HELMERICH & PAYNE INC (Form: 10-K, Received: 12/13/2005 17:25:56)

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Income for the Years Ended September 30, 2005, 2004 and 2003

Consolidated Balance Sheets at September 30, 2005 and 2004

Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2005, 2004 and 2003

Consolidated Statements of Cash Flows for the Years Ended September 30, 2005, 2004 and 2003

Notes to Consolidated Financial Statements

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

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2005 OR

[ ] 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				73-0679879
(State or other jurisdiction of incorporation or organization)				(I.R.S. employer identification no.)

1437 S. BOULDER AVE., SUITE 1400, TULSA, OKLAHOMA 74119-3623

(Address of principal executive offices) (Zip code)

Registrant’s telephone number, including area code (918) 742-5531

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

TITLE OF EACH CLASS				NAME OF EXCHANGE ON WHICH REGISTERED
Common Stock ($0.10 par value)				New York Stock Exchange
Common Stock Purchase Rights				New York Stock Exchange

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

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 [X] No [ ]

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. [ ]

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X] No [ ]

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

At March 31, 2005, the aggregate market value of the voting stock held by non-affiliates was $1,945,419,202.

Number of shares of common stock outstanding at December 2, 2005: 52,011,465.

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, 2005				Parts I and II
(2) Proxy Statement for Annual Meeting of Stockholders to be held March 1, 2006				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 7, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION ON PAGES 8 THROUGH 32 OF THE COMPANY’S ANNUAL REPORT. 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.

PART I

ITEM 1. BUSINESS

Helmerich & Payne, Inc. (the “Company”), was incorporated under the laws of the State of Delaware on February 3, 1940, and is successor to a business originally organized in 1920. The Company is primarily engaged in contract drilling of oil and gas wells for others. The contract drilling business accounts for almost all of the Company’s operating revenues. The Company is also engaged in the ownership, development, and operation of commercial real estate.

The Company is organized into two separate operating entities, contract drilling and real estate. Both businesses operate independently of the other through wholly owned subsidiaries. Operating decentralization is balanced by a centralized finance division, which handles all accounting, information technology, budgeting, insurance, cash management, and related activities.

The Company’s contract drilling business is composed of three business segments: U.S. land drilling, U.S. offshore platform drilling and international drilling. The Company’s U.S. land drilling is conducted primarily in Oklahoma, Texas, Wyoming, Colorado, and Louisiana, and offshore from platforms in the Gulf of Mexico and California. The Company also operated in seven international locations during fiscal 2005: Venezuela, Ecuador, Colombia, Argentina, Bolivia, Equatorial Guinea, and Hungary. In addition, the Company provided drilling consulting services for one customer in Russia.

The Company’s real estate investments are located in Tulsa, Oklahoma, where the Company maintains its executive offices.

Prior to October 1, 2002, the Company was engaged in the exploration, production and sale of crude oil and natural gas business (“exploration and production business”). During fiscal 2002, the Company transferred the assets and liabilities of its exploration and production business to its wholly owned subsidiary, Cimarex Energy Co. On September 30, 2002, the Company distributed the common stock of Cimarex Energy Co. to the Company’s stockholders and completed a merger of Key Production Company, Inc. with a subsidiary of Cimarex Energy Co. As a result of this transaction, Cimarex Energy Co. became a separate publicly-traded company that owned and operated the exploration and production business. The Company does not own any common stock of Cimarex Energy Co.

CONTRACT DRILLING

The Company believes that it is one of the major land and offshore platform drilling contractors in the western hemisphere. Operating principally in North and South America, the Company specializes in medium to deep drilling in major oil and gas producing basins of the United States and in drilling for oil and gas in international locations. In the United States, the Company draws its customers primarily from the major oil companies and the larger independents. In South America, the Company’s current customers include the Venezuelan state petroleum company and major international oil companies.

In fiscal 2005, the Company received approximately 59 percent of its consolidated operating revenues from the Company’s ten largest contract drilling customers. BP plc, ExxonMobil Corporation, and Petroleos de Venezuela S.A. (respectively, “BP”, “ExxonMobil” and “PDVSA”), including their affiliates, are the Company’s three largest contract drilling customers. The Company performs drilling services for BP and ExxonMobil on a world-wide basis and PDVSA in Venezuela. Revenues from drilling services performed for BP, ExxonMobil and PDVSA in fiscal 2005 accounted for approximately 11 percent, 9 percent and 8 percent, respectively, of the Company’s consolidated operating revenues for the same period.

The Company provides drilling rigs, equipment, personnel, and camps on a contract basis. These services are provided so that the Company’s 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 helicopter rig is one that can be disassembled into component part loads of approximately 4,000-20,000 pounds and transported to remote locations by helicopter, cargo plane, or other means. 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, the Company operates self-moving minimum-space platform drilling rigs and drilling rigs to be used on tension-leg platforms and spars. The minimum-space 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.

During fiscal 1998, the Company 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 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, the Company built and completed 12 new FlexRig2 rigs. During fiscal 2001, the Company announced that it would build an additional 25 new FlexRigs. These new rigs, known as “FlexRig3”, 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, the Company constructed seven more FlexRig3s at an approximate cost of $11.2 million each. Construction of these rigs was completed by March of 2004. All FlexRigs are available for work in the Company’s U.S. and international drilling operations.

During fiscal 2005 and the first quarter of fiscal 2006, the Company entered into separate drilling contracts with 12 exploration and production companies to build and operate a total of 50 new FlexRigs. Of the 50 FlexRigs, eight are FlexRig3s and 42 are FlexRig4s (described below). Each of the drilling contracts provides for a minimum fixed contract term of at least three years, with drilling services to be performed on a daywork contract basis. The FlexRig3 construction cost is approximately $14 million each and the FlexRig4 cost is approximately $11 million each. While the Company experienced an approximate 30-day construction schedule delay due to Hurricanes Katrina and Rita, approximately 30 FlexRigs should be completed during fiscal 2006 and the remainder by the end of fiscal 2007. This 50 rig new-build project represents the single largest rig construction project in the Company’s history.

While the new FlexRig3s are similar to the Company’s existing FlexRig3s, the FlexRig4s are designed to efficiently drill shallower 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 includes 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 will result in reduced environmental impact.

® FlexRig is a registered trademark of Helmerich & Payne, Inc.

The Company utilizes a lean manufacturing process in the construction of its FlexRigs. This approach minimizes the amount of equipment and supplies that must be inventoried. However, after experiencing delays resulting from Hurricanes Katrina and Rita, the Company will temporarily inventory increased amounts of equipment and supplies to reduce future delays.

The Company’s drilling contracts are obtained through competitive bidding or as a result of negotiations with customers, and sometimes cover multi-well and multi-year projects. Each drilling rig operates under a separate drilling contract. During fiscal 2005, all drilling services were performed on a “daywork” contract basis, under which the Company charges 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. The Company has previously performed contracts on a combination “footage” and “daywork” basis, under which the Company 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, the Company has previously accepted “turnkey” contracts under which the Company charges a fixed sum to deliver a hole to a stated depth and agrees to furnish services such as testing, coring, and casing the hole which are not normally done on a “footage” basis. “Turnkey” contracts entail varying degrees of risk greater than the usual “footage” contract. The Company did not accept any “footage” or “turnkey” contracts during fiscal 2005. The Company believes that under current market conditions “footage” and “turnkey” contract rates do not adequately compensate contractors for the added risks. The duration of the Company’s 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 the contractor 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 or sustained unacceptable performance, no early termination payment would be paid to the contractor.

Excluding the fixed term contracts covering the 50 FlexRig new-build project, the Company has 33 rigs under fixed term contracts as of the end of November 2005. While the duration for these current fixed-term contracts are for six month to three year periods, some fixed-term and well-to-well contracts are expected to be continued 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 the Company and the customer. In most instances contracts provide for additional payments for mobilization and demobilization.

U.S. LAND DRILLING

At the end of September, 2005 and 2004, the Company had 91 and 87, respectively, of its land rigs available for work in the United States. The total number of rigs owned at the end of the period increased by a net of four rigs, resulting from six rigs moving back from the Company’s international fleet during fiscal year 2005, and the sale of two conventional rigs in November of 2004. The Company’s U.S. land operations contributed approximately 66 percent of the Company’s consolidated operating revenues during fiscal 2005, compared with approximately 59 percent of consolidated operating revenues during fiscal 2004 and approximately 54 percent of consolidated operating revenues during fiscal 2003. Rig utilization in fiscal 2005 was approximately 94 percent, up from approximately 87 percent in fiscal 2004. The Company’s fleet of FlexRigs and highly mobile rigs maintained an average utilization of approximately 99 percent during fiscal 2005 while the Company’s conventional rigs had an average utilization rate of approximately 82 percent. At the close of fiscal 2005, 87 land rigs were working out of 91 available rigs.

