5,809		1,965			2,467		3,624		9,128		18,215		4,830
	19,866		26,969		25,418			5,529		24,820		1,189		13,295		2,547
	6,644		12,642		12,695			12,289		980		1,701		2,730		5,389
	293,858		127,606		4,359			17,873		53,706		80,467		36,470		32,115
	293,858		127,606		4,359			17,873		63,517		144,254		82,300		42,788
	2.77		1.23		.04			.18		.53		.79		.36		.32
	2.77		1.23		.04			.18		.63		1.42		.82		.43

$      33,853	$   288,752	$      65,296	$      38,189	$      46,883	$   128,826	$   107,632	$      21,758
164,143	410,316	185,427	110,848	105,852	223,980	179,884	82,893
218,309	178,452	161,532	158,770	150,175	203,271	307,425	240,891
1,483,134	981,965	998,674	1,058,205	897,445	650,051	526,723	553,769
2,134,712	1,663,350	1,406,844	1,417,770	1,227,313	1,300,121	1,200,854	1,073,465
175,000	200,000	200,000	200,000	100,000	50,000	50,000	50,000
1,381,892	1,079,238	914,110	917,251	895,170	1,026,477	955,703	848,109
528,905	86,805	90,212	242,912	312,064	184,668	65,820	78,357
73	50	48	43	26	13	6	6
12	12	11	11	11	11	10	11
28	29	28	29	29	25	22	23
9	11	11	12	12	10	10	10
27	26	32	32	33	37	40	39
149	128	130	127	111	96	88	89
100	100	99	97	96	100	99	79
100	99	91	89	97	89	95	90
95	82	67	58	70	99	77	61
99	94	87	81	84	97	85	69
69	53	48	51	83	98	94	95
90	77	54	39	51	56	47	53

5

Management's Discussion and 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, 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 and 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 6 of our Form 10-K are important factors (but not necessarily all important factors) that could cause actual results to differ materially from those expressed in any

6

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 254 drilling rigs at September 30, 2009. Our contract drilling segments include the U.S. Land segment in which we had 201 rigs, the Offshore segment in which we had 9 offshore platform rigs, and the International Land segment in which we had 44 rigs at September 30, 2009. As oil and natural gas prices steeply declined and the credit markets tightened in late calendar 2008, customers aggressively reduced drilling budgets. As a result, we experienced a decline in rig utilization in the U.S. Land segment and in some countries in the International Land segment. We believe that utilization has stabilized and is now slowly improving. During this cycle, we have had the opportunity to attract new customers. Additionally, we are seeing opportunities for expansion in international markets as we entered Mexico and placed a second rig in Africa during the fiscal year. We have also penetrated new markets in the U.S. Drilling has become more challenging with growing unconventional plays, requiring more highly capable rigs which are expected to be in short supply as demand improves. With our fleet that includes 183 FlexRigs with advanced technology, we are well positioned to meet the long-term needs of our customers and compete successfully for opportunities in an improving market.

RESULTS OF OPERATIONS

All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net income for 2009

7

was $353.5 million ($3.32 per share), compared with $461.7 million ($4.34 per share) for 2008 and $449.3 million ($4.27 per share) for 2007. Included in our net income were after-tax gains from the sale of investment securities of $13.5 million ($0.13 per share) in 2008 and $40.2 million ($0.38 per share) in 2007. Net income also includes after-tax gains from the sale of assets of $3.6 million ($0.04 per share) in 2009, $8.6 million ($0.08 per share) in 2008 and $26.5 million ($0.25 per share) in 2007. 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, $0.16 per share in 2008 and $0.09 per share in 2007. 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 deferred as a component of other comprehensive income.

Consolidated operating revenues were $1,894.0 million in 2009, $2,036.5 million in 2008, and $1,629.7 million in 2007. During 2007 and 2008, U.S. land revenues increased due to the addition of FlexRigs combined with continued increases in dayrates since 2005. 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 68 percent in 2009, 96 percent in 2008 and 97 percent in 2007. The average number of U.S. land rigs available was 194 rigs in 2009, 171 rigs in 2008 and 134 rigs in

8

2007. Revenue in the Offshore segment increased over the three-year period primarily as a result of rig utilization for offshore rigs increasing to 89 percent in 2009, compared to 75 percent in 2008 and 65 percent in 2007. International rig revenues decreased in 2009 after increasing in 2008 from 2007. Contributing to the decrease in revenue in 2009 was the discontinuation of recording revenue in Venezuela for the last three fiscal quarters of 2009. Additionally, rig utilization in 2009 declined to 68 percent as we discontinued work in Venezuela as contracts expired. For further detail regarding Venezuela, see the International Land segment below and Note 14 of the Consolidated Financial Statements. The increase in revenue in 2008 from 2007 was due to increases in dayrates even though rig utilization declined in 2008 to 82 percent from 90 percent in 2007.

We did not sell any investment securities in 2009, but recorded gains of $22.0 million in 2008 and $65.5 million in 2007. Interest and dividend income was $5.0 million in 2009 and 2008 and $4.2 million in 2007.

Direct operating costs in 2009 were $1,011.6 million, compared with $1,086.7 million in 2008 and $862.3 million in 2007. Direct operating costs for all three years were 53 percent of operating revenues.

Depreciation expense was $236.4 million in 2009, $210.8 million in 2008 and $146.0 million in 2007. Included in depreciation are abandonments of equipment of $5.3 million in 2009, $13.3 million in 2008, and $4.1 million in 2007. Depreciation expense, exclusive of the abandonments, increased over the three-year period as we placed into service 25 new rigs in 2009, 29 in 2008 and 48 in 2007. Depreciation expense in 2010 is expected to increase from 2009 from

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new rigs placed into service during 2009 and additional rigs placed into service during 2010. (See Liquidity and Capital Resources)

As conditions warrant, management performs an analysis of the industry market conditions in each drilling segment. Based on this analysis, management determines if any impairment is required. In 2009, 2008 and 2007, no impairment was recorded.

General and administrative expenses totaled $59.4 million in 2009, $57.1 million in 2008, and $47.4 million in 2007. The $2.3 million increase in 2009 from 2008 is primarily due to an increase in banking and legal fees associated with obtaining new debt, increased pension expense and services associated with the FCPA investigation and settlement discussed further in Item 3 Legal Proceedings of our Form 10-K. These increases were partially offset with a decrease in current year employee bonus accruals. The increase in 2008 from 2007 was primarily a result of increases in expenses associated with employee labor and employee benefits due to increases in the number of employees.

Interest expense was $13.5 million in 2009, $18.7 million in 2008, and $10.1 million in 2007. The interest expense is primarily attributable to the fixed-rate intermediate debt outstanding in each year and advances on the senior credit facility in 2009 and 2008. Interest expense decreased in 2009 from 2008 primarily as a result of reduced interest rates. Interest expense in 2008 increased from 2007 due to higher outstanding debt balances during 2008. Capitalized interest was $6.6 million, $4.7 million and $9.4 million in 2009, 2008 and 2007, respectively. All of the capitalized interest is attributable to our rig build program. The higher capitalized interest

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in 2007 was due to a higher number of new rigs being constructed during that year.

The provision for income taxes totaled $232.4 million in 2009, $255.6 million in 2008, and $251.0 million in 2007. The effective income tax rate increased to 40 percent in 2009 from 37 percent in 2008, and 36 percent in 2007. The increase in the effective tax rate is primarily due to Venezuelan income taxes being calculated using the accrual method of accounting for financial purposes while we are recognizing revenue in Venezuela using the cash basis method of accounting. 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 3 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 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.

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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 represents 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 up to $11 million based on specific commerciality milestones and certain earn-out provisions based on future earnings being met.

During 2009 and 2008, we incurred $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 be approximately $2.5 million in each quarter during 2010.

The following tables summarize operations by reportable operating segment.

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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		(12.4	)
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		(19.7	)%
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.

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 is 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 is 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 12.4 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

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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 is 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 includes charges for abandoned equipment of $4.9 million and $13.2 million in 2009 and 2008, respectively. Excluding the abandonment amounts, depreciation in 2009 increased 23 percent from 2008 due to the increase in available rigs.

We expect to complete and deliver another seven new FlexRigs by the end of the third fiscal quarter of 2010. Like those completed in fiscal 2009, 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 2009 and additional rigs scheduled for completion in 2010, we anticipate depreciation expense to continue to increase in fiscal 2010.

During 2009, the economic recession, including the decrease in oil and natural gas prices and deterioration in the credit markets, had a significant effect on customer spending and drilling activity. 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. Although not as severe as that experienced by most

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of our peers, we experienced a significant decline in drilling activity. Since June 2009, however, the industry's U.S. land rig count has been experiencing a slight recovery. At September 30, 2009, 122 out of 201 existing rigs in the U.S. Land segment were generating revenue. Of the 122 rigs generating revenue, 94 were under fixed term contracts, and 28 were working in the spot market. At November 19, 2009, the number of existing rigs under fixed term contracts in the segment increased to 96, and the number of rigs working in the spot market increased to 31.

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 higher activity including a rig that began work in Trinidad during 2008.

Currently, we have seven of our nine platform rigs working. One of the seven rigs is expected to become idle during the first quarter of

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fiscal 2010 and one of the two idle rigs began work under a new contract in November 2009.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2009 AND 2008

	2009			2008			% Change
INTERNATIONAL LAND OPERATIONS		(in thousands, except operating statistics)
Operating revenues		$237,397			$328,244		(27.7	)%
Direct operating expenses		213,552			224,683		(5.0	)
General and administrative expense		2,892			3,974		(27.2	)
Depreciation		28,180			29,614		(4.8	)
Segment operating income (loss)		$  (7,227	)		$  69,973		(110.3	)
Operating Statistics:
Revenue days		7,374			8,026		(8.1	)%
Average rig revenue per day		$  29,650			$  37,604		(21.2	)
Average rig expense per day		$  25,993			$  24,489		6.1
Average rig margin per day		$    3,657			$  13,115		(72.1	)
Number of rigs at end of period		44			30		46.7
Rig utilization		68	%		82	%	(17.1	)

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $18,755 and $26,431 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.

The International Land segment had an operating loss of $7.2 million for 2009 compared to operating income of $70.0 million for 2008. As further discussed in Note 14 of the Consolidated Financial Statements, 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. As a result, $57.9 million of revenue was not recorded during 2009. Primarily because of this change, revenue and average revenue per day decreased in 2009 compared to 2008. Revenues not recognized in 2009 will be recognized in future periods when cash is collected.

