HELMERICH & PAYNE INC (Form: 10-K, Received: 11/21/2012 13:41:43)

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

FORM 10-K


ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended September 30, 2012
		OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission file number 1-4221

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


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

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

Title of Each Class		Name of Each Exchange on Which Registered

Common Stock ($0.10 par value)		New York Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange

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

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

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

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

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

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

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


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

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

At March 30, 2012, the aggregate market value of the voting stock held by non-affiliates was $5,455,241,646

Number of shares of common stock outstanding at November 15, 2012: 105,728,157

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, 2012		Parts I and II
(2) Proxy Statement for Annual Meeting of Stockholders to be held March 6, 2013		Part III

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DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

THIS REPORT INCLUDES "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF THE SECURITIES ACT OF 1933, AS AMENDED, AND THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS REGARDING THE REGISTRANT'S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS. IN ADDITION, FORWARD-LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY THE USE OF FORWARD-LOOKING TERMINOLOGY SUCH AS "MAY", "WILL", "EXPECT", "INTEND", "ESTIMATE", "ANTICIPATE", "BELIEVE", OR "CONTINUE" OR THE NEGATIVE THEREOF OR SIMILAR TERMINOLOGY. ALTHOUGH THE REGISTRANT BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO BE CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE REGISTRANT'S EXPECTATIONS ARE DISCLOSED IN THIS REPORT UNDER THE CAPTION "RISK FACTORS" BEGINNING ON PAGE 6, AS WELL AS IN MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ON, AND INCORPORATED BY REFERENCE TO, PAGES 3 THROUGH 17 OF THE COMPANY'S ANNUAL REPORT (EXHIBIT 13 TO THIS FORM 10-K). ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE REGISTRANT, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY SUCH CAUTIONARY STATEMENTS. THE REGISTRANT ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE, EXCEPT AS REQUIRED BY LAW.

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HELMERICH & PAYNE, INC.
FORM 10-K
YEAR ENDED SEPTEMBER 30, 2012
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PART I
Item 1.	Business	1
Item 1A.	Risk Factors	6
Item 1B.	Unresolved Staff Comments	12
Item 2.	Properties	13
Item 3.	Legal Proceedings	21
Item 4.	Mine Safety Disclosures	21
	Executive Officers of the Company	22
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Selected Financial Data	23
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	24
Item 8.	Financial Statements and Supplementary Data	24
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	25
Item 9A.	Controls and Procedures	25
Item 9B.	Other Information	28
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	29
Item 11.	Executive Compensation	29
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	29
Item 13.	Certain Relationships and Related Transactions, and Director Independence	29
Item 14.	Principal Accountant Fees and Services	29
PART IV
Item 15.	Exhibits and Financial Statement Schedules	30
SIGNATURES		35

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HELMERICH & PAYNE, INC. AND SUBSIDIARIES

Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

For the Fiscal Year Ended September 30, 2012

PART I

Item 1. BUSINESS

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

Our contract drilling business is composed of three reportable business segments: U.S. Land, Offshore and International Land. During fiscal 2012, our U.S. Land operations drilled primarily in Oklahoma, California, Texas, Wyoming, Colorado, Louisiana, Pennsylvania, Ohio, Utah, Arkansas, New Mexico, Montana, North Dakota and West Virginia. Offshore operations were conducted in the Gulf of Mexico, and offshore of California, Trinidad and Equatorial Guinea. Our International Land segment operated in six international locations during fiscal 2012: Ecuador, Colombia, Argentina, Tunisia, Bahrain and United Arab Emirates ("UAE").

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

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

Our subsidiary, TerraVici Drilling Solutions, Inc. ("TerraVici"), is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. We acquired TerraVici to primarily complement our existing drilling rig technology as well as to potentially offer directional drilling services to third parties. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer.

On June 30, 2010, the Venezuelan government seized 11 rigs owned by our Venezuelan subsidiary and associated real and personal property. We have sued the Bolivarian Republic of Venezuela and related governmental entities for damages sustained as a result of the seizure of our Venezuelan drilling business. We are also participating in one arbitration against a non-Venezuelan entity related to the seizure of our property in Venezuela (For further information, see Item 3. Legal Proceedings). We are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. Our financial statements have been prepared with the net assets, results of operations, and cash flows of the Venezuelan operations presented as discontinued operations. The operations from our Venezuelan subsidiary were previously an operating segment within our International Land segment.

CONTRACT DRILLING

General

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

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In fiscal 2012, we received approximately 59 percent of our consolidated operating revenues from our ten largest contract drilling customers. Occidental Oil and Gas Corporation, Marathon Oil Company and Devon Energy Production Co. LP (respectively, "Oxy", "Marathon" and "Devon"), including their affiliates, are our three largest contract drilling customers. We perform drilling services for Oxy on a world-wide basis, and for Marathon and for Devon in U.S. land operations. Revenues from drilling services performed for Oxy, Marathon and Devon in fiscal 2012 accounted for approximately 12 percent, 10 percent and 10 percent, respectively, of our consolidated operating revenues for the same period.