U.S. OFFSHORE PLATFORM DRILLING

The Company’s offshore platform operations contributed approximately 11 percent of the Company’s consolidated operating revenues during fiscal 2005, compared with approximately 14 percent of consolidated operating revenues during fiscal 2004 and approximately 22 percent of consolidated operating revenues during fiscal 2003. Rig utilization in fiscal 2005 was approximately 53 percent, up from approximately 48 percent in fiscal 2004. At the end of this fiscal year, the Company had seven of its 11 offshore platform rigs (excluding Rig 201) under contract and continued to work under management contracts for two customer-owned rigs. Revenues from drilling services performed for the Company’s largest offshore platform drilling customer totaled approximately 73 percent of U.S. offshore platform revenues during fiscal 2005.

The Company’s offshore platform Rig 201 sustained significant damage from Hurricane Katrina. Specific equipment damage assessment has not been completed. The Company does not anticipate Rig 201 returning to service during fiscal 2006. The rig was insured at a value that approximated replacement cost. Excluding Rig 201, seven platform rigs are under contract as of the end of November 2005, and one additional rig is expected to be contracted for work commencing the second fiscal quarter of 2006.

INTERNATIONAL DRILLING

General

The Company’s international drilling operations began in 1958 with the acquisition of Sinclair Oil Company’s drilling rigs in Venezuela. Helmerich & Payne de Venezuela, C.A., a wholly owned subsidiary of the Company, is one of the leading drilling contractors in Venezuela. Beginning in 1972, with the introduction of its first helicopter rig, the Company expanded into other Latin American countries.

The Company’s international operations contributed approximately 22 percent of the Company’s consolidated operating revenues during fiscal 2005, compared with approximately 25 percent of consolidated operating revenues during fiscal 2004 and approximately 22 percent of consolidated operating revenues during fiscal 2003. Rig utilization in fiscal 2005 was 77 percent, up from 54 percent in fiscal 2004.

Venezuela

Venezuelan operations continue to be a significant part of the Company’s operations. During fiscal 2005, the Company moved a highly mobile rig to the United States, reducing the rig count to 12 in Venezuela. The Company worked for the Venezuelan state petroleum company, PDVSA, during fiscal 2005 and revenues from this work accounted for approximately 8 percent of the Company’s consolidated operating revenues during the fiscal year and approximately 38 percent of international operating revenues. Revenues generated from all Venezuelan drilling operations contributed approximately 8 percent of the Company’s consolidated operating revenues during 2005, compared with approximately 10 percent of consolidated operating revenues during fiscal 2004 and 6 percent of consolidated operating revenues during 2003. The Company had nine rigs working in Venezuela at the end of fiscal 2005.

The Company’s rig utilization rate in Venezuela has increased from approximately 65 percent during fiscal 2004 to approximately 72 percent in fiscal 2005. The Company has contracted to return one idle rig back to work during the second quarter of fiscal 2006. At this time, the Company is unable to predict future fluctuations in its utilization rates.

Ecuador

At the end of fiscal 2005, the Company owned eight rigs in Ecuador. The Company’s utilization rate was approximately 97 percent during fiscal 2005, up from approximately 74 percent in fiscal 2004. Revenues generated by Ecuadorian drilling operations contributed approximately 8 percent of the Company’s consolidated operating revenues during fiscal 2005, as compared with approximately 7 percent of consolidated operating revenues during fiscal 2004 and approximately 10 percent of consolidated operating revenues during fiscal 2003. Revenues from drilling services performed for the Company’s largest customer in Ecuador totaled approximately 3 percent of consolidated operating revenues and approximately 13 percent of international operating revenues during fiscal 2005. The Ecuadorian drilling contracts are primarily with large international oil companies.

Colombia

During fiscal 2005, the Company owned two rigs in Colombia. The Company’s utilization rate in Colombia was approximately 87 percent during fiscal 2005, up from approximately 13 percent in fiscal 2004. The revenues generated by Colombian drilling operations contributed approximately 2 percent of the Company’s consolidated operating revenues in fiscal 2005, as compared with approximately 1 percent of consolidated operating revenues during fiscal 2004 and fiscal 2003. At the end of fiscal 2005, the Company was operating two rigs in Colombia.

Other Locations

In addition to its operations in Venezuela, Ecuador and Colombia, at the end of fiscal 2005, the Company owned two rigs in Bolivia, and two rigs in Argentina. During fiscal 2005, one rig was moved to the United States from Hungary.

At the end of November 2005, two rigs were working in Argentina with an additional rig moving to Argentina from the United States. This rig is under contract and expected to begin work during the second quarter of fiscal 2006. One rig has moved from Bolivia to Chile and started drilling operations, and one rig is under contract in Bolivia. It is expected to begin work during the second quarter of fiscal 2006.

During fiscal 2005, the Company continued operations under a management contract for a customer-owned platform rig located offshore Equatorial Guinea. Also, during the fiscal year, the Company completed a drilling consulting services contract in Russia. The Company continues to pursue opportunities in Russia.

REAL ESTATE OPERATIONS

The Company’s real estate operations are conducted exclusively within the metropolitan area of Tulsa, Oklahoma. Its major holding is Utica Square Shopping Center, consisting of 15 separate buildings, with parking and other common facilities covering an area of approximately 30 acres. Utica Square contains approximately 441,588 usable square feet, composed of retail space of 379,018 usable square feet, office space of 38,785 usable square feet, storage space of 6,600 usable square feet and common area space of 17,185 usable square feet. The Company’s real estate operations occupy approximately 4,140 square feet of general office and storage space within the shopping center. Occupancy in the shopping center was approximately 91 percent in fiscal 2005 and fiscal 2004.

At the end of the 2005 fiscal year, the Company owned 11 of a total of 73 units in The Yorktown, a 16-story luxury residential condominium with approximately 150,940 square feet of living area located on a six-acre tract adjacent to Utica Square Shopping Center. Nine of the Company’s units are currently leased.

The Company owns and leases to third parties multi-tenant warehouse space. Three warehouses known as Space Center, each containing approximately 165,000 square feet of net leasable space, are situated in the southeast part of Tulsa at the intersection of two major limited-access highways. Present occupancy is approximately 89 percent, which is up from approximately 82 percent one year ago. The increase in occupancy is due to the

addition of three new tenants. The Company also owns approximately 1.5 acres of undeveloped land lying adjacent to such warehouses.

Southpark is an undeveloped tract of land located in a high growth area of southeast Tulsa and is suitable for mixed commercial and light industrial use. At the end of fiscal 2005, the Company owned approximately 218 acres in Southpark consisting of approximately 205 acres of undeveloped real estate and approximately 13 acres of multi-tenant warehouse area. The warehouse area is known as Space Center East and consists of two warehouses, one containing approximately 90,000 square feet and the other containing approximately 112,500 square feet. Occupancy increased to approximately 89 percent in 2005 from approximately 82 percent in fiscal 2004 due to the addition of two new tenants. The Company believes that a high quality office park, with peripheral commercial, office/warehouse, and hotel sites, is the best development use for the remaining land. The Company has contracted with a professional engineering and planning firm to prepare a topographic survey and preliminary site engineering plan to aid in the possible future development of Southpark.

The Company owns a five-building complex called Tandem Business Park. The property is located adjacent to and east of the Space Center East facility and contains approximately six acres, with approximately 88,084 square feet of office/warehouse space. Occupancy has increased from approximately 69 percent in 2004 to approximately 76 percent during fiscal 2005 due to the addition of three tenants. The Company also owns a 12-building complex, consisting of approximately 204,600 square feet of office/warehouse space, called Tulsa Business Park. The property is located south and east of the Space Center facility, separated by a city street, and contains approximately 12 acres. During fiscal 2005, occupancy has decreased from approximately 81 percent to approximately 69 percent due to the loss of one tenant.

The Company owns two service center properties located adjacent to arterial streets in south central Tulsa. The first, called Maxim Center, consists of one office/warehouse building containing approximately 40,800 square feet and is located on approximately 2.5 acres. During fiscal 2005, occupancy has decreased to approximately 56 percent from approximately 94 percent due to the loss of one large tenant. The second, called Maxim Place, consists of one office/warehouse building containing approximately 33,750 square feet and is located on approximately 2.25 acres. During fiscal 2005, occupancy has increased from approximately 44 percent to approximately 63 percent with the addition of one new tenant. The Company’s offsite disaster recovery center occupies approximately 3,517 square feet of office and computer equipment space in this property.