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Rig utilization for international land operations decreased to 68 percent in 2009 from 82 percent in 2008. The ability to collect accounts receivables in U.S. dollars from PDVSA deteriorated to the point that during the second fiscal quarter of 2009, we decided to discontinue work as contracts expired. All of our eleven rigs in Venezuela were active at the end of 2008. At the end of 2009, one rig remained active and has since become idle. During 2009, 12 rigs were transferred to the International Land segment from the U.S. Land segment. Of those twelve, seven are under contract and the remaining five are being used for bidding prospective work. The reduced activity in Venezuela and rigs transferred to the segment that are not yet working contributed to the decrease in utilization. The total number of rigs at September 30, 2009 was 44 compared to 30 rigs at September 30, 2008. The increase is due to two FlexRigs completed and ready for delivery and 12 rigs transferred from the U.S. Land segment. Three of the FlexRigs completed in 2008 were placed into service in 2009. The fourth rig completed in 2008 is under contract and will be sent to a location to be determined by the operator.

The average rig expense per day increased in 2009 from 2008 primarily due to labor and stacking expenses related to rigs that became idle during 2009.

We will continue to pursue future drilling opportunities in Venezuela, but do not expect to commit to new contracts until additional progress is made on unpaid invoices and converting local currency to U.S. dollars.

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COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2008 AND 2007

	2008			2007			% Change
U.S. LAND OPERATIONS		(in thousands, except operating statistics)
Operating revenues		$1,542,038			$1,174,956		31.2	%
Direct operating expenses		756,828			587,825		28.8
General and administrative expense		17,599			14,024		25.5
Depreciation		161,893			106,107		52.6
Segment operating income		$   605,718			$   467,000		29.7
Operating Statistics:
Revenue days		59,804			47,338		26.3	%
Average rig revenue per day		$      24,522			$      23,573		4.0
Average rig expense per day		$      11,393			$      11,170		2.0
Average rig margin per day		$      13,129			$      12,403		5.9
Number of rigs at end of period		185			157		17.8
Rig utilization		96	%		97	%	(1.0	)

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $75,519 and $59,035 for 2008 and 2007, respectively.
Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2007.

Operating income in the U.S. Land segment increased to $605.7 million in 2008 from $467.0 million in 2007. Improvement in revenue was primarily the result of increased revenue days and increased dayrates for new rigs placed in service during 2008. Rig utilization decreased to 96 percent in 2008 from 97 percent in 2007. At September 30, 2008, two conventional rigs and one highly mobile rig were stacked. The total number of rigs at September 30, 2008 was 185 compared to 157 rigs at September 30, 2007. The increase was due to 28 new FlexRigs being completed and placed into service. Depreciation included charges for abandoned equipment of $13.2 million and $2.3 million in 2008 and 2007, respectively. Excluding the abandonment amounts, depreciation in 2008 increased 43.2 percent from 2007 due to the increase in available rigs.

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COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2008 AND 2007

	2008			2007			% Change
OFFSHORE OPERATIONS		(in thousands, except operating statistics)
Operating revenues		$154,452			$123,148		25.4	%
Direct operating expenses		104,454			85,556		22.1
General and administrative expense		4,452			4,824		(7.7	)
Depreciation		12,152			10,687		13.7
Segment operating income		$  33,394			$  22,081		51.2
Operating Statistics:
Revenue days		2,442			2,141		14.1	%
Average rig revenue per day		$  47,743			$  34,469		38.5
Average rig expense per day		$  29,655			$  21,564		37.5
Average rig margin per day		$  18,088			$  12,905		40.2
Number of rigs at end of period		9			9		—
Rig utilization		75	%		65	%	15.4

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $16,330 and $14,328 for 2008 and 2007, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense.

Segment operating income in our Offshore segment increased 51.2 percent in 2008 from 2007 due to increased activity and a rig beginning work in Trinidad.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2008 AND 2007

	2008			2007			% Change
INTERNATIONAL LAND OPERATIONS		(in thousands, except operating statistics)
Operating revenues		$328,244			$320,283			2.5	%
Direct operating expenses		224,683			188,086			19.5
General and administrative expense		3,974			3,236			22.8
Depreciation		29,614			23,782			24.5
Segment operating income (loss)		$  69,973			$105,179			(33.5	)
Operating Statistics:
Revenue days		8,026			8,886			(9.7	)%
Average rig revenue per day		$  37,604			$  31,465			19.5
Average rig expense per day		$  24,489			$  16,708			46.6
Average rig margin per day		$  13,115			$  14,757			(11.1	)
Number of rigs at end of period		30			27			11.1
Rig utilization		82	%		90	%		(8.9	)

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $26,431 and $40,113 for 2008 and 2007, respectively. Also excluded are the effects of currency revaluation expense.
Rig utilization excludes four FlexRigs completed and ready for delivery at September 30, 2008.

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Segment operating income for our International Land segment decreased 33.5 percent from 2007 to 2008. Depreciation and operating income for 2008 were negatively impacted by an adjustment of approximately $5.9 million related to prior years' depreciation. Rig utilization for international land operations decreased to 82 percent in 2008 from 90 percent in 2007. Direct operating expenses increased in 2008 from 2007 as oilfield cost inflation pressures and labor cost increases in the international markets were experienced.

LIQUIDITY AND CAPITAL RESOURCES

Our capital spending was $880.8 million in 2009, $705.6 million in 2008, and $894.2 million in 2007. Net cash provided from operating activities was $897.3 million in 2009, $610.8 million in 2008 and $561.1 million in 2007. Our 2010 capital spending estimate is approximately $225 million, a decrease from the $881 million incurred during 2009. The primary reason for the decrease in estimated capital expenditures is that only seven contracted new FlexRigs are scheduled to be completed during 2010, a significant reduction in the number of new rigs built compared to 2009.

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.

We manage a portfolio of marketable securities that, at the close of fiscal 2009, had a market value of $359.5 million. Our investments

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in Atwood and Schlumberger, Ltd. made up 95 percent of the portfolio's market value on September 30, 2009. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding our investments in limited 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 and $73.4 million in 2007. We did not sell any portfolio securities in 2009.

The following table reconciles cash proceeds from the sale of portfolio securities stated above to proceeds from sale of investments shown in the Consolidated Statements of Cash Flows in our Consolidated Financial Statements:

	2009		2008		2007
		(in thousands)
Proceeds from the sale of portfolio securities		$—		$25,507		$  73,405
Sales with a trade date in current fiscal year but cash received in subsequent fiscal year		—		—		6,093
Proceeds from the sale of short-term investments		—		—		48,321
Proceeds from sale of investments per Consolidated Statements of Cash Flows		$—		$25,507		$127,819

In 2008, proceeds were from the sale of 170,000 shares of Schlumberger, Ltd. and all other available-for-sale securities we owned. In 2007, proceeds were primarily from the sale of 1,012,500 shares of Schlumberger, Ltd. Proceeds in both years were primarily used to fund capital expenditures.

Our proceeds from asset sales totaled $8.7 million in 2009, $22.9 million in 2008 and $51.6 million in 2007. In 2008, two international land rigs were sold generating $13.0 million in

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proceeds. Income from asset sales in 2008 totaled $13.5 million. In 2007, one U.S. land rig and two offshore rigs were sold generating $36.7 million in proceeds. Income from all asset sales in 2007 totaled $41.7 million. The rigs sold in each year 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, 2008 and 2007, we received insurance proceeds of approximately $0.2 million, $5.3 million and $19.2 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 in 2009, $10.2 million in 2008 and $16.7 million in 2007. 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.

From March 2005 through November 2008, we announced commitments with exploration and production companies to build a cumulative total of 140 new FlexRigs under fixed term contracts to perform drilling services on a daywork basis. Eight of these 140 new rigs were contracted for work in International Land operations and

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the remaining 132 in U.S. Land operations. We completed 133 of the 140 rigs through fiscal 2009 and have seven remaining new FlexRigs to complete by the end of the third fiscal quarter of 2010. The total estimated construction cost of all 140 rigs, including tubular and other ancillary equipment, is currently $2.2 billion, most of which was spent by the end of fiscal 2009.

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 6.50 percent. The terms of the debt obligations require that we maintain a minimum ratio of debt to total capitalization.

On July 21, 2009, we closed a private placement of our senior unsecured fixed rate notes maturing in July 2016 and received proceeds of $200 million. Interest on the notes will be 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 the third anniversary of the closing date. 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. The $200 million of proceeds from this facility were used to reduce our $400 million senior credit facility by $105 million and the remainder was used to fund capital expenditures and for other general corporate purposes.

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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 2009 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 .60 percent. At September 30, 2009, we had two letters of credit totaling $21.9 million under the facility and had borrowed $70 million against the facility with $308.1 million remaining available to borrow. Subsequent to September 30, 2009, we reduced the debt by $30 million and had $338.1 million available to borrow.

In January 2009, we closed an agreement with a multi-bank syndicate for a $105 million unsecured line of credit that matures January 2010. We committed to fully fund this facility for the entire term at a spread over 30 day LIBOR. The spread over LIBOR is determined according to the same scale of debt to total capitalization used in our $400 million facility which is described in the preceding paragraph. The spread over LIBOR for the new facility has increased to a range of 2 percent to 2.75 percent. At September 30, 2009, the spread on the borrowing was 2.25 percent over LIBOR. Simultaneous with the closing of this facility, we entered into an interest-rate swap with the same maturity and a notional amount of $105 million. We believe that the swap will act to fix the annualized interest rate of the facility at approximately 3.17 percent assuming the spread remains at 2.25 percent over LIBOR. The interest rate swap qualifies as a

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derivative and was not designated as a hedging instrument and, as such, we have not applied hedge accounting. At the end of an accounting period, the interest rate swap is recorded in the Consolidated Balance Sheet at fair value, either in other current assets or accrued liabilities, and any related gains or losses are recognized on our Consolidated Statement of Income within interest expense. The fair value of the interest rate swap liability at September 30, 2009 was $0.2 million and is included in accrued liabilities in the Consolidated Balance Sheet. Interest expense on the interest rate swap was $0.6 million during 2009.

Financial covenants in both facilities 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. Both facilities contain 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, 2009, we were in compliance with all debt covenants.

At September 30, 2009, we had unsecured letters of credit totaling $3.2 million which were used to obtain surety bonds for our international operations.

At September 30, 2009, we had 107 existing rigs with contracts under fixed terms with original term durations ranging from twelve months to seven years, with some expiring in fiscal 2010. 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. The 2009 economic slowdown, including the decrease in oil and natural gas prices and deterioration in the credit markets had a significant effect on customer spending. As a result, during 2009 some of our

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customers exercised termination provisions and elected to pay the early termination fee in lieu of continued drilling. 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 2010 will be funded through current cash, cash provided from operating activities, funds available under the current credit facilities, funds available under any new credit facility and, possibly, sales of available-for-sale securities. We anticipate that we will be able to utilize working capital as well as available borrowing capacity under our $400 million line of credit to pay off the $105 million facility when it matures in January 2010.

The current ratio was 1.7 at September 30, 2009 and 2.2 at September 30, 2008. The long-term debt to total capitalization ratio was 14 percent and 17 percent at September 30, 2009 and 2008, respectively. The decrease is due to equity increasing, primarily from earnings and a decrease in long-term debt.

During 2009, we paid dividends of $0.20 per share, or a total of $21.1 million, representing the 37th consecutive year of dividend increases.