Rigs, Equipment and Facilities

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

Mechanical rigs rely on belts, pulleys and other mechanical devices to control drilling speed and other rig processes. As such, mechanical rigs are not highly efficient or precise in their operation. In contrast to mechanical rigs, SCR rigs rely on direct current for power. This enables motor speed to be controlled by changing electrical voltage. Compared to mechanical rigs, SCR rigs operate with greater efficiency, more power and better control. AC rigs on the other hand provide for even greater efficiency and flexibility than what can be achieved with mechanical or SCR rigs. AC rigs use a variable frequency drive that allows motor speed to be manipulated via changes to electrical frequency. The variable frequency drive permits greater control of motor speed for more precision. Among other attributes, AC rigs are electrically more efficient, produce more torque, utilize regenerative braking, have digital controls and AC motors require less maintenance.

During the mid-1990's, we undertook an initiative to use our land and offshore platform drilling experience to develop a new generation of drilling rigs that would be safer, faster-moving and more capable than mechanical rigs. In 1998, we put to work a new generation of highly mobile/depth flexible land drilling rigs (individually the "FlexRig®"). Since the introduction of our FlexRigs, we have focused on designing and building high-performance, high-efficiency rigs to be used exclusively in our contract drilling business. We believed that over time FlexRigs would displace older less capable rigs. With the advent of unconventional shale plays, our AC drive FlexRigs have proven to be particularly well suited for more complex horizontal drilling requirements. The FlexRig has been able to significantly reduce average rig move and drilling times compared to similar depth-rated traditional land rigs. In addition, the FlexRig allows greater depth flexibility and provides greater operating efficiency. The original rigs were designated as FlexRig1 and FlexRig2 rigs and were designed to drill wells with a depth of between 8,000 and 18,000 feet. In 2001, we announced that we would build the next generation of FlexRigs, known as "FlexRig3", 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

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enlarged drill floor that enables simultaneous crew activities. FlexRig3s were designed to target well depths of between 8,000 and 22,000 feet.

In 2006, we placed into service our first FlexRig4. While FlexRig4s are similar to our FlexRig3s, the FlexRig4s are designed to efficiently drill more shallow depth wells of between 4,000 and 18,000 feet. The FlexRig4 design includes a trailerized version and a skidding version, which incorporate additional environmental and safety design. This design permits the installation of a pipe handling system which allows the rig to be more efficiently operated and eliminates the need for a casing stabber in the mast. While the FlexRig4 trailerized version provides for more efficient well site to well site rig moves, the skidding version allows for drilling of up to 22 wells from a single pad which results in reduced environmental impact. In 2011, we announced the introduction of the FlexRig5 design. The FlexRig5 is suited for long lateral drilling of multiple wells from a single location, which is well suited for unconventional shale reservoirs. The new design preserves the key performance features of FlexRig3 combined with a bi-directional pad drilling system and equipment capacities suitable for wells in excess of 22,000 feet of measured depth.

Industry trends toward more complex drilling have accelerated the retirement of less capable mechanical rigs. Over the past few years our mechanical rigs have been sold as we added new AC drive rigs to our fleet. The retirement of our remaining seven mechanical rigs in fiscal 2011 marked the end of a multi-year evolution in the high-grading of our fleet from mechanical rigs to high-efficiency, high-performance rigs.

Since 1998, we have built and delivered 280 FlexRigs, including 165 FlexRig3s, 86 FlexRig4s, and 12 FlexRig5s. Of the total FlexRigs built through September 30, 2012, 162 have been built in the last five years. As of November 15, 2012, an additional 9 new FlexRigs remained under construction.

The effective use of technology is important to the maintenance of our competitive position within the drilling industry. We expect to continue to refine our existing technology and develop new technology in the future.

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

During fiscal 2012, we leased a 150,000 square foot industrial facility near Tulsa, Oklahoma for the purpose of overhauling/repairing rig equipment and associated component parts. This facility is expected to be fully operational by December 2012.

Drilling Contracts

Our drilling contracts are obtained through competitive bidding or as a result of negotiations with customers, and often cover multi-well and multi-year projects. Each drilling rig operates under a separate drilling contract. During fiscal 2012, all drilling services were performed on a "daywork" contract basis, under which we charge a fixed rate per day, with the price determined by the location, depth and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. We have previously performed contracts on a combination "footage" and "daywork" basis, under which we charged a fixed rate per foot of hole drilled to a stated depth, usually no deeper than 15,000 feet, and a fixed rate per day for the remainder of the hole. Contracts performed on a "footage" basis involve a greater element of risk to the contractor than do contracts performed on a "daywork" basis. Also, we have previously accepted "turnkey" contracts under which we charge a fixed sum to deliver a hole to a stated depth and agree to furnish services such as testing, coring and casing the hole which are not normally done on a "footage" basis. "Turnkey" contracts entail varying degrees of risk greater than the usual "footage" contract. We have not accepted any "footage" or "turnkey" contracts in over fifteen years. We believe that under current market conditions, "footage" and "turnkey" contract rates do not adequately compensate us for the

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added risks. The duration of our drilling contracts are "well-to-well" or for a fixed term. "Well-to-well" contracts are cancelable at the option of either party upon the completion of drilling at any one site. Fixed-term contracts generally have a minimum term of at least six months but customarily provide for termination at the election of the customer, with an "early termination payment" to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us.