During fiscal 2005, the Company completed the demolition and site reclamation of its former headquarters building. No development plans for the site are pending.

FINANCIAL

Information relating to revenues, total assets and operating income or loss by business segments may be found on pages 58 through 62 of the Company’s Annual Report.

EMPLOYEES

The Company had 3,615 employees within the United States (six of which were part-time employees) and 1,186 employees in international operations as of September 30, 2005.

AVAILABLE INFORMATION

Information relating to the Company’s internet address and the Company’s SEC filings may be found on page 64 of the Company’s Annual Report.

RISK FACTORS

In addition to the risk factors discussed elsewhere in this Report, the Company cautions that the following “Risk Factors” could affect its actual results in the future.

Competition

Competition in the Contract Drilling Business

The contract drilling business is highly competitive. Competition in contract drilling involves such factors as price, rig availability, efficiency, condition 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, the Company has been successful in establishing long-term relationships with certain customers which have allowed the Company to secure drilling work even though the Company may not have been the lowest bidder for such work. The Company has continued to attempt to differentiate its services based upon its engineering design expertise, operational efficiency, and 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 the Company’s competitors could negatively affect the Company’s ability to differentiate its services.

Competition in the Real Estate Business

The Company has numerous competitors in the multi-tenant leasing business. The size and financial capacity of these competitors range from one property sole proprietors to large international corporations. The primary competitive factors include price, location, and configuration of space. The Company’s competitive position is enhanced by the location of its properties, its financial capability and the long-term ownership of its properties. However, many competitors have financial resources greater than the Company and have more contemporary facilities. Also, current economic conditions have encouraged prospective tenants to construct owner-occupied buildings rather than lease third party space.

2. Operating and Rig Construction Risks

The drilling operations of the Company 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. The Company’s offshore platform 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.

The Company’s new-build rig assembly facility is located near the Houston, Texas ship channel. Also, certain of the Company’s fabricators and other vendors are located in the Gulf Coast region. Due to their location, these facilities are exposed to potentially greater hurricane damage.

3. Fixed Term Contract Risk

Fixed term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to the Company 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 or sustained unacceptable performance by the Company, no early termination payment would be paid to the Company.

4. Indemnification and Insurance Coverage

The Company has insurance coverage for comprehensive general liability, public liability, automobile liability, worker’s compensation, employer’s liability, and property damage. Generally, deductibles range from $1 million or $2 million per occurrence, depending on whether a claim occurs inside or outside of the United States. The Company maintains certain other insurance coverages with $5 million deductibles. Insurance is purchased over these deductibles to limit the Company’s exposure to catastrophic events. In fiscal 2005, the Company obtained property insurance coverage for 85 percent of the aggregate estimated replacement cost of its land rigs in excess of a $1 million deductible. The Company self-insured the remaining 15 percent of such land rig value. No insurance is carried against loss of earnings or business interruption. The Company is unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, the Company is generally indemnified under its drilling contracts from this risk.

The Company retains a significant portion of its expected losses under its worker’s compensation, general, and automobile liability programs. The Company records estimates for incurred outstanding liabilities for unresolved 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 the Company believes 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.

The majority of the Company’s insurance coverage has been purchased through fiscal 2006. Multiple hurricanes in the Gulf of Mexico during August and September had a severe impact on the availability and price of the Company’s rig property insurance coverage for 2006. As a result, the Company was able to place only 85 percent of its rig property coverage excess of a $1 million per occurrence deductible. In addition, the Company could share in losses up to a maximum of $5 million should loss levels exceed a set percentage of excess property premium. No assurance can be given that all or a portion of the Company’s coverage will not be cancelled during fiscal 2006 or that insurance coverage will continue to be available at rates considered reasonable. No assurance can be given that the Company’s insurance and indemnification arrangements will adequately protect it against all liabilities that could result from the hazards of its drilling operations. Incurring a liability for which the Company is not fully insured or indemnified could materially affect the Company’s results of operations.

5. Availability of Equipment and Supplies

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.

6. Volatility of Oil and Gas Prices

The Company’s operations can be materially affected by low oil and gas prices. The Company believes 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 the Company’s 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 the Company’s services could have a material and adverse effect on the Company.

7. International Uncertainties and Local Laws

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 the Company’s operations or on the ability of the Company to continue operations in certain areas.

Because of the impact of local laws, the Company’s future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which the Company holds only a minority interest, or pursuant to arrangements under which the Company conducts operations under contract to local entities. While the Company believes that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on the Company’s operations or revenues, there can be no assurance that the Company will in all cases be able to structure or restructure its operations to conform to local law (or the administration thereof) on terms acceptable to the Company.

Although the Company attempts to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2005, approximately 22 percent of the Company’s consolidated operating revenues were generated from the international contract drilling business. Approximately 85 percent of the international operating revenues were from operations in South America and approximately 84 percent of South American operating revenues were from Venezuela and Ecuador.

8. Currency Risk

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 frequently requesting that a greater proportion of these payments be made in local currencies. Based upon current information, the Company believes that exposure to potential losses from currency devaluation is minimal in Colombia, Ecuador, Bolivia, and Equatorial Guinea. In those countries, all receivables and payments are currently in U.S. dollars. Cash balances are kept at a minimum which assists in reducing exposure.

Argentina

In 2002, Argentina suffered a 60 percent devaluation of the peso. As a consequence, the Company secured agreements with its customers that limited the portion of the accounts receivable that was paid in pesos with the balance of such accounts receivable paid in U.S. dollars. The Company experienced minimal Argentine currency losses in fiscal 2005.

Venezuela

The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. In Venezuela, approximately 40 percent of the Company’s invoice billings are in U.S. dollars and 60 percent are in the local currency, the bolivar. The significance of this arrangement is that even though the dollar-based invoices may be paid in bolivares, the Company, historically, has usually been able to convert the bolivares into U.S. dollars in a timely manner and thus avoid, in large measure, devaluation losses pertaining to the dollar-based invoices. However, this arrangement is effective only in the absence of exchange controls. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars through the Central Bank.

As part of the exchange controls regulation, the Venezuelan government provided a mechanism by which companies could request conversion of bolivares into U.S. dollars. In compliance with such regulations, the Company, in October of 2003, submitted a request to the Venezuelan government seeking permission to dividend earnings, which would convert 14 billion bolivares into U.S. dollars. In January 2004, the Venezuelan government approved the Company’s request to convert bolivar cash balances to U.S. dollars and allowed the remittance of $8.8 million U.S. dollars as dividends to the U.S. based parent. As a consequence, the Company’s exposure to currency devaluation was reduced by this amount.

As stated above, the Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. As a result of a 12 percent devaluation of the bolivar during fiscal 2005, the Company experienced total devaluation losses of $0.6 million during that same period.

These devaluation losses may not be reflective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2006 activity levels are similar to fiscal 2005, and if a 10 percent to 20 percent devaluation were to occur, the Company could experience potential currency devaluation losses ranging from approximately $1.6 million to $2.9 million.

In late August 2003, the Venezuelan state petroleum company agreed, on a prospective basis, to pay a portion of the Company’s dollar-based invoices in U.S. dollars. Were this agreement to end, the Company would again receive these payments in bolivares and thus increase bolivar cash balances and exposure to devaluation.

On September 28, 2005, the Company made application with the Venezuelan government requesting the approval to convert bolivar cash balances to U.S. dollars. Upon approval from the Venezuelan government, the Company’s Venezuelan subsidiary will remit those dollars as a dividend to its U.S. based parent, thus reducing the Company’s exposure to currency devaluation.

9. Governmental Instability in Venezuela

Venezuela has a history of governmental instability. In the event that extended labor strikes or turmoil occurs, the Company could experience shortages in material and supplies necessary to operate some or all of its Venezuelan drilling rigs.

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 Company’s loss of all or a portion of its assets and business in Venezuela.

10. Government Regulation and Environmental Risks

Many aspects of the Company’s 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, the Company is 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.

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

11. Interest Rate Risk

The Company has a $200 million intermediate-term unsecured debt obligation with staged maturities from August 2007 to August 2014, with varying fixed interest rates for each maturity series. There was $200 million outstanding at September 30, 2005, of which $25 million is due in 2007 and the remaining $175 million is due 2009 through 2014. The average interest rate during the next four years on this debt is 6.4 percent, after which it increases to 6.5 percent. The fair value of this debt at September 30, 2005 was approximately $215 million.