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STOCK PORTFOLIO HELD

September 30, 2009	Number of Shares		Cost Basis		Market Value
		(in thousands, except share amounts)
Atwood Oceanics, Inc.		8,000,000		$121,498		$282,160
Schlumberger, Ltd.		967,500		7,685		57,663
Other				12,369		19,707
Total				$141,552		$359,530

MATERIAL COMMITMENTS

We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations as of September 30, 2009, are summarized in the table below in thousands:

	Payments due by year
Contractual Obligations	Total		2010		2011		2012		2013		2014		After 2014
Long-term debt and estimated interest (a)		$517,887		$  22,385		$22,385		$206,382		$54,205		$126,159		$86,371
Short-term debt and estimated interest (b)		106,041		106,041		—		—		—		—		—
Operating leases (c)		32,182		8,165		6,145		3,050		2,569		2,271		9,982
Purchase obligations (c)		63,092		63,092		—		—		—		—		—
Total Contractual Obligations		$719,202		$199,683		$28,530		$209,432		$56,774		$128,430		$96,353

(a)  The estimated future interest payments on our variable-rate credit facilities were based on the interest rate and principal balance at September 30, 2009. Interest on fixed-rate debt was estimated based on principal maturities. See Note 2 "Debt" to our Consolidated Financial Statements.
(b)  Estimated interest was calculated based on the interest rate at September 30, 2009 and includes the value of an interest rate swap liability at September 30, 2009. See Note 2 "Debt" to our Consolidated Financial Statements.
(c)  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 2009, we contributed $0.8 million to the pension plan. Based on current information available from plan actuaries, we estimate contributing at least $3.0 million in 2010 to meet the minimum contribution required by law. We expect to make additional contributions to fund distributions in lieu of liquidating pension assets. With the unpredictability in the equity, debt and global markets, it is possible that contributions in fiscal 2010 will be greater

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than expected. Future contributions beyond 2010 are difficult to estimate due to multiple variables involved.

At September 30, 2009, we had $6.9 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 3 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 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

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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 and rig utilization. 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 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

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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 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 820-10. (See Note 7 of the Consolidated Financial Statements for disclosures.)

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. We maintain certain other insurance coverage with deductibles as high as $5 million. 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.

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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, 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. We maintain certain other insurance coverage with deductibles as high as $5 million. Excess insurance is purchased over these coverages 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.

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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 7.25 percent to 5.42 percent as of September 30, 2009 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 from future periods. We anticipate pension expense in 2010 to increase from 2009 by an estimated $2.1 million.

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 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

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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 based on the closing 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, 2009, unrecognized compensation cost related to unvested restricted stock was $2.2 million. The cost is expected to be recognized over a weighted-average period of 1.5 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, 2008, we adopted the disclosure requirements of Accounting Standards Codification (ASC) 820-10, Fair Value Measurements and Disclosures issued by the Financial Accounting Standards Board (FASB) in September 2006, which defines fair value,

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establishes a framework for measuring fair value and expands disclosures about fair value measurements required under other accounting pronouncements, but does not change existing guidance for carrying instruments at fair value. Our adoption of the required portions of ASC 820-10 as of October 1, 2008 did not have a material impact on our financial position, results of operations or cash flows. ASC 820-10-65, Transition related to FASB Staff Position FAS157-2, issued in February 2008, delays the application of ASC 820-10 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually), and will be adopted by us beginning the first quarter of fiscal 2010. Our adoption on October 1, 2009 is not expected to have a significant impact on the Consolidated Financial Statements.

ASC 825-10, Financial Instruments, permits choosing to measure certain financial assets and liabilities at fair value. We elected not to measure any assets or liabilities at fair value which were not being so measured prior to adopting ASC 820-10 on October 1, 2008.

In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value (ASU 2009-05). This update provides 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. ASU 2009-05 is effective for reporting periods beginning after August 28, 2009, which means that it will be effective for our first quarter beginning October 1, 2009. We do not currently believe this update will have a significant impact on the Consolidated Financial Statements.

On October 1, 2009, 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 recognize a realized

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income tax benefit associated with dividends or dividend equivalents paid on nonvested equity-classified employee share-based payment awards that are 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.

In June 2008, the FASB issued guidance contained in ASC 260-10-45 to clarify 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 260-10-05, Earnings per Share. We will adopt ASC 260-10-45 October 1, 2009. All prior-period earnings per share data presented will be adjusted retrospectively to conform to the provisions of ASC 260-10-45. We expect the impact, if any, of adopting ASC 260-10-45 to be immaterial on our prior period earnings per share.

ASC 715-20-65, Transition related to SFAS 132R-1, Employers' Disclosures about Postretirement Benefit Plan Assets, was issued by the FASB in December 2008. The new guidance requires employers of public and nonpublic companies to disclose 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 are effective for years ending after December 15, 2009. We will adopt the disclosure requirements for the year ended September 30, 2010, on a prospective basis. We do not expect the adoption to have a material impact on the Consolidated Financial Statements.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Foreign Currency Exchange Rate Risk We have operations in several South American countries, Trinidad, Mexico and Africa. With the exception of Argentina and Venezuela, 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 fiscal 2009, resulting in the recording a $2.2 million currency loss.

We are exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar fuerte (Bsf) receivable balances and Bsf cash balances. We have an agreement with the Venezuelan state oil company, PDVSA, whereby 60 percent of our billings are in U.S. dollars and 40 percent are in the local currency, the bolivar fuerte. PDVSA has previously paid U.S. dollar invoices in Bsf which increases our exposure to foreign currency devaluation. In 2008, we received notification from PDVSA that exchange of those U.S. dollar invoices previously paid in Bsf would be made only when supporting documentation had been approved. The supporting documentation was delivered to PDVSA and is awaiting approval. The approval and subsequent payment would result in reducing the foreign currency exposure by approximately $37.5 million. We are unable to determine when payment will be received.

Since 2005, the Venezuelan government has had exchange controls that fix the exchange rate at 2.15 Bsf to one U.S. dollar and also prohibits us, as well as other companies, from converting the Bsf into U.S. dollars. Since that time, we have, in compliance with applicable regulations, submitted three separate requests to the Venezuelan government seeking permission to convert existing Bsf balances into U.S. dollars. All three requests were approved by the Venezuelan

36

government and we were permitted to remit U.S. dollars as dividends from the Venezuelan subsidiary to the U.S. based parent. These dividends reduced our exposure to currency devaluation in Venezuela.

On July 22, 2008, we submitted another application with the Venezuelan government requesting the approval to convert Bsf cash balances to U.S. dollars. When and if we receive approval from the Venezuelan government, our Venezuelan subsidiary will remit approximately $28.4 million as a dividend to its U.S. based parent as cash balances permit. While we have been successful in obtaining government approval for conversion of Bsf to U.S. dollars, there is no guarantee that future conversion to U.S. dollars will be permitted. In the event that conversion to U.S. dollars would be prohibited, then Bsf cash balances could increase and we would be exposed to increased risk of devaluation.

Past devaluation losses may not be reflective of the actual potential for future devaluation losses. Venezuela continues to operate under exchange controls and the Venezuelan Bsf exchange rate has remained fixed at 2.15 Bsf to one U.S. dollar since March 2005. The exact amount and timing of any future devaluations attributable to the Venezuelan Bsf exchange rate is uncertain. At September 30, 2009, we had $45.3 million in cash denominated in Bsf exposed to the risk of currency devaluation. Additionally, we have other current assets including accounts receivable exposed to currency devaluation.

While we are unable to predict future devaluation in Venezuela, if fiscal 2010 balance sheet components are similar to fiscal 2009 and if a 10 percent to 100 percent devaluation were to occur, we could experience potential currency devaluation losses ranging from approximately $6.6 million to $35.7 million.

We are not operating in any country that is currently considered highly inflationary, which is defined as cumulative inflation rates

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exceeding 100 percent in the most recent three-year period. The economy in Venezuela has not been considered to be highly inflationary in the past five years, but it is reasonably possible that Venezuela may be considered highly inflationary again at some time in the future. 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.

Credit Risk Typically, contract drilling revenues are recognized as services are performed. In U.S. generally accepted accounting principles, one of the basic revenue recognition criteria is that collectability of the revenue is reasonably assured. Our revenue in Venezuela is from providing drilling services to 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 is no longer met as collectability of revenue is not reasonably assured, primarily due to the uncertainty of the timing of collectability as discussed further below. As a result of this change, $57.9 million of revenue was not recorded in the International Land segment during fiscal 2009. Since the beginning of the second quarter of fiscal 2009, approximately $69.3 million (U.S. dollars and U.S. currency equivalent) was collected from PDVSA of which $61.4 million was applicable to the accounts receivable balance at the end of the first fiscal quarter of 2009. As of September 30, 2009, the Consolidated Balance Sheet reflected accounts receivable from PDVSA of $26.6 million. Subsequent to the end of fiscal 2009, additional payments of approximately $20.8 million (U.S. dollars and U.S. currency equivalent) were received through November 19, 2009. Approximately 73 percent of this corresponds to accounts receivable at the end of the first fiscal quarter and the remainder to invoices

38

issued for work performed after the first fiscal quarter of 2009. We do not have enough information to conclude that the remaining receivable balance is not probable of collection. However, there is uncertainty regarding the timing of the collection due to the current political, economic and social instability in Venezuela, the dependence by Venezuela on oil to largely support its economy and the failure of PDVSA to pay many service companies working in Venezuela. The collection of receivables from PDVSA has historically been more difficult and slower than that of other customers in international countries in which we have drilling operations due to PDVSA policies and procedures.

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.

In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. The deterioration in the credit and capital markets in 2008 and the apparent slow, cautious recovery since, could make it

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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. We have reduced the impact of fluctuations in interest rates by maintaining a portion of our debt portfolio in fixed-rate debt. At September 30, 2009, the amount of our fixed-rate debt was approximately 83 percent of total debt.