Contracts generally contain renewal or extension provisions exercisable at the option of the customer at prices mutually agreeable to us and the customer. In most instances contracts provide for additional payments for mobilization and demobilization.

As of September 30, 2012, we had 176 rigs under fixed-term contracts. While the original duration for these current fixed-term contracts are for six-month to seven-year periods, some fixed-term and well-to-well contracts are expected to be extended for longer periods than the original terms. However, the contracting parties have no legal obligation to extend these contracts.

Backlog

Our contract drilling backlog, being the expected future revenue from executed contracts with original terms in excess of one year, as of September 30, 2012 and 2011 was $3.6 billion and $3.8 billion, respectively. The decrease in backlog at September 30, 2012 from September 30, 2011, is primarily due to expiration of long-term contracts. Approximately 57.2 percent of the total September 30, 2012 backlog is not reasonably expected to be filled in fiscal 2013. A portion of the backlog represents term contracts for new rigs that will be constructed in the future.

The following table sets forth the total backlog by reportable segment as of September 30, 2012 and 2011, and the percentage of the September 30, 2012 backlog not reasonably expected to be filled in fiscal 2013:

	Total Backlog Revenue

	Total Backlog Revenue				Percentage Not Reasonably Expected to be Filled in Fiscal 2013
Reportable Segment	9/30/2012		9/30/2011
	(in billions)
U.S. Land	$	3.0	$	3.3		58.2	%
Offshore		0.1		0.1		35.4	%
International		0.5		0.4		56.1	%

	$	3.6	$	3.8

We obtain certain key rig components from a single or limited number of vendors or fabricators. Certain of these vendors or fabricators are thinly capitalized independent companies located on the Texas gulf coast. Therefore, disruptions in rig component deliveries may occur. Accordingly, the actual amount of revenue earned may vary from the backlog reported. For further information, see Item 1A. Risk Factors.

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U.S. LAND DRILLING

At the end of September 2012, 2011 and 2010, we had 282, 248 and 220, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2012 increased by a net of 34 rigs from the end of fiscal 2011. The increase is due to 46 new FlexRigs being completed and placed into service, 3 rigs transferred to international operations, 3 rigs sold during fiscal 2012, and 4 mechanical highly mobile rigs and 2 conventional rigs being removed from service. Our U.S. Land operations contributed approximately 85 percent ($2.7 billion) of our consolidated operating revenues during fiscal 2012, compared with approximately 83 percent ($2.1 billion) of consolidated operating revenues during fiscal 2011 and approximately 75 percent ($1.4 billion) of consolidated operating revenues during fiscal 2010. Rig utilization was approximately 89 percent in fiscal 2012, approximately 86 percent in fiscal 2011 and approximately 73 percent in fiscal 2010. Our fleet of FlexRigs had an average utilization of approximately 97 percent during fiscal 2012, while our conventional and highly mobile rigs had an average utilization of approximately 11 percent. A rig is considered to be utilized when it is operated or being mobilized or demobilized under contract. At the close of fiscal 2012, 231 out of an available 282 land rigs were working.

OFFSHORE DRILLING

Our Offshore operations contributed approximately 6 percent in fiscal year 2012 ($189.1 million) of our consolidated operating revenues compared to approximately 8 percent ($201.4 million) of consolidated operating revenues during fiscal 2011 and 11 percent ($202.7 million) of consolidated operating revenues during fiscal 2010. Rig utilization in fiscal 2012 was approximately 79 percent compared to approximately 77 percent in fiscal 2011 and approximately 80 percent in fiscal 2010. At the end of fiscal 2012, we had eight of our nine offshore platform rigs under contract and continued to work under management contracts for four customer-owned rigs. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 56 percent of offshore revenues during fiscal 2012.

INTERNATIONAL LAND DRILLING

General

Our International Land operations contributed approximately 9 percent ($270.0 million) of our consolidated operating revenues during fiscal 2012, compared with approximately 9 percent ($226.8 million) of consolidated operating revenues during fiscal 2011 and 13 percent ($247.2 million) in fiscal 2010. Rig utilization in fiscal 2012 was 77 percent, 70 percent in fiscal 2011 and 71 percent in fiscal 2010.

Argentina

At the end of fiscal 2012, we had nine rigs in Argentina. Our utilization rate was approximately 52 percent during fiscal 2012, approximately 49 percent during fiscal 2011 and approximately 53 percent during fiscal 2010. Revenues generated by Argentine drilling operations contributed approximately 2 percent in both fiscal years 2012 and 2011 ($54.3 million and $44.2 million, respectively) of our consolidated operating revenues compared with approximately 3 percent of consolidated operating revenues ($55.9 million) in fiscal 2010. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 2 percent of consolidated operating revenues and approximately 20 percent of international operating revenues during fiscal 2012. The Argentine drilling contracts are primarily with large international or national oil companies.