At September 30, 2005, the Company had in place a committed unsecured line of credit totaling $50 million with no outstanding borrowings. The Company, as of September 30, 2005, had letters of credit totaling $14 million outstanding against such line of credit. The Company’s line of credit interest rate is based on LIBOR plus 87.5 to 112.5 basis points or prime minus 175 to 150 basis points based on the Company’s EBITDA to net debt ratio. As the Company draws on this line of credit, it is subject to the interest rates prevailing during the term at which the Company had outstanding borrowings. Interest rates could rise for various reasons in the future and increase the Company’s total interest expense, depending upon the amount borrowed against the credit line.

12. Equity Price Risk

At September 30, 2005, the Company owned stocks in other publicly held companies with a total market value of $293.4 million. These securities are subject to a wide variety of market-related risks that could substantially reduce or increase the market value of the Company’s holdings. Except for the Company’s holdings in Atwood Oceanics, Inc., the portfolio is recorded at fair value on its balance sheet with changes in unrealized after-tax value reflected in the equity section of its balance sheet. Any reduction in market value would have an impact on the Company’s debt ratio and financial strength. In October 2004, the Company sold 1,000,000 shares of its position in Atwood Oceanics, Inc. as part of a 2,175,000 share public offering by Atwood. The sale generated $15.9 million ($0.31 per diluted share) of net income in fiscal 2005. The Company currently owns 2,000,000 shares of Atwood.

13. Reliance on Small Number of Customers

In fiscal 2005, the Company received approximately 59 percent of its consolidated operating revenues from the Company’s ten largest contract drilling customers and approximately 28 percent of its consolidated operating revenues from the Company’s three largest customers (including their affiliates). The Company believes that its relationship with all of these customers is good; however, the loss of one or more of its larger customers would have a material adverse effect on the Company’s results of operations.

14. Key Personnel

The Company utilizes highly skilled personnel in operating and supporting its businesses. In times of high utilization, it can be difficult to find qualified individuals. Although to date the Company’s operations have not been materially affected by competition for personnel, an inability to obtain a sufficient number of qualified personnel could materially impact the Company’s results of operations.

15. Changes in Technologies

Although the Company takes measures to ensure that it uses advanced oil and natural gas drilling technology, changes in technology or improvements in competitors’ equipment could make the Company’s equipment less competitive or require significant capital investments to keep its equipment competitive.

16. Concentration of Credit

The concentration of the Company’s customers in the energy industry could cause them to be similarly affected by changes in industry conditions and, as a result, could impact the Company’s exposure to credit risk. The Company cannot offer assurances that losses due to uncollectible receivables will be consistent with expectations.

ITEM 2. PROPERTIES

CONTRACT DRILLING

The following table sets forth certain information concerning the Company’s U.S. drilling rigs as of September 30, 2005:

Location
*FLEXRIGS*
Texas	164	18,000	SCR (FlexRig1	)	1,500
Texas	165	18,000	SCR (FlexRig1	)	1,500
Texas	166	18,000	SCR (FlexRig1	)	1,500
Texas	167	18,000	SCR (FlexRig1	)	1,500
Texas	168	18,000	SCR (FlexRig1	)	1,500
Texas	169	18,000	SCR (FlexRig1	)	1,500
Texas	178	18,000	SCR (FlexRig2	)	1,500
Wyoming	179	18,000	SCR (FlexRig2	)	1,500
Wyoming	180	18,000	SCR (FlexRig2	)	1,500
Texas	181	18,000	SCR (FlexRig2	)	1,500
Texas	182	18,000	SCR (FlexRig2	)	1,500
Texas	183	18,000	SCR (FlexRig2	)	1,500
Texas	184	18,000	SCR (FlexRig2	)	1,500
Texas	185	18,000	SCR (FlexRig2	)	1,500
Texas	186	18,000	SCR (FlexRig2	)	1,500
Texas	187	18,000	SCR (FlexRig2	)	1,500
Texas	188	18,000	SCR (FlexRig2	)	1,500
Oklahoma	189	18,000	SCR (FlexRig2	)	1,500
Texas	210	18,000	AC (FlexRig3	)	1,500
Texas	211	18,000	AC (FlexRig3	)	1,500
Texas	212	18,000	AC (FlexRig3	)	1,500

Location
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
Texas	217	18,000	AC (FlexRig3	)	1,500
Texas	218	18,000	AC (FlexRig3	)	1,500
Texas	219	18,000	AC (FlexRig3	)	1,500
Texas	220	18,000	AC (FlexRig3	)	1,500
Louisiana	221	18,000	AC (FlexRig3	)	1,500
Oklahoma	222	18,000	AC (FlexRig3	)	1,500
Texas	223	18,000	AC (FlexRig3	)	1,500
Texas	224	18,000	AC (FlexRig3	)	1,500
Texas	225	18,000	AC (FlexRig3	)	1,500
Texas	226	18,000	AC (FlexRig3	)	1,500
Texas	227	18,000	AC (FlexRig3	)	1,500
Texas	228	18,000	AC (FlexRig3	)	1,500
Texas	229	18,000	AC (FlexRig3	)	1,500
Texas	230	18,000	AC (FlexRig3	)	1,500
Texas	231	18,000	AC (FlexRig3	)	1,500
Texas	232	18,000	AC (FlexRig3	)	1,500
Texas	233	18,000	AC (FlexRig3	)	1,500
Texas	234	18,000	AC (FlexRig3	)	1,500
Texas	235	18,000	AC (FlexRig3	)	1,500
Texas	236	18,000	AC (FlexRig3	)	1,500
Texas	237	18,000	AC (FlexRig3	)	1,500
Texas	238	18,000	AC (FlexRig3	)	1,500
Colorado	239	18,000	AC (FlexRig3	)	1,500
Texas	240	18,000	AC (FlexRig3	)	1,500
Colorado	241	18,000	AC (FlexRig3	)	1,500

*HIGHLY MOBILE RIGS*
Oklahoma	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
Texas	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
Wyoming	146	16,000	SCR		1,200
Texas	147	16,000	SCR		1,200
Wyoming	154	16,000	SCR		1,500

Location
*CONVENTIONAL RIGS*
Texas	110	12,000		SCR	700
Oklahoma	96	16,000		SCR	1,000
Texas	118	16,000		SCR	1,200
Oklahoma	119	16,000		SCR	1,200
Texas	120	16,000		SCR	1,200
Texas	171	16,000		Mechanical	1,000
Wyoming	172	16,000		Mechanical	1,000
Texas	122	16,000		SCR	1,700
Texas	162	18,000		SCR	1,500
Louisiana	79	20,000		SCR	2,000
Oklahoma	80	20,000		SCR	1,500
Texas	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	173	20,000		Mechanical	2,000
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
Texas	134	30,000		SCR	3,000
Louisiana	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
Texas*	139	30,000	+	SCR	3,000

*OFFSHORE PLATFORM RIGS*
Louisiana	91	20,000		Conventional	3,000
Gulf of Mexico	203	20,000		Self-Erecting	2,500
Gulf of Mexico	205	20,000		Tension-leg	2,000
Gulf of Mexico	206	20,000		Self-Erecting	1,500
Gulf of Mexico	100	30,000		Conventional	3,000
Louisiana	105	30,000		Conventional	3,000
Louisiana	106	30,000		Conventional	3,000
Gulf of Mexico	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

Rig moved to Argentina in November, 2005

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

Years ended September 30,
U.S. Land Rigs
Number of rigs owned at end of period	49		66		83		87		91
Average rig utilization rate during period ⁽¹⁾	97	%	84	%	81	%	87	%	94	%
U.S. Offshore Platform Rigs
Number of rigs owned at end of period	10		12		12		11		11
Average rig utilization rate during period ⁽¹⁾	98	%	83	%	51	%	48	%	53	%

(1)

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

The following table sets forth certain information concerning the Company’s international drilling rigs as of September 30, 2005:

Location
Argentina	175	30,000		SCR	3,000
Argentina	177	30,000		SCR	3,000
Bolivia*	123	26,000		SCR	2,100
Bolivia	151	30,000	+	SCR	3,000
Colombia	133	30,000		SCR	3,000
Colombia	152	30,000	+	SCR	3,000
Ecuador	22	18,000		SCR (Heli Rig)	1,700
Ecuador	23	18,000		SCR (Heli Rig)	1,500
Ecuador	132	18,000		SCR	1,500
Ecuador	176	18,000		SCR	1,500
Ecuador	121	20,000		SCR	1,700
Ecuador	117	26,000		SCR	2,500
Ecuador	138	26,000		SCR	2,500
Ecuador	190	26,000		SCR	2,000
Venezuela	148	26,000		SCR	2,000
Venezuela	160	26,000		SCR	2,000
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	174	30,000		SCR	3,000
Venezuela	153	30,000	+	SCR	3,000

Rig moved to Chile in the first quarter of fiscal 2006

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

Years ended September 30,

Number of rigs owned at end of period	37		33		32		32		26
Average rig utilization rate during period ⁽¹⁾⁽²⁾	56	%	51	%	39	%	54	%	77	%

(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 United States for major modifications and upgrades.