The following tables provide information as of September 30, 2009 and 2008 about our interest rate risk sensitive instruments:

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%

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INTEREST RATE RISK AS OF SEPTEMBER 30, 2008 (dollars in thousands)

		2009			2010		2011		2012			2013		After 2013			Total			Fair Value 9/30/08
Fixed Rate Debt			$25,000		$	—		$         —		$75,000		$	—		$75,000			$175,000			$198,000
	Average Interest Rate		5.9	%		—		—		6.5	%		—		6.6	%		6.5	%
Variable Rate Debt			$       —		$	—		$325,000		$       —		$	—		$       —			$325,000			$325,000
	Average Interest Rate (a)		—			—		—		—			—		—			(a	)

(b)  Advances bear interest rates ranging from 2.84% to 4.06%

Equity Price Risk On September 30, 2009, we had a portfolio of securities with a total fair value of $359.5 million. The total fair value of the portfolio of securities was $384.0 million at September 30, 2008. Our investments in Atwood Oceanics, Inc. and Schlumberger, Ltd. made up 95 percent of the portfolio's fair value at September 30, 2009. Although we sold portions of our positions in Schlumberger in 2008 and 2007, 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 19, 2009, the total fair value of the portfolio of securities had increased to approximately $387.3 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, 2009 and 2008, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2009. 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2009, 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, 2009, 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, 2009 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
November 24, 2009

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Consolidated Statements of Income

Years Ended September 30,		2009			2008			2007
		(in thousands, except per share amounts)
OPERATING REVENUES
	Drilling – U.S. Land		$1,441,164			$1,542,038			$1,174,956
	Drilling – Offshore		204,702			154,452			123,148
	Drilling – International Land		237,397			328,244			320,283
	Other		10,775			11,809			11,271
			1,894,038			2,036,543			1,629,658
OPERATING COSTS AND EXPENSES
	Operating costs, excluding depreciation		1,011,558			1,086,666			862,254
	Depreciation		236,437			210,766			146,042
	Research and development		9,671			1,833			—
	Acquired in-process research and development		—			11,129			—
	General and administrative		59,413			57,059			47,401
	Gain from involuntary conversion of long-lived assets		(541	)		(10,236	)		(16,661	)
	Income from asset sales		(6,032	)		(13,490	)		(41,697	)
			1,310,506			1,343,727			997,339
Operating income			583,532			692,816			632,319
Other income (expense)
	Interest and dividend income		4,965			5,038			4,234
	Interest expense		(13,490	)		(18,689	)		(10,126	)
	Gain on sale of investment securities		—			21,994			65,458
	Other		808			(1,230	)		(1,532	)
			(7,717	)		7,113			58,034
Income before income taxes and equity in income of affiliate			575,815			699,929			690,353
Income tax provision			232,381			255,557			250,984
Equity in income of affiliate net of income taxes			10,111			17,366			9,892
NET INCOME			$    353,545			$   461,738			$   449,261
Earnings per common share:
	Basic		$           3.36			$          4.43			$          4.35
	Diluted		$           3.32			$          4.34			$          4.27
Average common shares outstanding (in thousands):
	Basic		105,364			104,284			103,338
	Diluted		106,650			106,424			105,128

The accompanying notes are an integral part of these statements.

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Consolidated Balance Sheets

ASSETS

September 30,			2009		2008
				(in thousands)
CURRENT ASSETS:
	Cash and cash equivalents			$    141,486		$   121,513
	Short-term investments			12,500		—
	Accounts receivable, less reserve of $659 in 2009 and $1,331 in 2008			246,790		462,833
	Inventories			44,723		33,098
	Deferred income taxes			12,861		21,939
	Assets held for sale			1,023		—
	Prepaid expenses and other			63,549		51,264
		Total current assets		522,932		690,647
INVESTMENTS				356,404		199,266
PROPERTY, PLANT AND EQUIPMENT, at cost:
	Contract drilling equipment			4,076,371		3,263,818
	Construction in progress			232,055		279,422
	Real estate properties			61,114		60,811
	Other			176,797		150,200
				4,546,337		3,754,251
	Less-Accumulated depreciation			1,280,430		1,072,000
		Net property, plant and equipment		3,265,907		2,682,251
OTHER ASSETS				15,781		15,881
TOTAL ASSETS				$4,161,024		$3,588,045

The accompanying notes are an integral part of these statements.

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LIABILITIES AND SHAREHOLDERS' EQUITY

September 30,			2009		2008
				(in thousands, except share data and per share amounts)
CURRENT LIABILITIES:
	Accounts payable			$      70,218		$   153,851
	Accrued liabilities			126,688		128,373
	Short-term debt			105,000		—
	Notes payable			—		1,733
	Long-term debt due within one year			—		25,000
		Total current liabilities		301,906		308,957
NONCURRENT LIABILITIES:
	Long-term debt			420,000		475,000
	Deferred income taxes			681,542		479,963
	Other			74,567		58,651
		Total noncurrent liabilities		1,176,109		1,013,614
SHAREHOLDERS' EQUITY:
	Common stock, $.10 par value, 160,000,000 shares authorized, 107,057,904 shares issued as of September 30, 2009 and 2008 and 105,486,218 and 105,222,421 shares outstanding as of September 30, 2009 and 2008, respectively			10,706		10,706
	Preferred stock, no par value, 1,000,000 shares authorized, no shares issued			—		—
	Additional paid-in capital			176,039		169,497
	Retained earnings			2,414,942		2,082,518
	Accumulated other comprehensive income			112,451		38,407
				2,714,138		2,301,128
	Less treasury stock, 1,571,686 shares in 2009 and 1,835,483 shares in 2008, at cost			31,129		35,654
		Total shareholders' equity		2,683,009		2,265,474
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY				$4,161,024		$3,588,045

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, 2006				107,058		$10,706		$135,500			$1,215,127			$69,645			3,189			$(49,086	)		$1,381,892
Comprehensive Income:
	Net income										449,261												449,261
	Other comprehensive income (loss):
		Unrealized losses on available-for-sale securities, net												(2,930	)								(2,930	)
		Minimum pension liability adjustment, net												9,170									9,170
	Total other comprehensive gain																						6,240
Total comprehensive income																							455,501
Cash dividends ($.18 per share)											(18,622	)											(18,622	)
Exercise of stock options								(1,156	)								(298	)		4,958			3,802
Tax benefit of stock-based awards, including excess tax benefits of $1.5 million								1,792															1,792
Repurchase of common stock																	682			(15,859	)		(15,859	)
Stock-based compensation								7,010															7,010
Balance, September 30, 2007				107,058		10,706		143,146			1,645,766			75,885			3,573			(59,987	)		1,815,516
Adjustment to initially apply ASC 740-10-30-5											(5,048	)											(5,048	)
Comprehensive Income:
	Net income										461,738												461,738
	Other comprehensive loss:
		Unrealized losses on available-for-sale securities, net												(30,863	)								(30,863	)
		Amortization of net periodic benefit costs – net of actuarial gain												(6,615	)								(6,615	)
	Total other comprehensive loss																						(37,478	)
Total comprehensive income																							424,260
Capital adjustment of equity investee								1,669															1,669
Cash dividends ($.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 $24.9 million								27,022															27,022
Treasury stock issued for vested restricted stock								(56	)								(3	)		56			—
Stock-based compensation								7,456															7,456
Balance, September 30, 2008				107,058		10,706		169,497			2,082,518			38,407			1,835			(35,654	)		2,265,474
Comprehensive Income:
	Net income										353,545												353,545
	Other comprehensive loss:
		Unrealized gains on available- for-sale securities, net												88,519									88,519
		Amortization of net periodic benefit costs – net of actuarial gain												(14,475	)								(14,475	)
	Total other comprehensive gain																						74,044
Total comprehensive income																							427,589
Capital adjustment of equity investee								174															174
Cash dividends ($.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

The accompanying notes are an integral part of these statements.

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Consolidated Statements of Cash Flows

Years Ended September 30,					2009			2008			2007
						(in thousands)
OPERATING ACTIVITIES:
	Net income					$     353,545			$    461,738			$    449,261
	Adjustments to reconcile net income     to net cash provided by operating activities:
		Depreciation				236,437			210,766			146,042
		Provision for (recovery of) bad debt				(645	)		704			1,030
		Equity in income of affiliate before income taxes				(16,308	)		(28,009	)		(15,954	)
		Stock-based compensation				8,348			7,456			7,010
		Gain on sale of investment securities				—			(21,864	)		(65,320	)
		Gain from involuntary conversion of long-lived assets				(541	)		(10,236	)		(16,661	)
		Income from asset sales				(6,032	)		(13,490	)		(41,697	)
		Acquired in-process research and development				—			11,129			—
		Deferred income tax expense				158,153			117,998			82,294
		Other				2			—			1,000
		Change in assets and liabilities:
			Accounts receivable			216,688			(127,992	)		(53,773	)
			Inventories			(11,625	)		(3,953	)		(2,980	)
			Prepaid expenses and other			(12,241	)		(25,602	)		(18,606	)
			Accounts payable			(28,640	)		(15,652	)		73,780
			Accrued liabilities			(1,261	)		28,214			5,299
			Deferred income taxes			6,648			11,593			6,107
			Other noncurrent liabilities			(5,209	)		8,028			4,235
				Net cash provided by operating activities		897,319			610,828			561,067
INVESTING ACTIVITIES:
	Capital expenditures					(880,753	)		(705,635	)		(894,214	)
	Acquisition of business, net of cash acquired					(16	)		(12,041	)		—
	Proceeds from asset sales					8,699			22,908			51,568
	Insurance proceeds from involuntary conversion					541			13,926			16,257
	Purchase of short-term investments					(12,500	)		—			—
	Proceeds from sale of investments					—			25,507			127,819
				Net cash used in investing activities		(884,029	)		(655,335	)		(698,570	)
FINANCING ACTIVITIES:
	Repurchase of common stock					—			—			(17,621	)
	Increase (decrease) in notes payable					(1,733	)		1,733			(3,721	)
	Decrease in long-term debt					(25,000	)		—			(25,000	)
	Proceeds from line of credit					3,840,000			3,550,000			1,490,000
	Payments on line of credit					(3,790,000	)		(3,495,000	)		(1,220,000	)
	Increase (decrease) in bank overdraft					2,038			—			(17,430	)
	Dividends paid					(21,111	)		(19,333	)		(18,638	)
	Proceeds from exercise of stock options					1,272			14,537			3,802
	Excess tax benefit from stock-based compensation					1,217			24,868			1,473
				Net cash provided by financing activities		6,683			76,805			192,865
Net increase in cash and cash equivalents						19,973			32,298			55,362
Cash and cash equivalents, beginning of period						121,513			89,215			33,853
Cash and cash equivalents, end of period						$     141,486			$    121,513			$    89,215

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.

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 $2.9 million and $1.6 million in fiscal 2009 and 2008, respectively, and gains of $1.0 million in fiscal 2007.

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 STANDARD

In June 2009, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 168, The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162 ("SFAS 168"). SFAS 168 replaced all previously issued accounting standards and establishes the FASB Accounting Standards Codification™ ("ASC") as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with U.S. GAAP. The new standard, ASC 105-10, was effective for all interim and annual periods ending after September 15, 2009. The ASC is not intended to change existing U.S. GAAP. The adoption of this pronouncement only resulted in changes to our financial statement disclosure references. As such, adoption of this pronouncement had no effect on our consolidated financial position, results of operations, or cash flows. All references to U.S. GAAP within this report on Form 10-K are updated to reflect the new codification.

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 for moving funds to, and several "zero-balance" disbursement accounts for funding

48

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 $13.9 million and $13.3 million at September 30, 2009 and 2008, 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, 2009, $2.0 million is from the initial capitalization of the captive company and management has elected to restrict an additional $10.9 million. The remaining restricted cash consists of $1.0 million held in escrow in conjunction with the 2008 acquisition of TerraVici Drilling Solutions. 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,	2009		2008
Other current assets		$11,890		$10,274
Other assets		$  2,000		$  3,012

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.