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Colombia

At the end of fiscal 2012, we had seven rigs in Colombia. Our utilization rate was approximately 79 percent during fiscal 2012, approximately 83 percent during fiscal 2011 and approximately 71 percent during fiscal 2010. Revenues generated by Colombian drilling operations contributed approximately 3 percent in the three fiscal years 2012, 2011 and 2010 of our consolidated operating revenues ($82.2 million, $74.5 million and $57.5 million, respectively). Revenues from drilling services performed for our largest customer in Colombia totaled approximately 1 percent of consolidated operating revenues and approximately 16 percent of international operating revenues during fiscal 2012. The Colombian drilling contracts are primarily with large international or national oil companies.

Ecuador

At the end of fiscal 2012, we had five rigs in Ecuador. The utilization rate in Ecuador was 97 percent in fiscal 2012, compared to 85 percent in fiscal 2011 and 100 percent in fiscal 2010. Revenues generated by Ecuadorian drilling operations contributed approximately 2 percent in both fiscal years 2012 and 2011 ($56.4 million and $42.6 million, respectively) of consolidated operating revenues compared with approximately 3 percent in fiscal 2010 ($52.1 million) of our consolidated operating revenues. Revenues from drilling services performed for the largest customer in Ecuador totaled approximately 1 percent of consolidated operating revenues and approximately 14 percent of international operating revenues during fiscal 2012. The Ecuadorian drilling contracts are primarily with large international or national oil companies.

Other Locations

In addition to our operations discussed above, at the end of fiscal 2012 we had two rigs in Tunisia, four rigs in Bahrain and two rigs in UAE.

FINANCIAL

Information relating to revenues, total assets and operating income by reportable operating segments may be found on, and is incorporated by reference to, pages 51 through 55 of our Annual Report (Exhibit 13 to this Form 10-K).

EMPLOYEES

We had 8,147 employees within the United States (19 of which were part-time employees) and 1,282 employees in international operations as of September 30, 2012.

AVAILABLE INFORMATION

Information relating to our internet address and information relating to our Securities and Exchange Commission ("SEC") filings may be found on, and is incorporated by reference to, page 57 of our Annual Report (Exhibit 13 to this Form 10-K).

Item 1A. RISK FACTORS

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

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Our offshore and land operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.

Our drilling operations are subject to the many hazards inherent in the business, including inclement weather, blowouts, well fires, loss of well control, pollution, and reservoir damage. These hazards could cause significant environmental damage, personal injury and death, suspension of drilling operations, serious damage or destruction of equipment and property and substantial damage to producing formations and surrounding lands and waters.

Our Offshore drilling operations are also subject to potentially greater environmental liability, including pollution of offshore waters and related negative impact on wildlife and habitat, adverse sea conditions and platform damage or destruction due to collision with aircraft or marine vessels. Our Offshore operations may also be negatively affected by blowouts or uncontrolled release of oil by third parties whose offshore operations are unrelated to our operations. We operate several platform rigs in the Gulf of Mexico. The Gulf of Mexico experiences hurricanes and other extreme weather conditions on a frequent basis, the frequency of which may increase with any climate change. Damage caused by high winds and turbulent seas could potentially curtail operations on such platform rigs for significant periods of time until the damage can be repaired. Moreover, even if our platform rigs are not directly damaged by such storms, we may experience disruptions in operations due to damage to customer platforms and other related facilities in the area.

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

We have indemnification agreements with many of our customers and we also maintain liability and other forms of insurance. In general, our drilling contracts contain provisions requiring our customer to indemnify us for, among other things, pollution and reservoir damage. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts by us, our subcontractors and/or suppliers. Our customers may also dispute, or be unable to meet, their contractual indemnification obligations to us. Accordingly, we may be unable to transfer these risks to our drilling customers by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect our business, financial condition and results of operations.

With the exception of "named wind storm" risk in the Gulf of Mexico, we insure rigs and related equipment at values that approximate the current replacement cost on the inception date of the policy. However, we self-insure a large deductible as well as a significant portion of the estimated replacement cost of our offshore rigs and our land rigs and equipment. We also carry insurance with varying deductibles and coverage limits with respect to offshore platform rigs and "named wind storm" risk in the Gulf of Mexico.

We have insurance coverage for comprehensive general liability, automobile liability, worker's compensation and employer's liability, and certain other specific risks. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. We retain a significant portion of our expected losses under our worker's compensation, general liability and automobile liability programs. The Company self-insures a number of other risks including loss of earnings and business interruption. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage; however, we are generally indemnified under our drilling contracts from this risk.

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If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition and results of operations. Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes aggregate policy limits. As a result, we retain the risk for any loss in excess of these limits. No assurance can be given that all or a portion of our coverage will not be cancelled during fiscal 2013, that insurance coverage will continue to be available at rates considered reasonable or that our coverage will respond to a specific loss. Further, we may experience difficulties in collecting from our insurers or our insurers may deny all or a portion of our claims for insurance coverage.

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

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

A sluggish global economy may affect our business.

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

The contract drilling business is highly competitive.

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

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

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

In fiscal 2012, we received approximately 59 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 32 percent of our consolidated operating revenues from our three largest customers (including their affiliates). We believe that our relationship with all of these customers is good; however, the loss of one or more of our larger customers could have a material adverse effect on our business, financial condition and results of operations.

International uncertainties and local laws could adversely affect our business.