REAL ESTATE OPERATIONS

See Item 1. BUSINESS, pages 5 through 6 of this Report.

STOCK PORTFOLIO

Information required by this item regarding the stock portfolio held by the Company may be found on page 24 of the Company’s Annual Report under the caption, “Management’s Discussion & Analysis of Results of Operations and Financial Condition.”

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS

None.

ITEM 4A. EXECUTIVE OFFICERS OF THE COMPANY

The following table sets forth the names and ages of the Company’s 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 elected and have qualified or until their earlier resignation or removal.

W. H. Helmerich, III, 82

Chairman of the Board
Director since 1949; Chairman of the Board since 1960

Hans Helmerich, 47

President and Chief Executive Officer
Director since 1987; President and Chief Executive Officer since 1989

George S. Dotson, 64

Vice President
Director since 1990; Vice President since 1977 and President and Chief Operating Officer of Helmerich & Payne International Drilling Co. since 1977

Douglas E. Fears, 56

Vice President and Chief Financial Officer since 1988

Steven R. Mackey, 54

Vice President, Secretary and General Counsel
Secretary since 1990; Vice President and General Counsel since 1988

Effective March 1, 2006, following the retirement of George S. Dotson, John W. Lindsay and M. Alan Orr will serve as Executive Vice Presidents for Helmerich & Payne International Drilling Co. Mr. Lindsay will become Executive Vice President, U.S. and International Operations, and Mr. Orr will serve as Executive Vice President, Engineering and Development.

Mr. Lindsay, age 45, joined the Company in 1987 as a drilling engineer. He has since served in various positions including operations manager for the Company’s Mid-Continent region and division manager of U.S. Land Operations. In 1997, Mr. Lindsay was appointed to his present position of Vice President, U.S. Land Operations, for Helmerich & Payne International Drilling Co. Mr. Lindsay graduated in 1986 from the University of Tulsa, where he earned a Bachelor of Science degree in Petroleum Engineering.

Mr. Orr, age 54, joined the Company in 1975 as a roughneck. In his 30-year career, Mr. Orr has held various supervisory positions in the Company’s domestic and international operations. In 1992, Mr. Orr was appointed to his present position as Vice President and Chief Engineer for Helmerich & Payne International Drilling Co. Mr. Orr graduated from the United States Military Academy at West Point in 1973, with a Bachelor of Science degree in General Engineering.

PART II

ITEM 5.

MARKET FOR THE COMPANY’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The principal market on which the Company’s 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:

	2004				2005
Quarter	High		Low		High		Low
First	$	28.37	$	23.77	$	34.16	$	27.66
Second		30.61		27.02		41.10		31.57
Third		29.55		24.25		46.92		37.38
Fourth		29.07		24.01		61.12		47.61

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

	Paid per Share Fiscal				Total Payment Fiscal
Quarter	2004		2005		2004		2005

First	$	.080	$	.0825	$	4,011,879	$	4,165,965
Second		.080		.0825		4,017,204		4,213,594
Third		.080		.0825		4,032,709		4,226,835
Fourth		.0825		.0825		4,160,221		4,259,852

The Company paid a cash dividend of $0.0825 per share on December 1, 2005, to shareholders of record on November 15, 2005. Payment of future dividends will depend on earnings and other factors.

As of December 5, 2005, there were 808 record holders of the Company’s common stock as listed by the transfer agent’s records.

SUMMARY OF ALL EXISTING EQUITY COMPENSATION PLANS

The following chart sets forth information concerning the equity compensation plans of the Company as of September 30, 2005.

EQUITY COMPENSATION PLAN INFORMATION

	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan Category	(a)		(b)		(c)
Equity compensation plans approved by security holders ⁽¹⁾		3,244,073	$	24.566		754,505
Equity compensation plans not approved by security holders ⁽²⁾		—		—		—
Total		3,244,073	$	24.566		754,505

(1)

Includes the 1990 Stock Option Plan, the 1996 Stock Incentive Plan and the 2000 Stock Incentive Plan of the Company.

(2)

The Company does not maintain any equity compensation plans that have not been approved by the stockholders.

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 & Analysis of Results of Operations and Financial Condition contained on pages 8 through 32 of the Company’s Annual Report. On September 30, 2002, the Company spun off Cimarex Energy Co. The historical financial data for the business conducted by Cimarex Energy Co. for 2002 has been reported as discontinued operations which is not included in the five-year summary of selected financial data.

FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA

	2001		2002		2003		2004		2005
	(in thousands except per share amounts)
Operating revenues	$	528,187	$	523,418	$	504,223	$	589,056	$	800,726
Asset Impairment Charge		—		—		—		51,516		—
Other*		15,266		28,925		11,783		32,957		46,093
Income from continuing operations		80,467		53,706		17,873		4,359		127,606
Income from continuing operations per common share:
Basic		1.61		1.08		0.36		0.09		2.50
Diluted		1.58		1.07		0.35		0.09		2.45

Total assets		1,300,121		1,227,313		1,417,770		1,406,844		1,663,350
Long-term debt		50,000		100,000		200,000		200,000		200,000
Cash dividends declared per common share		0.30		0.31		0.32		0.3225		0.33

Other includes gain on sale of assets and investment securities, interest income and dividend income.

ITEM 7.

MANAGEMENT’S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Information required by this item may be found on pages 8 through 32 of the Company’s Annual Report under the caption “Management’s Discussion & Analysis of Results of Operations and Financial Condition.”

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 7 of this Report and on the following pages of the Company’s Annual Report under Management’s Discussion & Analysis of Results of Operations and Financial Condition and in Notes to Consolidated Financial Statements:

MARKET RISK				PAGE
• Foreign Currency Exchange Rate Risk				29-31
• Commodity Price Risk				31
• Interest Rate Risk				31-32
• Equity Price Risk				32

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information required by this item may be found on pages 34 through 63 of the Company’s Annual Report.

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, the Company’s management, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer believe that:

•

the Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files or submits 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

•

the Company’s 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 the Company’s management, and made known to the Company’s 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 of Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s 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. The Company’s 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 the assets of the Company;

(ii)

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

(iii)

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.

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 the Company’s Chief Executive Officer and Chief Financial Officer, conducted its evaluation of the effectiveness of internal controls 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 controls over financial reporting, based on the Company’s evaluation, management has concluded that the Company’s internal controls over financial reporting were effective as of September 30, 2005.

The Company’s registered public accounting firm that audited the Company’s financial statements, Ernst & Young LLP, has issued a report on management’s assessment of the Company’s internal control over financial reporting. This report appears below.

Report of Independent
Registered Public Accounting Firm

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

We have audited management’s assessment, included in the accompanying Management’s Report of Internal Control over Financial Reporting, that Helmerich & Payne, Inc. maintained effective internal control over financial reporting as of September 30, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Helmerich and 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Helmerich & Payne, Inc. maintained effective internal control over financial reporting as of September 30, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Helmerich & Payne, Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2005, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2005 and 2004, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2005 and our report dated December 1, 2005, except for Note 15, as to which the date is December 7, 2005, expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Tulsa, Oklahoma
December 1, 2005

(c) Changes in Internal Controls. There have been no changes in the Company’s internal controls over financial reporting during the Company’s last fiscal quarter of 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS AND EXECUTIVE OFFICERS OF
THE COMPANY

Information required under this item with respect to Directors and with respect to delinquent filers pursuant to Item 405 of Regulation S-K is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 1, 2006, to be filed with the Commission not later than 120 days after September 30, 2005. The information required by this Item with respect to the Company’s Executive Officers appears on pages 16 and 17 of this Report.

The Company has adopted a Code of Ethics for Principal Executive Officers and Senior Financial Officers. The text of such Code is located on the Company’s website under “Investor Relations – Corporate Governance.” The Company’s Internet address is www.hpinc.com.

ITEM 11. EXECUTIVE COMPENSATION

This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 1, 2006, to be filed with the Commission not later than 120 days after September 30, 2005.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a) 1.

Financial Statements: The following appear in the Company’s Annual Report on the pages indicated below and are incorporated herein by reference:

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.

Exhibits. The following documents are included as exhibits to this Form 10-K. Exhibits incorporated herein are duly noted as such. Unless so noted, each exhibit is filed herewith.

3.1 Restated Certificate of Incorporation and Amendment to Restated Certificate of Incorporation of the Company are incorporated herein by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221.