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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.

During fiscal 2009, we adopted the disclosure provisions contained in ASC 815 that provides companies with requirements for enhanced disclosures about derivative instruments and hedging activities to enable investors to better understand their effects on a company's financial position, financial performance and cash flows. For further information regarding the derivative instruments including our disclosures of our interest rate swap, refer to Note 2, Debt, and Note 7, Financial Instruments and Fair Value Measurement, of these Consolidated Financial Statements.

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 $5.3 million, $13.3 million and $4.1 million for fiscal 2009, 2008 and 2007, 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.

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 2009, 2008 and 2007 was $6.6 million, $4.7 million, and $9.4 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 in accordance with ASC 360-10. 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 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 and rig utilization. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on

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each rig's 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.

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. 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,	2009		2008		2007
		(in thousands)
Minimum rents		$8,803		$9,469		$8,873
Overage and percentage rents		$1,414		$1,582		$1,474

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At September 30, 2009, minimum future rental income to be received on noncancelable operating leases was as follows (in thousands):

Fiscal Year		Amount
2010			$  7,751
2011			6,206
2012			4,491
2013			3,151
2014			2,166
Thereafter			3,721
	Total		$27,486

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

At September 30, 2009 and 2008, the cost and accumulated depreciation for real estate properties were as follows (in thousands):

September 30,	2009			2008
Real estate properties		$61,114			$60,811
Accumulated depreciation		(37,786	)		(36,155	)
		$23,328			$24,656

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 740-10-30-5, Deferred Tax Expense (or Benefit), which was adopted effective October 1, 2007, and is more fully discussed in Note 3. 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 Consolidation Statements of Income.

On October 1, 2009, 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 recognize a realized income tax benefit associated with dividends or dividend equivalents paid on nonvested equity-classified employee share-based payment awards that is 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.

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EARNINGS PER SHARE

Basic earnings per share is based on the weighted-average number of common shares outstanding during the period. Diluted earnings per share includes the dilutive effect of stock options and 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.

NEW ACCOUNTING STANDARDS

In June 2008, the FASB issued guidance contained in ASC 260-10-45 to clarify 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 260-10-05, Earnings per Share. We will adopt ASC 260-10-45 on October 1, 2009. All prior-period earnings per share data presented will be adjusted retrospectively to conform to the provisions of ASC 260-10-45. We expect the impact, if any, of adopting ASC 260-10-45 to be immaterial on our prior period earnings per share.

ASC 820-10-65, Transition related to FASB Staff Position FAS157-2, delays the effective date for the disclosure requirements included in ASC 820-10 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually). ASC 820-10-65 will be adopted on October 1, 2009 and is not expected to have a material impact on our Consolidated Financial Statements.

ASC 715-20-65, Transition related to SFAS 132R-1, Employers' Disclosures about Postretirement Benefit Plan Assets, was issued by the FASB in December 2008. The new guidance requires employers of public and nonpublic companies to disclose 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 are effective for years ending after December 15, 2009. The disclosure requirements will be

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adopted for the year ended September 30, 2010, on a prospective basis. We do not expect the adoption to have a material impact on the Consolidated Financial Statements.

In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value (ASU 2009-05). This update provides 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. ASU 2009-05 is effective for reporting periods beginning after August 28, 2009, which means that it will be effective for our first quarter beginning October 1, 2009. We do not currently believe this update will have a material impact on the Consolidated Financial Statements.

NOTE 2 DEBT

At September 30, 2009 and 2008, we had $420 million and $475 million, respectively, in unsecured long-term debt outstanding at rates and maturities shown in the following table (in thousands):

		September 30,
		2009		2008
Unsecured intermediate debt issued August 15, 2002:
	Series B, due August 15, 2009, 5.91%		$          —		$  25,000
	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		—
	Due July 21, 2013, 6.10%		40,000		—
	Due July 21, 2014, 6.10%		40,000		—
	Due July 21, 2015, 6.10%		40,000		—
	Due July 21, 2016, 6.10%		40,000		—
Unsecured senior credit facility due December 18, 2011, .60%			70,000		325,000
			$420,000		$500,000
Less long-term debt due within one year			—		25,000
Long-term debt			$420,000		$475,000

The intermediate unsecured debt outstanding at September 30, 2009 matures over a period from August 2012 to August 2014 and carries a weighted-average interest rate of 6.5 percent, which is paid semi-annually. The terms require that we maintain a minimum ratio of debt to total capitalization. The debt is held by various entities, including $3 million held by a company affiliated with one of our Board members.

On July 21, 2009, we closed a private placement of senior unsecured fixed-rate notes that will mature July 2016 and received proceeds of $200 million. Interest on the notes will be 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 the third anniversary of the closing date. 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

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customary in unsecured debt arrangements for companies that are similar in size and credit quality. The $200 million of proceeds from this facility were used to reduce borrowings under the $400 million senior credit facility by $105 million and the remainder was used to fund capital expenditures and for other general corporate purposes.

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 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, 2009, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. At September 30, 2009, we had two letters of credit totaling $21.9 million under the facility and had $70 million borrowed against the facility with $308.1 million available to borrow. The advances bear an interest rate of 0.60 percent at September 30, 2009. Subsequent to September 30, 2009, the debt was reduced by $30 million and we had $338.1 million available to borrow.

We have an agreement with a multi-bank syndicate for a $105 million unsecured line of credit that will mature January 2010. We closed on the agreement on January 21, 2009. We committed to fully fund this facility for the entire term at a spread over 30 day LIBOR. The spread over LIBOR is determined according to the same scale of debt to total capitalization used in our $400 million facility which is described in the preceding paragraph. The spread over LIBOR for the new facility has increased to a range of 2 percent to 2.75 percent. At September 30, 2009, the spread on the borrowing was 2.25 percent over LIBOR. Simultaneous with the closing of this facility, we entered into an interest-rate swap with the same maturity and a notional amount of $105 million. We believe that the swap will act to fix the annualized interest rate of the facility at approximately 3.17 percent assuming the spread remains at 2.25 percent over LIBOR. The interest rate swap qualifies as a derivative and was not designated as a hedging instrument and, as such, we have not applied hedge accounting. At the end of an accounting period, the interest rate swap is recorded in the Consolidated Balance Sheet at fair value, either in other current assets or accrued liabilities, and any related gains or losses are recognized on our Consolidated Statement of Income within interest expense. The fair value of the interest rate swap liability at September 30, 2009 was $0.2 million and is included in accrued liabilities in the Consolidated Balance Sheet. Interest expense on the interest rate swap was $0.6 million during fiscal year 2009.

Financial covenants in both facilities 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. Both facilities contain 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, 2009, we were in compliance with all debt covenants.

Additionally, as of September 30, 2009, we had unsecured letters of credit totaling $3.2 million which were used to obtain surety bonds for international operations.

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At September 30, 2009, aggregate maturities of long-term debt are as follows (in thousands):

Years ending September 30,
2010	$          —
2011	—
2012	185,000
2013	40,000
2014	115,000
Thereafter	80,000
	$420,000

NOTE 3 INCOME TAXES

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

Years Ended September 30,		2009		2008			2007
			(in thousands)
Current:
	Federal		$  45,780		$  97,871			$125,169
	Foreign		19,559		28,875			31,552
	State		8,889		10,813			11,969
			74,228		137,559			168,690
Deferred:
	Federal		148,367		110,077			74,389
	Foreign		1,279		(1,467	)		1,528
	State		8,507		9,388			6,377
			158,153		117,998			82,294
Total provision			$232,381		$255,557			$250,984

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

Years Ended September 30,	2009		2008		2007
		(in thousands)
Domestic		$571,028		$627,344		$579,589
Foreign		4,787		72,585		110,764
		$575,815		$699,929		$690,353

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,			2009			2008
				(in thousands)
Deferred tax liabilities:
	Property, plant and equipment		$	597,647		$	440,081
	Available-for-sale securities			123,763			26,029
	Equity investments			—			37,079
	Other			(108	)		557
		Total deferred tax liabilities		721,302			503,746
Deferred tax assets:
	Pension reserves			12,901			4,187
	Self-insurance reserves			3,740			4,509
	Net operating loss and foreign tax credit carryforwards			48,107			43,495
	Financial accruals			32,042			32,901
	Other			3,939			4,124
		Total deferred tax assets		100,729			89,216
	Valuation allowance			48,107			43,495
		Net deferred tax assets		52,622			45,721
Net deferred tax liabilities			$	668,680		$	458,025

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

As of September 30, 2009, we had state and foreign net operating loss carryforwards for income tax purposes of $1.0 million and $13.8 million, respectively, and foreign tax credit carryforwards of approximately $43.3 million which will expire in years 2010 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,	2009			2008			2007
U.S. Federal income tax rate		35	%		35	%		35	%
Effect of foreign taxes		3			—			(1	)
State income taxes		2			2			2
Effective income tax rate		40	%		37	%		36	%

Effective October 1, 2007, we adopted ASC 740-10-30-5, Deferred Tax Expense (or Benefit), issued by the FASB in July 2006. The guidance clarifies the accounting for uncertainty in income taxes recognized in an entity's financial statements in accordance with ASC 740, Income Taxes, and prescribes 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 740-10-30-5, the impact of an uncertain income tax position must be

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recognized in the financial statements at the largest amount that is more likely than not 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. Additionally, guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition was provided in ASC 740-10-30-5. 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, 2009 and 2008, we had accrued interest and penalties of $1.7 million and $2.5 million, respectively.

A reconciliation of the change in our gross unrecognized tax benefits for the fiscal year ended September 30, 2009 and 2008 is as follows (in thousands):

September 30,	2009			2008
Unrecognized tax benefits at October 1,	$	5,692		$	4,628
Gross decreases – tax positions in prior periods		(731	)		—
Gross increases – current period effect of tax positions		283			1,064
Unrecognized tax benefits at September 30	$	5,244		$	5,692

As of September 30, 2009 and September 30, 2008, our liability for unrecognized tax benefits was $5.2 million and $5.7 million, respectively, which would affect the effective tax rate if recognized. The decrease in unrecognized tax benefits was mainly due to an effective settlement with the Argentinean tax authorities. The increase in unrecognized tax benefits was mainly due to the current period impact of tax positions taken in prior periods. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in our Consolidated Balance Sheets.

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 2005 through 2008. Audits in foreign jurisdictions are generally complete through fiscal year 2001.

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.

NOTE 4 SHAREHOLDERS' EQUITY

On September 30, 2009, we had 105,486,218 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

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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 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 5 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.

A summary of compensation cost for stock-based payment arrangements recognized in general and administrative expense in fiscal 2009, 2008 and 2007 is as follows (in thousands):

September 30,		2009		2008		2007
Compensation expense
	Stock options	$	6,899	$	6,210	$	5,643
	Restricted stock		1,449		1,246		1,367
		$	8,348	$	7,456	$	7,010

Benefits of tax deductions in excess of recognized compensation cost of $1.2 million, $24.9 million and $1.5 million are reported as a financing cash flow in the Consolidated Statements of Cash Flows for fiscal 2009, 2008 and 2007, respectively.