International operations are subject to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of social unrest, strikes, terrorism, kidnapping of employees, nationalization, forced negotiation or modification of contracts, expropriation of equipment as well as expropriation of a particular oil company operator's property and drilling rights, taxation policies, foreign exchange restrictions, currency rate fluctuations and general hazards associated with foreign sovereignty over certain areas in which operations are conducted. On June 30, 2010, the Venezuelan government seized 11 rigs and associated real and personal property owned by our Venezuelan subsidiary. In Argentina, general economic conditions have shown improvement and political protests and social disturbances have diminished considerably since the economic crisis of 2001 and 2002. However, the rapid and radical nature of the changes in the Argentine social, political, economic and legal environment over the past several years and the absence of a clear political consensus in favor of any particular set of economic policies have given rise to significant uncertainties about the country's economic and political future. It is currently unclear whether the economic and political instability experienced over the past several years will continue and it is possible that, despite recent economic growth, Argentina may return to a deeper recession, higher inflation and unemployment and greater social unrest. If instability persists, there could be a material adverse effect on our results of operations and financial condition.

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

Although we attempt to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2012, approximately 9 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2012, approximately 72 percent of the international operating revenues were from operations in South America. All of the South American operating revenues were from Argentina, Colombia and Ecuador.

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

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

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construction or other operations, which could have a material adverse effect on our business, financial condition and results of operations.

If our principal fabricator, located on the Texas gulf coast, was unable or unwilling to continue fabricating rig components, then we would have to transfer this work to other acceptable fabricators. This transfer could result in significant delay in the completion of new FlexRigs. Any significant interruption in the fabrication of rig components could have a material adverse impact on our business, financial condition and results of operations.

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

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

At September 30, 2012, we had a portfolio of securities with a total fair value of approximately $452 million. The fair value in Atwood Oceanics, Inc. and Schlumberger, Ltd. was $434 million at September 30, 2012. These securities are subject to a wide variety of market-related risks that could substantially reduce or increase the fair value of our holdings. Except for investments in limited partnerships carried at cost, the portfolio is recorded at fair value on our balance sheet with changes in unrealized after-tax value reflected in the equity section of our balance sheet. Subsequent to September 30, 2012, we sold our share in the limited partnerships. Any reduction in fair value would have an impact on our debt ratio and financial strength. At November 15, 2012, the fair value of the portfolio had increased to approximately $438 million.

Government regulations and environmental laws could adversely affect our business.

Many aspects of our operations are subject to government regulation, including those relating to drilling practices, pollution, disposal of hazardous substances and oil field waste. The United States and various other countries have environmental regulations which affect drilling operations. The cost of compliance with these laws could be substantial. A failure to comply with these laws and regulations could expose us to substantial civil and criminal penalties. In addition, environmental laws and regulations in the United States impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of drilling rigs, we may be deemed to be a responsible party under these laws and regulations.

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

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

Scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs") and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. We are aware of the increasing focus of local, state, national and

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international regulatory bodies on GHG emissions and climate change issues. The United States Congress may consider legislation to reduce GHG emissions. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding GHG emissions could have a material adverse impact on our business, financial condition and results of operations.

New legislation and regulatory initiatives relating to hydraulic fracturing could delay or limit the drilling services we provide to customers whose drilling programs could be impacted by such laws.

Members of the U.S. Congress and the U.S. Environmental Protection Agency, or the EPA, are reviewing more stringent regulation of hydraulic fracturing, a technology which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Both the U.S. Congress and the EPA are studying whether there is any link between hydraulic fracturing and soil or ground water contamination or any impact on public health. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have and others are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. We do not engage in any hydraulic fracturing activities. However, any new laws, regulation or permitting requirements regarding hydraulic fracturing could delay or limit the drilling services we provide to customers whose drilling programs could be impacted by new legal requirements. Widespread regulation significantly restricting or prohibiting hydraulic fracturing by our customers could have a material adverse impact on our business, financial condition and results of operation.

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

Contracts for work in foreign countries generally provide for payment in U.S. dollars; however, government-owned petroleum companies may in the future require that a greater proportion of these payments be made in local currencies. Based upon current information, we believe that our exposure to potential losses from currency devaluation in foreign countries is immaterial. However, in the event of future payments in local currencies or an inability to exchange local currencies for U.S. dollars, we may incur currency devaluation losses which could have a material adverse impact on our business, financial condition and results of operations.

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

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

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

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

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

Although we take measures to ensure that we use advanced oil and natural gas drilling technology, changes in technology or improvements in competitors' equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive. Any such changes in technology could have a material adverse effect on our business, financial condition and results of operations.

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

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

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

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

Item 1B. UNRESOLVED STAFF COMMENTS

We have received no written comments regarding our periodic or current reports from the staff of the Securities and Exchange Commission that were issued 180 days or more preceding the end of our 2012 fiscal year and that remain unresolved.