3.2 Amended and Restated By-Laws of the Company are incorporated herein by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended March 31, 2002, 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 No. 1 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.

* 10.1 Consulting Services Agreement between W. H. Helmerich, III, and the Company effective January 1, 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 Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.6 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221.

* 10.3 Helmerich & Payne, Inc. 1990 Stock Option Plan is incorporated herein by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221.

* 10.4 Form of Nonqualified Stock Option Agreement for the 1990 Stock Option Plan is incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement No. 33-55239 on Form S-8, dated August 26, 1994.

* 10.5 Supplemental Savings Plan for Salaried Employees of Helmerich and Payne, Inc. is incorporated herein by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1999, SEC File No. 001-04221.

* 10.6 Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1 to the Company’s Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997.

* 10.7 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.

* 10.8 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.

* 10.9 Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1 to the Company’s Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001.

* 10.10 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.

* 10.11 Form of Director Nonqualified Stock Option Agreement for the 2000 Helmerich & Payne, Inc. 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.

* 10.12 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.

10.13 Credit Agreement, dated as of July 16, 2002, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc., the several lenders from time to time party thereto, and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.5 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.

10.14 First Amendment to Credit Agreement dated July 15, 2003, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A.

10.15 Second Amendment to Credit Agreement dated May 4, 2004, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A.

10.16 Third Amendment to Credit Agreement dated July 13, 2004, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A.

10.17 Fourth Amendment to Credit Agreement dated July 12, 2005, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A. is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on July 13, 2005, SEC File No. 001-04221.

10.18 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.

10.19 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.

* 10.20 Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on September 9, 2004.

10.21 Shareholders Agreement and Registration Rights Agreement dated July 19, 2004 between Helmerich & Payne International Drilling Co. and Atwood Oceanics, Inc. is incorporated herein by reference to Exhibit 1.1 of the Company’s Amended Schedule 13D filed on July 21, 2004.

10.22 Underwriting Agreement dated October 13, 2004, between Helmerich & Payne International Drilling Co. and various underwriters is incorporated herein by reference to Exhibit 1.1 of the Company’s Form 8-K filed on October 14, 2004.

* 10.23 Amended and restated Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers, together with fiscal 2005 Executive Officer compensation, is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 9, 2005.

13. The Company’s Annual Report to Shareholders for fiscal 2005.

21. List of Subsidiaries of the Company.

23.1 Consent of Independent Registered Public Accounting Firm.

31.1 Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer, 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.

Management or Compensatory Plan or Arrangement.

Exhibit Index

4.2 Amendment No. 1 to Rights Agreement dated December 8, 2005 between the Company and VMB Bank, N.A. is incorporated herein by reference to Exhibit 4 of the Company’s Form 8-K filed on December 12, 2005.

10.14 First Amendment to Credit Agreement dated July 15, 2003, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A.

10.15 Second Amendment to Credit Agreement dated May 4, 2004, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A.

10.16 Third Amendment to Credit Agreement dated July 13, 2004, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., and Bank of Oklahoma, N.A.

* 10.20 Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on September 9, 2004.

13. The Company’s Annual Report to Shareholders for fiscal 2005.

21. List of Subsidiaries of the Company.

23.1 Consent of Independent Registered Public Accounting Firm.

31.1 Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer, 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.

Management or Compensatory Plan or Arrangement.

By:	__________________________
Name:		Douglas E. Fears
Title:		Vice President

By:	__________________________
Name:		Douglas E. Fears
Title:		Vice President

By:	____________________________
Name:		__________________________
Title:		__________________________

By:	____________________________
Name:		__________________________
Title:		__________________________

By:	____________________________
Name:	____________________________
Title:		__________________________

Schedule 2.6(a)	-	Existing Letters of Credit
Schedule 6.12(ii)	-	ERISA Matters
Schedule 6.13(d)	-	Regulation O
Schedule 7.6	-	Insurance

Amount:	$12,000,000.00
Expiry:	03/09/04
Beneficiary:	National Union Fire (AIG)

Amount:	$1,087,260.00
Expiry:	12/30/03
Beneficiary:	Banco Bisa Lapaz Bolivia

BOK00SDF06739
Amount:	$12,000,000.00
Expiry:	03/09/04
Beneficiary:	National Union Fire (AIG)
BOK00SIF05082 Amount:	$1,087,260.00
Expiry:	12/30/03
Beneficiary:	Banco Bisa Lapaz Bolivia

Years Ended September 30,	2005		2004
	(in thousands, except per share amounts)
Operating Revenues	$	800,726	$	589,056
Net Income		127,606		4,359
Diluted Earnings per Share		2.45		.09
Dividends Paid per Share		.33		.3225
Capital Expenditures		86,805		90,212
Total Assets		1,663,350		1,406,844

Years Ended September 30,	2005		2004			2003

SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME *†
Operating Revenues	$	800,726	$	589,056		$	504,223
Operating Costs		484,231		417,716			346,259
Depreciation**		96,274		145,941			82,513
General and Administrative Expense		41,015		37,661			41,003
Operating Income (loss)		179,206		(12,262	)		34,448
Interest, Dividend, and Other Income		5,574		2,162			2,565
Income from Investment and Asset Sales		40,519		30,795			9,218
Interest Expense		12,642		12,695			12,289
Income from Continuing Operations		127,606		4,359			17,873
Net Income		127,606		4,359			17,873
Diluted Earnings Per Common Share:
Income from Continuing Operations		2.45		.09			.35
Net Income		2.45		.09			.35
*$000’s omitted, except per share data
†All data excludes discontinued operations except net income.
**2004 includes an asset impairment of $51,516
SUMMARY FINANCIAL DATA*
Cash**	$	288,752	$	65,296		$	38,189
Working Capital**		410,316		185,427			110,848
Investments		178,452		161,532			158,770
Property, Plant, and Equipment, Net**		981,965		998,674			1,058,205
Total Assets		1,663,350		1,406,844			1,417,770
Long-term Debt		200,000		200,000			200,000
Shareholders’ Equity		1,079,238		914,110			917,251
Capital Expenditures		86,805		90,212			242,912
*$000’s omitted
**Excludes discontinued operations
RIG FLEET SUMMARY
Drilling Rigs –
U. S. Land – FlexRigs		50		48			43
U. S. Land – Highly Mobile		12		11			11
U. S. Land – Conventional		29		28			29
U. S. Offshore Platform		11		11			12
International		26		32			32
Total Rig Fleet		128		130			127
Rig Utilization Percentage –
U. S. Land – FlexRigs		100		99			97
U. S. Land – Highly Mobile		99		91			89
U. S. Land – Conventional		82		67			58
U. S. Land – All Rigs		94		87			81
U. S. Offshore Platform		53		48			51
International		77		54			39

2002	2001		2000		1999		1998		1997		1996		1995


$523,418	$	528,187	$	383,898	$	430,475	$	476,750	$	351,710	$	275,096	$	227,646
362,133		331,063		249,318		288,969		321,798		227,921		185,210		159,073
61,447		49,532		77,317		70,092		58,187		48,291		39,592		37,364
36,563		28,180		23,306		24,629		21,299		15,636		15,222		14,019
63,275		119,412		33,957		46,785		75,466		59,862		35,072		17,190
2,713		9,876		19,540		2,823		5,899		5,779		5,381		6,455
26,212		5,390		14,164		4,786		41,032		6,575		230		6,752
980		1,701		2,730		5,389		336		34		678		407
53,706		80,467		36,470		32,115		80,790		48,801		25,844		18,464
63,517		144,254		82,300		42,788		101,154		84,186		72,566		9,751

1.07		1.58		.73		.65		1.60		.97		.52		.38
1.26		2.84		1.64		.86		2.00		1.67		1.46		.20




$46,883	$	128,826	$	107,632	$	21,758	$	24,476	$	27,963	$	16,892	$	19,543
105,852		223,980		179,884		82,893		49,179		65,802		48,128		50,038
150,175		203,271		307,425		240,891		200,400		323,510		229,809		156,908
897,445		650,051		526,723		553,769		548,555		392,489		329,377		286,678
1,227,313		1,300,121		1,200,854		1,073,465		1,053,200		987,432		786,351		707,061
100,000		50,000		50,000		50,000		50,000		—		—		—
895,170		1,026,477		955,703		848,109		793,148		780,580		645,970		562,435
312,064		184,668		65,820		78,357		217,597		114,626		83,411		89,709




26		13		6		6		6		—		—		—
11		11		10		11		7		7		7		8
29		25		22		23		23		22		23		22
12		10		10		10		10		9		11		11
33		37		40		39		44		39		36		35
111		96		88		89		90		77		77		76