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

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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.

	2009			2008			2007
Risk-free interest rate		1.7	%		3.3	%		4.6	%
Expected stock volatility		43.3	%		31.1	%		35.9	%
Dividend yield		0.9	%		0.5	%		0.7	%
Expected term (in years)		5.8			4.8			5.5

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 $8.16, $10.81 and $10.36 per share for fiscal 2009, 2008 and 2007, respectively.

The following summary reflects the stock option activity for our common stock and related information for fiscal 2009, 2008 and 2007 (shares in thousands):

	2009				2008				2007
	Options			Weighted-Average Exercise Price	Options			Weighted-Average Exercise Price	Options			Weighted-Average Exercise Price
Outstanding at October 1,		4,819		$20.02		6,032		$15.80		5,619		$14.24
Granted		865		21.07		742		35.11		731		26.90
Exercised		(267	)	12.18		(1,845	)	11.87		(298	)	12.77
Forfeited/Expired		(16	)	26.91		(110	)	27.31		(20	)	28.57
Outstanding on September 30,		5,401		$20.55		4,819		$20.02		6,032		$15.80
Exercisable on September 30,		3,599		$17.42		3,206		$15.07		4,335		$12.70
Shares available to grant		1,656				2,511				3,231

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The following table summarizes information about stock options at September 30, 2009 (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
$9.4178 to $13.870		1,972	2.6	$12.25		1,972	$12.25
$16.0100 to $21.065		1,583	7.3	$18.75		753	$16.20
$26.8950 to $35.105		1,846	7.3	$30.97		874	$30.11
$9.4178 to $35.105		5,401	5.6	$20.55		3,599	$17.42

At September 30, 2009, the weighted-average remaining life of exercisable stock options was 4.2 years and the aggregate intrinsic value was $79.6 million with a weighted-average exercise price of $17.42 per share.

The number of options vested or expected to vest at September 30, 2009 was 5,359,244 with an aggregate intrinsic value of $102.0 million and a weighted-average exercise price of $20.50 per share.

As of September 30, 2009, the unrecognized compensation cost related to the stock options was $11.4 million. That cost is expected to be recognized over a weighted-average period of 2.4 years.

The total intrinsic value of options exercised during fiscal 2009, 2008 and 2007 was $4.9 million, $21.9, and $5.8 million, respectively.

The grant date fair value of shares vested during fiscal 2009, 2008 and 2007 was $6.3 million, $5.8 million and $5.4 million, respectively.

RESTRICTED STOCK

Restricted stock awards consist of our common stock and are time vested over three to five 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 closing price of our shares on the grant date. As of September 30, 2009, there was $2.2 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 1.5 years.

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A summary of the status of our restricted stock awards as of September 30, 2009, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2009, 2008 and 2007 is as follows (share amounts in thousands):

	2009				2008				2007
	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,		243		$29.92		240		$29.27		213	$29.57
Granted		—		—		22		35.11		27	26.90
Vested		(66	)	29.52		(3	)	16.01		—	—
Forfeited/Expired		—		—		(16	)	30.24		—	—
Outstanding on September 30,		177		$30.06		243		$29.92		240	$29.27

NOTE 6 EARNINGS PER SHARE

The computation of basic earnings per share is based on the weighted average number of common shares outstanding during the period. The computation of diluted earnings per share reflects the potential dilution that would occur if stock options were exercised and the dilution from the issuance of restricted shares, computed using the treasury stock method.

A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows:

September 30,		2009		2008		2007
		(in thousands)
Basic weighted-average shares			105,364		104,284		103,338
Effect of dilutive shares:
	Stock options and restricted stock		1,286		2,140		1,790
Diluted weighted-average shares			106,650		106,424		105,128

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:

	2009		2008		2007
	(in thousands, except per share amounts)
Shares excluded from calculation of diluted earnings per share		1,206		—		594
Weighted-average price per share	$	33.12	$	—	$	30.24

NOTE 7 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 those accounted for under the equity method of

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accounting at September 30, 2008 (see Note 1), 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, 2009	$129,183	$210,640	$—	$339,823
	September 30, 2008	$    7,685	$  67,867	$—	$  75,552

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 years ended September 30, 2008 and 2007, marketable equity available-for-sale securities with a fair value at the date of sale of $25.5 million and $73.4 million, respectively, were sold. For the same years, the gross realized gains on such sales of available-for-sale securities totaled $22.0 million and $65.5 million, respectively. We had no sales of marketable equity available-for-sale securities in fiscal 2009.

The investments in the limited partnerships carried at cost were approximately $12.4 million at September 30, 2009 and 2008. The estimated fair value of the limited partnerships was $19.7 million and $17.3 million at September 30, 2009 and 2008, respectively.

The assets held in a Non-qualified Supplemental Savings Plan are carried at fair market value which totaled $4.2 million and $6.4 million at September 30, 2009 and 2008, 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. Interest earned is included in interest and dividend income on the Consolidated Statements of Income. The carrying amount of the certificate of deposit approximates fair value.

During fiscal 2007, we liquidated our position in auction rate securities with no realized gains or losses. The proceeds of $48.3 million were included in the sale of investments under investing activities on the Consolidated Statements of Cash Flows. There were no purchases or sales of auction rate securities during fiscal 2009 and 2008.

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The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2009 and 2008.

During fiscal 2009, we adopted the disclosure requirements of ASC 820-10, Fair Value Measurements and Disclosures, issued by the FASB in September 2006, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements required under other accounting pronouncements, but does not change existing guidance for carrying instruments at fair value. ASC 820-10-65, issued in February 2008, allows a delayed application of ASC 820-10 for nonfinancial assets and liabilities until the first quarter of fiscal 2010. The FASB 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". Our adoption of the required portions of ASC 820-10 as of October 1, 2008 did not have a material impact on our financial position, results of operations and cash flows.

ASC 820-10 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, 2009, our financial assets utilizing Level 1 inputs include cash and cash equivalents, money market funds we have elected to classify as restricted assets and equity securities with active markets. For these items, quoted current market prices are readily available.

During fiscal 2009, we entered into an interest rate swap agreement with a $105 million notional amount to hedge the risk of changes in the interest rate associated with amounts outstanding under an unsecured line of credit that expires in January 2010. The fair value of the swap agreement was determined using Level 2 inputs. Level 2 inputs also include a bank certificate of deposit classified as a short-term investment and restricted cash 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, 2009:

		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	$141,486	$141,486	$     —	$—
	Short-term investments	12,500	—	12,500	—
	Investments	339,823	339,823	—	—
	Other current assets	11,890	10,866	1,024	—
	Other assets	2,000	2,000	—	—
Total assets measured at fair value		$507,699	$494,175	$13,524	$—
Liabilities:
	Accrued liabilities – interest rate swap	$      229	$         —	$     229	$—
Total liabilities measured at fair value		$      229	$         —	$     229	$—

The following information presents the supplemental fair value information about long-term fixed-rate debt at September 30, 2009 and September 30, 2008.

September 30,	2009		2008
		(in thousands)
Carrying value of long-term fixed-rate debt	$	350.0	$	175.0
Fair value of long-term fixed-rate debt	$	380.9	$	198.0

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.

ASC 825-10, Financial Instruments, permits choosing to measure certain financial assets and liabilities at fair value. We elected not to measure any assets or liabilities at fair value which were not being so measured prior to adopting ASC 820-10. Therefore, our adoption of ASC 820-10 as of October 1, 2008 did not have an impact on our financial position, results of operations or cash flows.

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NOTE 8 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of other comprehensive income for the years ended September 30, 2009, 2008 and 2007 were as follows (in thousands):

Years Ended September 30,	2009			2008			2007
Unrealized appreciation (depreciation) on securities, net of tax of $54,254, $(10,558) and $23,076	$	88,519		$	(17,227	)	$	37,654
Reclassification of realized gains in net income, net of tax of $0, $8,358 and $24,874		—			(13,636	)		(40,584	)
Minimum pension liability adjustments, net of tax of $5,621		—			—			9,170
Amortization of net periodic benefit costs – net of actuarial gain, net of tax of $(8,872) and $(4,054)		(14,475	)		(6,615	)		—
	$	74,044		$	(37,478	)	$	6,240

The components of accumulated other comprehensive income (loss) at September 30, 2009 and 2008, net of applicable tax effects, were as follows (in thousands):

September 30,	2009			2008
Unrealized appreciation on securities	$	130,597		$	42,078
Unrecognized actuarial gain (loss) and prior service cost		(18,146	)		(3,671	)
	$	112,451		$	38,407

NOTE 9 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.

The acquisition was accounted for using the purchase method of accounting. The purchase price was allocated to identifiable assets acquired and liabilities assumed based upon their estimated fair values, with the excess purchase price recorded as goodwill, none of which is tax deductible.

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The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Current assets	$	371
Fixed assets		4,257
Trademark		919
In-process research and development		11,129
Other noncurrent assets		280
Assets acquired		16,956
Liabilities assumed		(5,477	)
Net assets acquired		11,479
Goodwill		702
Acquisition cost	$	12,181

In-process research and development, or IPR&D, represents 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. Accordingly, the purchase price allocated to IPR&D was expensed immediately subsequent to the acquisition. This charge will be 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.

NOTE 10 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.

On September 30, 2007, we adopted the provisions of ASC 715, "Compensation—Retirement Benefits". This statement requires employers to a) recognize the funded status of a benefit plan, determined as the difference between the fair value of plan assets and the benefit obligation, as an asset or liability in the statement of financial position, b) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, c) measure the defined benefit plan assets and obligations as of the date of the employer's fiscal year-end, which we have used historically, and d) include additional disclosures in the notes to the financial statements about effects on net periodic benefit cost that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations.

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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, 2009 and a statement of the funded status as of September 30, 2009 and 2008 (in thousands):

		2009			2008
Accumulated Benefit Obligation ("ABO")		$	89,996		$	69,475
Changes in Projected Benefit Obligations ("PBO")
Projected benefit obligation at beginning of year		$	69,475		$	78,247
	Interest cost		4,988			4,919
	Actuarial gain (loss)		18,977			(8,975	)
	Benefits paid		(3,444	)		(4,716	)
Projected benefit obligation at end of year		$	89,996		$	69,475
Change in plan assets
Fair value of plan assets at beginning of year		$	59,605		$	74,877
	Actual return on plan assets		270			(13,662	)
	Employer contribution		750			3,106
	Benefits paid		(3,444	)		(4,716	)
Fair value of plan assets at end of year		$	57,181		$	59,605
Funded status of the plan at end of year		$	(32,815	)	$	(9,870	)

September 30,		2009			2008
Amounts Recognized in the Consolidated Balance Sheets (in thousands):
	Accrued liabilities	$	(40	)	$	(43	)
	Noncurrent liabilities-other		(32,775	)		(9,827	)
	Net amount recognized	$	(32,815	)	$	(9,870	)
The amounts recognized in Accumulated Other Comprehensive Income at September 30, 2009 and 2008, and not yet reflected in net periodic benefit cost, are as follows (in thousands):
Net actuarial gain (loss)		$	(29,267	)	$	(5,919	)
Prior service cost			(1	)		(1	)
Total		$	(29,268	)	$	(5,920	)

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 $2.1 million.