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Item 2. PROPERTIES

CONTRACT DRILLING

The following table sets forth certain information concerning our U.S. land and offshore drilling rigs as of September 30, 2012:

Location			Rig Type

FLEXRIGS
TEXAS	164	18,000	SCR (FlexRig1)	1,500
TEXAS	165	18,000	SCR (FlexRig1)	1,500
TEXAS	166	18,000	SCR (FlexRig1)	1,500
TEXAS	167	18,000	SCR (FlexRig1)	1,500
TEXAS	168	18,000	SCR (FlexRig1)	1,500
TEXAS	169	18,000	SCR (FlexRig1)	1,500
NORTH DAKOTA	179	18,000	SCR (FlexRig2)	1,500
NORTH DAKOTA	180	18,000	SCR (FlexRig2)	1,500
TEXAS	181	18,000	SCR (FlexRig2)	1,500
TEXAS	182	18,000	SCR (FlexRig2)	1,500
TEXAS	183	18,000	SCR (FlexRig2)	1,500
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	22,000	AC (FlexRig3)	1,500
TEXAS	211	22,000	AC (FlexRig3)	1,500
TEXAS	212	22,000	AC (FlexRig3)	1,500
TEXAS	213	22,000	AC (FlexRig3)	1,500
NEW MEXICO	214	22,000	AC (FlexRig3)	1,500
WYOMING	215	22,000	AC (FlexRig3)	1,500
TEXAS	216	22,000	AC (FlexRig3)	1,500
TEXAS	217	22,000	AC (FlexRig3)	1,500
TEXAS	218	22,000	AC (FlexRig3)	1,500
OKLAHOMA	219	22,000	AC (FlexRig3)	1,500
TEXAS	220	22,000	AC (FlexRig3)	1,500
TEXAS	221	22,000	AC (FlexRig3)	1,500
TEXAS	222	22,000	AC (FlexRig3)	1,500
NEW MEXICO	223	22,000	AC (FlexRig3)	1,500
OKLAHOMA	224	22,000	AC (FlexRig3)	1,500
PENNSYLVANIA	225	22,000	AC (FlexRig3)	1,500
TEXAS	226	22,000	AC (FlexRig3)	1,500
NEW MEXICO	227	22,000	AC (FlexRig3)	1,500
TEXAS	229	22,000	AC (FlexRig3)	1,500
TEXAS	231	22,000	AC (FlexRig3)	1,500
TEXAS	232	22,000	AC (FlexRig3)	1,500
TEXAS	233	22,000	AC (FlexRig3)	1,500
TEXAS	234	22,000	AC (FlexRig3)	1,500
OKLAHOMA	235	22,000	AC (FlexRig3)	1,500
CALIFORNIA	236	22,000	AC (FlexRig3)	1,500

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Location			Rig Type

TEXAS	238	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	239	22,000	AC (FlexRig3)	1,500
CALIFORNIA	240	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	241	22,000	AC (FlexRig3)	1,500
OKLAHOMA	243	22,000	AC (FlexRig3)	1,500
TEXAS	244	22,000	AC (FlexRig3)	1,500
TEXAS	245	22,000	AC (FlexRig3)	1,500
TEXAS	246	22,000	AC (FlexRig3)	1,500
TEXAS	247	22,000	AC (FlexRig3)	1,500
TEXAS	248	22,000	AC (FlexRig3)	1,500
TEXAS	249	22,000	AC (FlexRig3)	1,500
OKLAHOMA	250	22,000	AC (FlexRig3)	1,500
OKLAHOMA	251	22,000	AC (FlexRig3)	1,500
OKLAHOMA	252	22,000	AC (FlexRig3)	1,500
TEXAS	253	22,000	AC (FlexRig3)	1,500
TEXAS	254	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	255	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	256	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	257	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	258	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	259	22,000	AC (FlexRig3)	1,500
TEXAS	260	22,000	AC (FlexRig3)	1,500
CALIFORNIA	261	22,000	AC (FlexRig3)	1,500
CALIFORNIA	262	22,000	AC (FlexRig3)	1,500
TEXAS	263	22,000	AC (FlexRig3)	1,500
TEXAS	264	22,000	AC (FlexRig3)	1,500
TEXAS	265	22,000	AC (FlexRig3)	1,500
TEXAS	266	22,000	AC (FlexRig3)	1,500
TEXAS	267	22,000	AC (FlexRig3)	1,500
OKLAHOMA	268	22,000	AC (FlexRig3)	1,500
TEXAS	269	22,000	AC (FlexRig3)	1,500
WYOMING	271	18,000	AC (FlexRig4)	1,500
MONTANA	272	18,000	AC (FlexRig4)	1,500
UTAH	273	18,000	AC (FlexRig4)	1,500
TEXAS	274	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	275	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	276	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	277	18,000	AC (FlexRig4)	1,500
COLORADO	278	18,000	AC (FlexRig4)	1,500
TEXAS	279	18,000	AC (FlexRig4)	1,500
WYOMING	280	18,000	AC (FlexRig4)	1,500
TEXAS	281	8,000	AC (FlexRig4)	1,150
TEXAS	282	8,000	AC (FlexRig4)	1,150
TEXAS	283	8,000	AC (FlexRig4)	1,150
PENNSYLVANIA	284	18,000	AC (FlexRig4)	1,500
OHIO	285	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	286	18,000	AC (FlexRig4)	1,500
OHIO	287	18,000	AC (FlexRig4)	1,500
TEXAS	288	18,000	AC (FlexRig4)	1,500