96		100		99		79		100		—		—		—
97		89		95		90		100		100		87		76
70		99		77		61		92		99		88		72
84		97		85		69		94		99		88		73
83		98		94		95		99		63		70		66
51		56		47		53		88		91		85		84

	2005			2004
U.S. LAND OPERATIONS	(in thousands, except operating statistics)
Operating revenues	$	527,637		$	346,015		52.5	%
Direct operating expenses		294,164			246,177		19.5
General and administrative expense		8,594			7,765		10.7
Depreciation		60,222			56,528		6.5
Operating income	$	164,657		$	35,545		363.2

Operating Statistics:
Activity days		30,968			27,472		12.7	%
Average rig revenue per day	$	15,941		$	11,635		37.0
Average rig expense per day	$	8,403		$	8,001		5.0
Average rig margin per day	$	7,538		$	3,634		107.4
Number of owned rigs at end of period		91			87		4.6
Rig utilization		94	%		87	%	8.0

	2005			2004
U.S. OFFSHORE OPERATIONS	(in thousands, except operating statistics)
Operating revenues	$	84,921		$	84,238		.8	%
Direct operating expenses		52,786			52,987		(.4	)
General and administrative expense		3,825			3,256		17.5
Depreciation		10,602			12,107		(12.4	)
Asset impairment charge		—			51,516
Operating income (loss)	$	17,708		$	(35,628	)	149.7

Operating Statistics:
Activity days		2,122			2,088		1.6	%
Average rig revenue per day	$	29,228		$	29,070		.5
Average rig expense per day	$	15,967		$	16,509		(3.3	)
Average rig margin per day	$	13,261		$	12,561		5.6
Number of owned rigs at end of period		11			11		—
Rig utilization		53	%		48	%	10.4

	2005
	(in millions)
Operating income (loss), as reported	$	17.7	(35.6	)
Asset impairment charge		—	51.5
Operating income, excluding asset impairment charge	$	17.7	15.9		11.5	%

	2005			2004
INTERNATIONAL OPERATIONS	(in thousands, except operating statistics)
Operating revenues	$	177,480		$	148,788		19.3	%
Direct operating expenses		135,837			113,988		19.2
General and administrative expense		2,563			2,144		19.5
Depreciation		20,107			20,530		(2.1	)
Operating income	$	18,973		$	12,126		56.5

Operating Statistics:
Activity days		7,491			6,266		19.5	%
Average rig revenue per day	$	19,332		$	19,580		(1.3	)
Average rig expense per day	$	14,039		$	14,279		(1.7	)
Average rig margin per day	$	5,293		$	5,301		(.2	)
Number of owned rigs at end of period		26			32		(18.8	)
Rig utilization		77	%		54	%	42.6

	2005		2004
REAL ESTATE	(in thousands)
Operating revenues	$	10,688	$	10,015	6.7	%
Direct operating expenses		3,622		4,564	(20.6	)
Depreciation		2,352		2,253	4.4
Operating income	$	4,714	$	3,198	47.4

September 30, 2005	Number of Shares		Cost Basis		Market Value
	(in thousands, except share amounts)
Atwood Oceanics, Inc.		2,000,000	$	46,533	$	168,420
Schlumberger, Ltd.		1,230,000		19,539		103,787
Other				11,398		21,150
Total			$	77,470	$	293,357

Payments Due By Year	Total		2006		2007		2008		2009		2010		After 2010
	(in thousands)
Long-term debt (a)	$	200,000	$	—	$	25,000	$	—	$	25,000	$	—	$	150,000
Operating leases (b)		9,231		3,095		2,470		1,615		1,569		482		—
Total Contractual Obligations	$	209,231	$	3,095	$	27,470	$	1,615	$	26,569	$	482	$	150,000

	2006		2007			2008			2009			2010			After 2010			Total			Fair Value @ 9/30/05
Fixed Rate Debt		—	$	25,000			—		$	25,000			—		$	150,000		$	200,000		$	215,000
Average Interest Rate		—		5.5	%		—			5.9	%		—			6.5	%		6.4	%


INTEREST RATE RISK AS OF SEPTEMBER 30, 2004 (in thousands)
	2005		2006			2007			2008			2009			After 2009			Total			Fair Value @ 9/30/04
Fixed Rate Debt		—		—		$	25,000			—		$	25,000		$	150,000		$	200,000		$	216,400
Average Interest Rate		—		—			5.5	%		—			5.9	%		6.5	%		6.3	%

Years Ended September 30,	2005			2004			2003
	(in thousands, except per share amounts)
OPERATING REVENUES
Drilling – U.S. Land	$	527,637		$	346,015		$	273,179
Drilling – U.S. Offshore		84,921			84,238			112,259
Drilling – International		177,480			148,788			109,517
Real Estate		10,688			10,015			9,268
		800,726			589,056			504,223
OPERATING COSTS AND EXPENSES
Operating costs		484,231			417,716			346,259
Depreciation		96,274			94,425			82,513
Asset impairment		—			51,516			—
General and administrative		41,015			37,661			41,003
		621,520			601,318			469,775

Operating income (loss)		179,206			(12,262	)		34,448

Other income (expense)
Interest and dividend income		5,809			1,965			2,467
Interest expense		(12,642	)		(12,695	)		(12,289	)
Gain on sale of investment securities		26,969			25,418			5,529
Income from asset sales		13,550			5,377			3,689
Other		(235	)		197			98
		33,451			20,262			(506	)

Income before income taxes and equity in income (loss) of affiliates		212,657			8,000			33,942
Income tax provision		87,463			4,365			14,649
Equity in income (loss) of affiliates net of income taxes		2,412			724			(1,420	)

NET INCOME	$	127,606		$	4,359		$	17,873

Earnings per common share:
Basic	$	2.50		$	0.09		$	0.36
Diluted	$	2.45		$	0.09		$	0.35
Average common shares outstanding (in thousands):
Basic		51,087			50,312			50,039
Diluted		52,033			50,833			50,596

September 30,	2005		2004
	(in thousands)
CURRENT ASSETS:

Cash and cash equivalents	$	288,752	$	65,296
Accounts receivable, less reserve of $1,791 in 2005 and $1,265 in 2004		162,646		133,262
Inventories		21,313		20,826
Deferred income taxes		8,765		4,346
Prepaid expenses and other		18,321		21,600
Total current assets		499,797		245,330

INVESTMENTS		178,452		161,532

PROPERTY, PLANT AND EQUIPMENT, at cost:

Contract drilling equipment		1,549,112		1,531,937
Construction in progress		34,774		1,228
Real estate properties		57,489		56,307
Other		96,614		93,640
		1,737,989		1,683,112
Less-Accumulated depreciation and amortization		756,024		684,438
Net property, plant and equipment		981,965		998,674

OTHER ASSETS		3,136		1,308

TOTAL ASSETS	$	1,663,350	$	1,406,844

September 30,	2005			2004
	(in thousands, except share data)
CURRENT LIABILITIES:

Accounts payable	$	44,854		$	28,012
Accrued liabilities		44,627			31,891
Total current liabilities		89,481			59,903

NONCURRENT LIABILITIES:

Long-term notes payable		200,000			200,000
Deferred income taxes		246,975			194,573
Other		47,656			38,258
Total noncurrent liabilities		494,631			432,831

SHAREHOLDERS’ EQUITY:

Common stock, $.10 par value, 80,000,000 shares authorized, 53,528,952 shares issued		5,353			5,353
Preferred stock, no par value, 1,000,000 shares authorized, no shares issued		—			—
Additional paid-in capital		112,297			85,466
Retained earnings		939,380			828,763
Unearned compensation		(134	)		—
Accumulated other comprehensive income		47,544			36,252
		1,104,440			955,834
Less treasury stock, 1,594,362 shares in 2005 and 3,083,516 shares in 2004, at cost		25,202			41,724
Total shareholders’ equity		1,079,238			914,110

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	1,663,350		$	1,406,844

	Common Stock														Treasury Stock
	Shares	Amount		Additional Paid-in Capital		Retained Earnings			Unearned Compensation			Accumulated Other Comprehensive Income (Loss)			Shares			Amount			Total
	(in thousands, except per share amounts)
Balance, September 30, 2002	53,529	$	5,353	$	82,489	$	838,929		$	(190	)	$	16,180			3,518		$	(47,591	)	$	895,170