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

Years Ended September 30,	2009		2008		2007
Discount rate for net periodic benefit costs		7.25%		6.25%		5.75%
Discount rate for year-end obligations		5.42%		7.25%		6.25%
Expected return on plan assets		8.00%		8.00%		8.00%

We contributed $0.8 million to the Pension Plan in fiscal 2009 to fund distributions in lieu of liquidating pension assets. We estimate contributing at least $3.0 million in fiscal 2010 to meet the minimum contribution required by law and expect to make additional contributions to continue funding distributions. Subsequent to

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September 30, 2009, we contributed $1.0 million to the plan. With the unpredictability in the equity, debt and global markets, it is possible that contributions in fiscal 2010 will be greater than expected.

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

Years Ended September 30,	2009			2008			2007
Interest cost	$	4,988		$	4,919		$	4,865
Expected return on plan assets		(4,643	)		(5,990	)		(5,123	)
Amortization of prior service cost		(1	)		—			—
Recognized net actuarial loss		3			9			139
Net pension expense (benefit)	$	347		$	(1,062	)	$	(119	)

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,
2010		2011		2012		2013		2014		2015-2019	Total
$	3,789	$	3,977	$	4,439	$	4,824	$	5,041	$28,492	$	50,562

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.

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.

The target allocation for 2010 and the asset allocation for the Pension Plan at the end of fiscal 2009 and 2008, by asset category, follows:

		Target Allocation			Percentage of Plan Assets At September 30,
Asset Category		2010			2009			2008
U.S. equities			56	%		57	%		58	%
International equities			14			15			15
Fixed income			25			27			24
Real estate and other			5			1			3
	Total		100	%		100	%		100	%

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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 $14.3 million, $15.0 million, and $10.9 million in fiscal 2009, 2008 and 2007, respectively.

FOREIGN PLAN

We maintain an unfunded pension plan in one of our international subsidiaries. Pension expense was approximately $0.4 million, $0.4 million and $0.3 million in fiscal 2009, 2008 and 2007, respectively. The pension liability at September 30, 2009 and 2008 was $5.0 million.

NOTE 11 SUPPLEMENTAL BALANCE SHEET INFORMATION

The following reflects the activity in our reserve for bad debt for 2009, 2008 and 2007:

September 30,		2009			2008			2007
			(in thousands)
Reserve for bad debt:
	Balance at October 1,	$	1,331		$	2,957		$	2,007
	Provision for (recovery of) bad debt		(645	)		704			1,030
	Write-off of bad debt		(27	)		(2,330	)		(80	)
	Balance at September 30,	$	659		$	1,331		$	2,957

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

September 30,		2009		2008
			(in thousands)
Accounts receivable, net of reserve:
	Trade receivables	$	246,790	$	446,846
	Income tax		—		15,987
		$	246,790	$	462,833
Prepaid expenses and other:
	Prepaid value added tax	$	25,979	$	6,146
	Restricted cash		11,890		10,274
	Prepaid insurance		8,304		9,957
	Deferred mobilization		9,046		13,853
	Other		8,330		11,034
		$	63,549	$	51,264
Accrued liabilities:
	Taxes payable, other than income tax	$	49,613	$	42,884
	Accrued income taxes		15,992		—
	Self-insurance liabilities		2,626		3,696
	Payroll and employee benefits		13,827		44,525
	Accrued operating costs		2,150		16,500
	Deferred income		16,514		55
	Other		25,966		20,713
		$	126,688	$	128,373
Noncurrent liabilities:
	Pension and other non-qualified retirement plans	$	42,422	$	21,533
	Deferred income		7,024		839
	Uncertain tax positions including interest and penalties		6,298		8,163
	Self-insurance liabilities		6,103		6,557
	Deferred mobilization		5,164		12,000
	Other		7,556		9,559
		$	74,567	$	58,651

NOTE 12 SUPPLEMENTAL CASH FLOW INFORMATION

Years Ended September 30,	2009		2008		2007
		(in thousands)
Cash payments:
Interest paid, net of amounts capitalized	$	12,097	$	18,595	$	9,713
Income taxes paid	$	39,415	$	133,194	$	181,591

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Capital expenditures on the Consolidated Statements of Cash Flows for the years ended September 30, 2009, 2008 and 2007, does 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,	2009			2008			2007
		(in thousands)
Capital expenditures incurred	$	823,712		$	745,538		$	825,448
Additions incurred prior year but paid for in current year		66,857			26,954			95,720
Additions incurred but not paid for as of the end of the year		(9,816	)		(66,857	)		(26,954	)
Capital expenditures per Consolidated Statements of Cash Flows	$	880,753		$	705,635		$	894,214

NOTE 13 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. In Venezuela, we had $45.3 million in cash at September 30, 2009, as discussed below, along with other considerations in Note 14, Operations and Risks in Venezuela. 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. 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 substantially 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 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. The deterioration in the credit and capital markets during the past year could 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

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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, 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. We maintain certain other insurance coverage with deductibles as high as $5 million. 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 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 (White Eagle), 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. 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 have two insurance policies covering six offshore platform rigs for "named wind storm" 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. Rig property insurance coverage expires in May 2010. No insurance is carried against loss of earnings or business interruption. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, we are generally entitled to indemnification under our drilling contracts from this risk. Premiums paid to White Eagle by the drilling segments have been included in the drilling segment expenses but eliminated, along with the premium earned income, in the Consolidated Statements of Income.

INTERNATIONAL DRILLING OPERATIONS

International drilling operations are a significant contributor 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, 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.

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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. The economy in Venezuela has not been considered to be highly inflationary in the past four years. We have completed an analysis to determine if Venezuela should be accounted for as a highly inflationary economy under the provisions of ASC 830 during the current fiscal year. Based on current Securities and Exchange Commission guidance, we used two relevant inflation indexes for this analysis; the Consumer Price Index (CPI) and the National Consumer Price Index (NCPI). These indexes are published by the Central Bank of Venezuela and they are acceptable for calculation of the three year cumulative inflation rate. Using a blended NCPI and CPI rate for the three year period ended June 30, 2009, Venezuela would not be considered highly inflationary as the cumulative inflation rate is less than 100 percent. 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.

NOTE 14 OPERATIONS AND RISKS IN VENEZUELA

Typically, contract drilling revenues are recognized as services are performed. In U.S. generally accepted accounting principles, one of the basic revenue recognition criteria is that collectability of the revenue is reasonably assured. Our revenue in Venezuela is 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 is no longer met as collectability of revenue is not reasonably assured, primarily due to the uncertainty of the timing of collectability as discussed further below. As a result, $57.9 million of revenue was not recorded in the International Land segment during fiscal 2009. Revenue not recognized in 2009 will be recognized in future periods when cash is collected. Since the beginning of the second quarter of fiscal 2009, approximately $69.3 million (U.S. dollars and U.S. currency equivalent) was collected from PDVSA of which $61.4 million was applicable to accounts receivable at the end of the first quarter of fiscal 2009. As of September 30, 2009, the Consolidated Balance Sheets include accounts receivable from PDVSA of $26.6 million. Subsequent to the end of fiscal 2009, additional payments of approximately $20.8 million (U.S. dollars and U.S. currency equivalent) were received through November 24, 2009. Approximately 73 percent of this corresponds to accounts receivable at the end of the first quarter of fiscal 2009 and the remainder to invoices issued for work performed after the first quarter of fiscal 2009. We do not have enough information to conclude that the remaining receivable balance is not probable of collection. However, there continues to be uncertainty regarding the timing of the collection due to the current political, economic and social instability in Venezuela, the dependence by Venezuela on oil to largely support its economy and the failure of PDVSA to pay many service companies working in Venezuela. The collection of receivables from PDVSA has historically been more difficult and slower than that of other customers in international countries in which we have drilling operations due to PDVSA policies and procedures.

During the second quarter of fiscal 2009, we began discontinuing work for PDVSA as contracts expired. All of our eleven rigs were active in Venezuela during the first quarter of fiscal 2009. At the end of fiscal 2009, one rig remained active and has since become idle. At September 30, 2009, the net book value of long-lived assets in Venezuela was $71.6 million. We will continue to pursue future drilling opportunities in Venezuela, but

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do not expect to commit to new contracts until additional progress is made on unpaid invoices and converting local currency to U.S. dollars.

We have an agreement with PDVSA whereby 60 percent of our billings to PDVSA are in U.S. dollars and 40 percent are in the local currency, the bolivar fuerte. PDVSA has previously paid U.S. dollar invoices in Bsf which increases our exposure to foreign currency devaluation. In 2008, we received notification from PDVSA that exchange of those U.S. dollar invoices previously paid in Bsf would be made only when supporting documentation had been approved. The supporting documentation was delivered to PDVSA and is awaiting approval. The approval and subsequent payment would result in reducing the foreign currency exposure by approximately $37.5 million. We are unable to determine when payment will be received.

Since 2005, the Venezuelan government has had exchange controls that fix the exchange rate at 2.15 Bsf to one U.S. dollar and prohibits us, as well as other companies, from converting Bsf into U.S. dollars. Since that time, we have, in compliance with applicable regulations, submitted three separate requests to the Venezuelan government seeking permission to convert existing Bsf balances into U.S. dollars. All three requests were approved by the Venezuelan government and we were permitted to remit U.S. dollars as dividends from the Venezuelan subsidiary to the U.S. based parent. These dividends reduced our exposure to currency devaluation in Venezuela.

On July 22, 2008, we submitted another application with the Venezuela government requesting the approval to convert Bsf cash balances to U.S. dollars. When and if we receive approval from the Venezuelan government, our Venezuelan subsidiary will remit approximately $28.4 million as a dividend to its U.S. based parent as cash balances permit. While we have been successful in the past in obtaining government approval for conversion of Bsf to U.S. dollars, there is no guarantee that future conversion to U.S. dollars will be permitted. In the event that conversion to U.S. dollars would be prohibited, then Bsf cash balances could increase and we would be exposed to increased risk of devaluation.

Past devaluation losses may not be reflective of the potential for future devaluation losses. Venezuela continues to operate under exchange controls and the Venezuelan Bsf exchange rate has remained fixed at 2.15 Bsf to one U.S. dollar since March 2005. The exact amount and timing of any future devaluations attributable to the Venezuelan Bsf exchange rate is uncertain. At September 30, 2009, we had the equivalent of $45.3 million in cash denominated in Bsf's exposed to the risk of currency devaluation. Additionally, we have other current assets including accounts receivable exposed to currency devaluation.