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Location			Rig Type

ARKANSAS	289	18,000	AC (FlexRig4)	1,500
PENNSYLVANIA	290	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	293	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	294	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	295	18,000	AC (FlexRig4)	1,500
TEXAS	296	18,000	AC (FlexRig4)	1,500
TEXAS	297	18,000	AC (FlexRig4)	1,500
UTAH	298	18,000	AC (FlexRig4)	1,500
TEXAS	299	18,000	AC (FlexRig4)	1,500
NEW MEXICO	300	18,000	AC (FlexRig4)	1,500
TEXAS	302	8,000	AC (FlexRig4)	1,150
TEXAS	303	8,000	AC (FlexRig4)	1,150
TEXAS	304	8,000	AC (FlexRig4)	1,150
TEXAS	305	8,000	AC (FlexRig4)	1,150
TEXAS	306	8,000	AC (FlexRig4)	1,150
COLORADO	307	18,000	AC (FlexRig4)	1,500
COLORADO	308	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	309	18,000	AC (FlexRig4)	1,500
WYOMING	310	18,000	AC (FlexRig4)	1,500
WYOMING	311	18,000	AC (FlexRig4)	1,500
TEXAS	312	18,000	AC (FlexRig4)	1,500
TEXAS	313	18,000	AC (FlexRig4)	1,500
TEXAS	314	18,000	AC (FlexRig4)	1,500
COLORADO	315	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	316	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	317	18,000	AC (FlexRig4)	1,500
UTAH	318	18,000	AC (FlexRig4)	1,500
UTAH	319	18,000	AC (FlexRig4)	1,500
MONTANA	320	18,000	AC (FlexRig4)	1,500
COLORADO	321	18,000	AC (FlexRig4)	1,500
COLORADO	322	18,000	AC (FlexRig4)	1,500
COLORADO	323	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	324	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	325	18,000	AC (FlexRig4)	1,500
COLORADO	326	18,000	AC (FlexRig4)	1,500
TEXAS	327	18,000	AC (FlexRig4)	1,500
TEXAS	328	18,000	AC (FlexRig4)	1,500
NORTH DAKOTA	329	18,000	AC (FlexRig4)	1,500
COLORADO	330	18,000	AC (FlexRig4)	1,500
TEXAS	331	18,000	AC (FlexRig4)	1,500
TEXAS	332	18,000	AC (FlexRig4)	1,500
TEXAS	340	8,000	AC (FlexRig4)	1,150
TEXAS	341	18,000	AC (FlexRig4)	1,500
TEXAS	342	18,000	AC (FlexRig4)	1,500
COLORADO	343	18,000	AC (FlexRig4)	1,500
TEXAS	344	8,000	AC (FlexRig4)	1,150
TEXAS	345	8,000	AC (FlexRig4)	1,150
TEXAS	346	8,000	AC (FlexRig4)	1,150
TEXAS	347	8,000	AC (FlexRig4)	1,150

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Location			Rig Type

TEXAS	348	8,000	AC (FlexRig4)	1,150
CALIFORNIA	349	8,000	AC (FlexRig4)	1,150
TEXAS	351	8,000	AC (FlexRig4)	1,150
TEXAS	352	8,000	AC (FlexRig4)	1,150
COLORADO	353	18,000	AC (FlexRig4)	1,500
ARKANSAS	354	18,000	AC (FlexRig4)	1,500
NEW MEXICO	355	8,000	AC (FlexRig4)	1,150
OKLAHOMA	356	8,000	AC (FlexRig4)	1,150
TEXAS	360	8,000	AC (FlexRig4)	1,150
NEW MEXICO	370	22,000	AC (FlexRig3)	1,500
PENNSYLVANIA	371	22,000	AC (FlexRig3)	1,500
TEXAS	372	22,000	AC (FlexRig3)	1,500
TEXAS	373	22,000	AC (FlexRig3)	1,500
OKLAHOMA	374	22,000	AC (FlexRig3)	1,500
OKLAHOMA	375	22,000	AC (FlexRig3)	1,500
OKLAHOMA	376	22,000	AC (FlexRig3)	1,500
OKLAHOMA	377	22,000	AC (FlexRig3)	1,500
OKLAHOMA	378	22,000	AC (FlexRig3)	1,500
OKLAHOMA	379	22,000	AC (FlexRig3)	1,500
CALIFORNIA	380	22,000	AC (FlexRig3)	1,500
CALIFORNIA	381	22,000	AC (FlexRig3)	1,500
TEXAS	382	22,000	AC (FlexRig3)	1,500
TEXAS	383	22,000	AC (FlexRig3)	1,500
TEXAS	384	22,000	AC (FlexRig3)	1,500
PENNSYLVANIA	385	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	386	22,000	AC (FlexRig3)	1,500
TEXAS	387	22,000	AC (FlexRig3)	1,500
TEXAS	388	22,000	AC (FlexRig3)	1,500
TEXAS	389	22,000	AC (FlexRig3)	1,500
TEXAS	390	22,000	AC (FlexRig3)	1,500
TEXAS	391	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	392	22,000	AC (FlexRig3)	1,500
TEXAS	393	22,000	AC (FlexRig3)	1,500
TEXAS	394	22,000	AC (FlexRig3)	1,500
TEXAS	395	22,000	AC (FlexRig3)	1,500
TEXAS	396	22,000	AC (FlexRig3)	1,500
TEXAS	397	22,000	AC (FlexRig3)	1,500
TEXAS	398	22,000	AC (FlexRig3)	1,500
TEXAS	399	22,000	AC (FlexRig3)	1,500
TEXAS	415	22,000	AC (FlexRig3)	1,500
NEW MEXICO	416	22,000	AC (FlexRig3)	1,500
LOUISIANA	417	22,000	AC (FlexRig3)	1,500
TEXAS	418	22,000	AC (FlexRig3)	1,500
OKLAHOMA	419	22,000	AC (FlexRig3)	1,500
TEXAS	420	22,000	AC (FlexRig3)	1,500
TEXAS	421	22,000	AC (FlexRig3)	1,500
CALIFORNIA	422	22,000	AC (FlexRig3)	1,500
TEXAS	423	22,000	AC (FlexRig3)	1,500
CALIFORNIA	424	22,000	AC (FlexRig3)	1,500