Comprehensive Income:
Net Income							17,873															17,873
Other comprehensive income:
Unrealized gains on available- for-sale securities, net													15,005									15,005
Derivatives instruments
Amortization, net													982									982
Minimum pension liability adjustment, net													1,501									1,501
Total other comprehensive gain																						17,488
Total comprehensive income																						35,361
Cash dividends ($.32 per share)							(16,026	)														(16,026	)
Exercise of stock options					441											(129	)		1,753			2,194
Tax benefit of stock-based awards					372																	372
Amortization of deferred compensation										180												180
Balance, September 30, 2003	53,529		5,353		83,302		840,776			(10	)		33,668			3,389			(45,838	)		917,251

Comprehensive Income:
Net Income							4,359															4,359
Other comprehensive income (loss):
Unrealized gains on available- for-sale securities, net													3,721									3,721
Derivatives instruments
Amortization, net													72									72
Minimum pension liability adjustment, net													(1,209	)								(1,209	)
Total other comprehensive gain																						2,584
Total comprehensive income																						6,943
Cash dividends ($.3225 per share)							(16,372	)														(16,372	)
Exercise of stock options					813											(305	)		4,114			4,927
Tax benefit of stock-based awards					1,351																	1,351
Amortization of deferred compensation										10												10
Balance, September 30, 2004	53,529		5,353		85,466		828,763			—			36,252			3,084			(41,724	)		914,110


Comprehensive Income:
Net Income							127,606															127,606
Other comprehensive income (loss):
Unrealized gains on available-for-sale securities, net													14,708									14,708
Minimum pension liability adjustment, net													(3,416	)								(3,416	)
Total other comprehensive gain																						11,292
Total comprehensive income																						138,898
Capital adjustment of equity investee					2,682																	2,682
Stock issued under Restricted Stock Award Plan					93					(160	)					(5	)		67			—
Cash dividends ($.33 per share)							(16,989	)														(16,989	)
Exercise of stock options					8,903											(1,485	)		16,455			25,358
Tax benefit of stock-based awards					15,153																	15,153
Amortization of deferred compensation										26												26
Balance, September 30, 2005	53,529	$	5,353	$	112,297	$	939,380		$	(134	)	$	47,544			1,594		$	(25,202	)	$	1,079,238

Years Ended September 30,	2005			2004			2003
	(in thousands)
OPERATING ACTIVITIES:
Net income	$	127,606		$	4,359		$	17,873
Adjustments to reconcile income to net cash provided by operating activities:
Depreciation		96,274			94,425			82,513
Asset impairment charge		—			51,516			—
Equity in (income) loss of affiliates before income taxes		(3,891	)		(1,168	)		2,290
Amortization of deferred compensation		26			10			180
Gain on sale of investment securities		(26,969	)		(22,766	)		(5,529	)
Non-monetary investment gain		—			(2,521	)		—
Gain on sale of assets		(13,550	)		(5,377	)		(3,689	)
Deferred income tax expense		38,014			5,934			41,391
Other – net		(349	)		(98	)		336
Change in assets and liabilities:
Accounts receivable		(46,223	)		(25,335	)		1,516
Inventories		(487	)		1,707			251
Prepaid expenses and other		1,451			24,142			(29,355	)
Accounts payable		8,517			(378	)		(14,804	)
Accrued liabilities		12,736			2,870			(1,281	)
Deferred income taxes		16,557			2,323			(166	)
Other noncurrent liabilities		2,526			6,997			1,589
		84,632			132,281			75,242
Net cash provided by operating activities		212,238			136,640			93,115

INVESTING ACTIVITIES:
Capital expenditures		(86,805	)		(90,212	)		(242,912	)
Proceeds from asset sales		28,992			7,941			6,720
Purchase of investments		(5,000	)		—			—
Proceeds from sale of investments		65,539			14,033			18,215
Net cash provided by (used in) investing activities		2,726			(68,238	)		(217,977	)

FINANCING ACTIVITIES:
Proceeds from long-term debt		—			—			100,000
Decrease (increase) in short-term notes		—			(30,000	)		30,000
Dividends paid		(16,866	)		(16,222	)		(16,026	)
Proceeds from exercise of stock options		25,358			4,927			2,194
Net cash provided by (used in) financing activities		8,492			(41,295	)		116,168

Net increase (decrease) in cash and cash equivalents		223,456			27,107			(8,694	)
Cash and cash equivalents, beginning of period		65,296			38,189			46,883
Cash and cash equivalents, end of period	$	288,752		$	65,296		$	38,189

Years Ended September 30,	2005		2004		2003
	(in thousands)
Minimum rents	$	7,606	$	7,490	$	7,333
Overage and percentage rents	$	1,162	$	1,207	$	768

Fiscal Year	Amount

2006	$	6,887
2007		6,134
2008		4,840
2009		3,532
2010		2,901
Thereafter		4,765
Total	$	29,059

September 30,	2005		2004		2003
	(in thousands)
Gross revenues	$	176,156	$	163,454	$	144,766
Costs and expenses		149,785		155,867		157,568
Net income (loss)	$	26,371	$	7,587	$	(12,802	)
Helmerich & Payne, Inc.’s equity in net income (loss), net of income taxes	$	2,412	$	724	$	(1,414	)

Current assets	$	93,283	$	92,966	$	76,012
Noncurrent assets		403,641		405,970		446,662
Current liabilities		56,159		60,053		49,949
Noncurrent liabilities		78,268		167,294		209,258
Shareholders’ equity		362,497		271,589		263,467

Helmerich & Payne, Inc.’s investment	$	46,533	$	57,824	$	56,655

September 30,	2005			2004			2003
	(in thousands, except per share amounts)
Net income, as reported	$	127,606		$	4,359		$	17,873
Stock-based employee compensation expense included in the Consolidated Statements of Income, net of related tax effects		16			6			112
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(3,563	)		(4,172	)		(4,387	)
Pro forma net income	$	124,059		$	193		$	13,598
Earnings per share:
Basic-as reported	$	2.50		$	0.09		$	0.36
Basic-pro forma	$	2.43		$	0.00		$	0.27
Diluted-as reported	$	2.45		$	0.09		$	0.35
Diluted-pro forma	$	2.34		$	0.00		$	0.27

Issue Amount	Maturity Date
$25,000	August 15, 2007	5.51	%
$25,000	August 15, 2009	5.91	%
$75,000	August 15, 2012	6.46	%
$75,000	August 15, 2014	6.56	%

Years Ended September 30,	2005		2004			2003
	(in thousands)
Current:
Federal	$	39,139	$	(5,997	)	$	(34,495	)
Foreign		8,185		4,622			6,870
State		2,125		(194	)		883
		49,449		(1,569	)		(26,742	)
Deferred:
Federal		31,573		4,037			42,835
Foreign		4,863		1,902			(3,383	)
State		1,578		(5	)		1,939
		38,014		5,934			41,391
Total provision (benefit)	$	87,463	$	4,365		$	14,649

Years Ended September 30,	2005		2004			2003
	(in thousands)
Domestic	$	195,978	$	(2,565	)	$	31,638
Foreign		16,679		10,565			2,304
	$	212,657	$	8,000		$	33,942

September 30,	2005		2004
	(in thousands)
Deferred tax liabilities:
Property, plant and equipment	$	210,861	$	188,240
Available-for-sale securities		31,929		28,203
Equity investments		20,915		17,793
Other		1,715		1,714
Total deferred tax liabilities		265,420		235,950
Deferred tax assets:
Pension reserves		10,310		7,283
Insurance reserves		3,943		4,452
Net operating loss and foreign tax credit carryforwards		32,567		56,213
Minimum tax credit carryforwards		428		3,748
Financial accruals		11,295		7,848
Other		12		1,315
Total deferred tax assets		58,555		80,859
Valuation allowance		31,345		35,136
Net deferred tax assets		27,210		45,723
Net deferred tax liabilities	$	238,210	$	190,227

Years Ended September 30,

U.S. Federal income tax rate	35	%	35	%	35	%
Effect of foreign taxes	3		18		4
State income taxes	3		—		4
Other	—		2		—
Effective income tax rate	41	%	55	%	43	%

	2005					2004					2003
	Options			Weighted-Average Exercise Price		Options			Weighted-Average Exercise Price		Options			Weighted-Average Exercise Price
Outstanding at October 1,		4,457		$	22.03		4,327		$	21.41		3,875		$	20.28
Granted		463			32.02		469			24.18		611			27.74
Exercised		(1,611	)		19.57		(305	)		16.15		(130	)		16.93
Forfeited/Expired		(65	)		27.22		(34	)		25.38		(29	)		23.85
Outstanding on September 30,		3,244		$	24.57		4,457		$	22.03		4,327		$	21.41
Exercisable on September 30,		2,027		$	22.74		2,997		$	20.62		2,575		$	19.34
Shares available to grant		755					1,158					1,597