While we are unable to predict the potential magnitude and timing of future devaluation in Venezuela, if current activity levels continue and if a 10 percent to 100 percent devaluation were to occur, we could experience potential currency devaluation losses ranging from approximately $6.6 million to $35.7 million.

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NOTE 15 COMMITMENTS AND CONTINGENCIES

COMMITMENTS

From March 2005 through November 2008, we entered into separate drilling contracts to build and operate a total of 140 new FlexRigs. Eight of these 140 new rigs were contracted for work in International Land operations and the remaining 132 in U.S. Land operations. The construction of the 140 rigs is estimated to cost $2.2 billion, most of which was spent by the end of fiscal 2009. 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, 2009, we had commitments outstanding of approximately $63.1 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, 2009 are as follows:

Fiscal Year		Amount (in thousands)
2010		$  8,165
2011		6,145
2012		3,050
2013		2,569
2014		2,271
Thereafter		9,982
	Total	$32,182

Total rent expense was $5.2 million, $4.2 million and $3.7 million for fiscal 2009, 2008 and 2007, respectively.

CONTINGENCIES

In August 2007, we experienced a fire on U.S. Land Rig 178, a 1,500 horsepower FlexRig2, when the well it was drilling had a blowout. There were no serious personal injuries although the drilling rig was lost. The rig was insured at a value that approximated replacement cost. At September 30, 2007, the net book value of the rig was removed from property, plant and equipment and a receivable from insurance was recorded, net of a $1.0 million insurance deductible. During fiscal 2008, gross insurance proceeds of approximately $8.7 million were received and a gain from involuntary conversion of approximately $5.0 million was recorded. During the first quarter of fiscal 2009, we settled the claim and received approximately $0.3 million as final

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payment. The proceeds were recorded as a gain from involuntary conversion in the Consolidated Statements of Income.

In August 2005, our Rig 201, which operates on an operator's tension-leg platform in the Gulf of Mexico, lost its entire derrick and suffered significant damage as a result of Hurricane Katrina. The rig was insured at a value that approximated replacement cost. Capital costs incurred in conjunction with rebuilding the rig were capitalized in fiscal 2007 and are being depreciated. Insurance proceeds received through fiscal 2008 totaled approximately $24.5 million with approximately $21.9 recorded as a gain from involuntary conversion of long-lived assets. During fiscal 2009, proceeds of approximately $0.2 million were received as final settlement and recorded as a gain from involuntary conversion.

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.

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 Venezuela, Colombia, Ecuador 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. 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.

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 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 each of the years ended September 30, 2009, 2008 and 2007 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
2009
Contract Drilling
	U.S. Land			$1,441,164		$   —			$1,441,164			$573,708			$187,259		$2,962,062		$703,073
	Offshore			204,702		—			204,702			55,293			11,872		129,465		17,584
	International     Land			237,397		—			237,397			(7,227	)		28,180		491,807		98,541
				1,883,263		—			1,883,263			621,774			227,311		3,583,334		819,198
Other				10,775		836			11,611			(7,032	)		9,126		577,690		4,514
				1,894,038		836			1,894,874			614,742			236,437		4,161,024		823,712
Eliminations				—		(836	)		(836	)		—			—		—		—
		Total		$1,894,038		$   —			$1,894,038			$614,742			$236,437		$4,161,024		$823,712
2008
Contract Drilling
	U.S. Land			$1,542,038		$—			$1,542,038			$605,718			$161,893		$2,660,232		$682,310
	Offshore			154,452		—			154,452			33,394			12,152		152,497		14,614
	International     Land			328,244		—			328,244			69,973			29,614		368,659		41,696
				2,024,734		—			2,024,734			709,085			203,659		3,181,388		738,620
Other				11,809		878			12,687			(7,996	)		7,107		406,657		6,918
				2,036,543		878			2,037,421			701,089			210,766		3,588,045		745,538
Eliminations				—		(878	)		(878	)		—			—		—		—
		Total		$2,036,543		$   —			$2,036,543			$701,089			$210,766		$3,588,045		$745,538
2007
Contract Drilling
	U.S. Land			$1,174,956		$   —			$1,174,956			$467,000			$106,107		$2,073,015		$762,501
	Offshore			123,148		—			123,148			22,081			10,687		124,014		25,418
	International     Land			320,283		—			320,283			105,179			23,782		314,625		22,726
				1,618,387		—			1,618,387			594,260			140,576		2,511,654		810,645
Other				11,271		828			12,099			5,007			5,466		373,715		14,803
				1,629,658		828			1,630,486			599,267			146,042		2,885,369		825,448
Eliminations				—		(828	)		(828	)		—			—		—		—
	Total			$1,629,658		$   —			$1,629,658			$599,267			$146,042		$2,885,369		$825,448

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

Years Ended September 30,			2009			2008			2007
Segment operating income				$614,742			$701,089			$599,267
Income from asset sales				6,032			13,490			41,697
Gain from involuntary conversion of long-lived assets				541			10,236			16,661
Corporate general and administrative costs and     corporate depreciation				(37,783	)		(31,999	)		(25,306	)
	Operating income			583,532			692,816			632,319
Other income (expense)
	Interest and dividend income			4,965			5,038			4,234
	Interest expense			(13,490	)		(18,689	)		(10,126	)
	Gain on sale of investment securities			—			21,994			65,458
	Other			808			(1,230	)		(1,532	)
		Total unallocated amounts		(7,717	)		7,113			58,034
Income before income taxes and equity in income of affiliate				$575,815			$699,929			$690,353

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,			2009		2008		2007
Revenues
	United States			$1,613,940		$1,687,075		$1,292,636
	Venezuela			50,298		167,172		127,278
	Argentina			42,087		44,367		39,330
	Ecuador			52,250		55,100		93,903
	Colombia			77,322		42,439		26,849
	Other Foreign			58,141		40,390		49,662
		Total		$1,894,038		$2,036,543		$1,629,658
Long-Lived Assets
	United States			$2,879,222		$2,461,726		$1,951,907
	Venezuela			71,634		76,867		83,804
	Argentina			99,896		38,125		26,355
	Ecuador			26,022		25,560		45,120
	Colombia			62,942		41,889		10,061
	Other Foreign			126,191		38,084		35,369
		Total		$3,265,907		$2,682,251		$2,152,616

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

Revenues from one company doing business with the contract drilling business accounted for approximately 12.1 percent, 10.3 percent, and 5.5 percent of the total operating revenues during the years ended September 30, 2009, 2008 and 2007, respectively. Revenues from another company doing business with the

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contract drilling business accounted for approximately 9.9 percent, 3.4 percent, and 1.3 percent of total operating revenues during the years ended September 30, 2009, 2008 and 2007, respectively. Collectively, the receivables from these customers were approximately $53.0 million and $60.7 million at September 30, 2009 and 2008, respectively.

NOTE 17 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

(in thousands, except per share amounts)

2009	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
Operating revenues		$623,754		$520,300		$387,767		$362,217
Operating income		222,420		183,338		91,432		86,342
Net income		145,275		103,738		53,044		51,488
Basic net income per common share		1.38		.99		.50		.49
Diluted net income per common share		1.36		.98		.50		.48

2008	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
Operating revenues		$456,663		$473,644		$522,517		$583,719
Operating income		168,633		155,670		177,807		190,706
Net income		107,830		102,054		125,369		126,485
Basic net income per common share		1.04		.98		1.20		1.20
Diluted net income per common share		1.02		.96		1.18		1.18

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 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 $1.1 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 $0.8 million, $0.01 per share on a diluted basis.

In the first quarter of fiscal 2008, net income includes an after-tax gain from the involuntary conversion of long-lived assets of $3.1 million, $0.03 per share on a diluted basis.

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In the second quarter of fiscal 2008, net income includes an after-tax gain on the sale of available-for-sale securities of $3.3 million, $0.03 per share on a diluted basis and an after-tax gain from the sale of assets of $1.2 million, $0.01 per share on a diluted basis.

In the third quarter of fiscal 2008, net income includes an after-tax gain on the sale of available-for-sale securities of $10.0 million, $0.09 per share on a diluted basis, an after-tax gain from the sale of assets of $1.0 million, $0.01 per share on a diluted basis, and an after-tax gain from the involuntary conversion of long-lived assets of $3.5 million, $0.03 per share on a diluted basis. Included in net income for the third quarter of fiscal 2008 is an after-tax charge of $6.9 million, $0.07 per share on a diluted basis, from in-process research and development.

In the fourth quarter of fiscal 2008, net income includes an after-tax gain from the sale of assets of $5.8 million, $0.05 per share on a diluted basis. Included in net income for the fourth quarter of fiscal 2008 is after-tax equipment abandonments of $7.3 million, $0.07 per share on a diluted basis.

NOTE 18 SUBSEQUENT EVENTS

We have evaluated events and transactions through November 24, 2009, and have determined we have no recognized subsequent events and one nonrecognized subsequent event.

In September 2009, we accepted bids for the sale of one highly mobile rig in the U.S. Land segment. The net book value at September 30, 2009 was approximately $1.0 million and has been classified as "Assets held for sale" on our September 30, 2009 Balance Sheet. In October 2009, we sold U.S. Land Rig 147.

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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 Douglas E. Fears Executive Vice President and Chief Financial Officer Steven R. Mackey Executive Vice President, Secretary, and General Counsel John W. Lindsay Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. M. Alan Orr Executive Vice President, Engineering and Development of Helmerich & Payne International Drilling Co. Gordon K. Helm Vice President and Controller	Stockholders' Meeting The annual meeting of stockholders will be held on March 3, 2010. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 26, 2010. 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 19, 2009, there were 663 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 March 27, 2009. 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

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QuickLinks

Exhibit 13

EX-21

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 (Australia) Drilling Co. (Incorporated in Oklahoma)

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 Square Shopping Center, Inc. (Incorporated in Oklahoma)

Subsidiaries of Utica Square Shopping Center, Inc.

Fishercorp, Inc. (Incorporated in Oklahoma)

EX-23.1

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 report dated November 24, 2009, with respect to the consolidated financial statements of Helmerich & Payne, Inc., included in the 2009 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, 2009, with respect to the consolidated financial statements of Helmerich & Payne, Inc. incorporated herein by reference and our report dated November 24, 2009, with respect to the effectiveness of internal control over financial reporting of Helmerich & Payne, Inc., included herein.

Tulsa, Oklahoma

November 25, 2009

EX-31.1

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 25, 2009
	/s/ HANS HELMERICH Hans Helmerich President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

        I, Douglas E. Fears, 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 25, 2009
	/s/ DOUGLAS E. FEARS Douglas E. Fears Executive Vice President and Chief Financial Officer

EX-32

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, 2009 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 Douglas E. Fears, as Executive 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 25, 2009 /s/ DOUGLAS E. FEARS
Douglas E. Fears
Executive Vice President and
Chief Financial Officer
Date: November 25, 2009