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Location			Rig Type

OKLAHOMA	425	22,000	AC (FlexRig3)	1,500
CALIFORNIA	426	22,000	AC (FlexRig3)	1,500
OKLAHOMA	427	22,000	AC (FlexRig3)	1,500
TEXAS	428	22,000	AC (FlexRig3)	1,500
TEXAS	429	22,000	AC (FlexRig3)	1,500
TEXAS	430	22,000	AC (FlexRig3)	1,500
TEXAS	431	22,000	AC (FlexRig3)	1,500
TEXAS	432	22,000	AC (FlexRig3)	1,500
TEXAS	433	22,000	AC (FlexRig3)	1,500
TEXAS	434	22,000	AC (FlexRig3)	1,500
OKLAHOMA	435	22,000	AC (FlexRig3)	1,500
TEXAS	436	22,000	AC (FlexRig3)	1,500
TEXAS	437	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	438	22,000	AC (FlexRig3)	1,500
TEXAS	439	22,000	AC (FlexRig3)	1,500
CALIFORNIA	440	22,000	AC (FlexRig3)	1,500
TEXAS	441	22,000	AC (FlexRig3)	1,500
TEXAS	442	22,000	AC (FlexRig3)	1,500
TEXAS	443	22,000	AC (FlexRig3)	1,500
CALIFORNIA	444	22,000	AC (FlexRig3)	1,500
TEXAS	445	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	446	22,000	AC (FlexRig3)	1,500
OKLAHOMA	447	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	448	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	449	22,000	AC (FlexRig3)	1,500
OKLAHOMA	450	22,000	AC (FlexRig3)	1,500
TEXAS	451	22,000	AC (FlexRig3)	1,500
TEXAS	452	22,000	AC (FlexRig3)	1,500
TEXAS	453	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	454	22,000	AC (FlexRig3)	1,500
TEXAS	455	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	456	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	457	22,000	AC (FlexRig3)	1,500
TEXAS	458	22,000	AC (FlexRig3)	1,500
TEXAS	459	22,000	AC (FlexRig3)	1,500
TEXAS	460	22,000	AC (FlexRig3)	1,500
TEXAS	461	22,000	AC (FlexRig3)	1,500
TEXAS	462	22,000	AC (FlexRig3)	1,500
TEXAS	463	22,000	AC (FlexRig3)	1,500
TEXAS	464	22,000	AC (FlexRig3)	1,500
TEXAS	465	22,000	AC (FlexRig3)	1,500
TEXAS	466	22,000	AC (FlexRig3)	1,500
TEXAS	467	22,000	AC (FlexRig3)	1,500
TEXAS	468	22,000	AC (FlexRig3)	1,500
TEXAS	469	22,000	AC (FlexRig3)	1,500
TEXAS	470	22,000	AC (FlexRig3)	1,500
NORTH DAKOTA	471	22,000	AC (FlexRig3)	1,500
TEXAS	472	22,000	AC (FlexRig3)	1,500
TEXAS	473	22,000	AC (FlexRig3)	1,500

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Location			Rig Type

NEW MEXICO	474	22,000	AC (FlexRig3)	1,500
TEXAS	475	22,000	AC (FlexRig3)	1,500
NEW MEXICO	477	22,000	AC (FlexRig3)	1,500
TEXAS	478	22,000	AC (FlexRig3)	1,500
TEXAS	479	22,000	AC (FlexRig3)	1,500
TEXAS	480	22,000	AC (FlexRig3)	1,500
TEXAS	481	22,000	AC (FlexRig3)	1,500
TEXAS	482	22,000	AC (FlexRig3)	1,500
TEXAS	483	22,000	AC (FlexRig3)	1,500
TEXAS	485	22,000	AC (FlexRig3)	1,500
TEXAS	486	22,000	AC (FlexRig3)	1,500
TEXAS	487	22,000	AC (FlexRig3)	1,500
TEXAS	488	22,000	AC (FlexRig3)	1,500
TEXAS	494	22,000	AC (FlexRig3)	1,500
PENNSYLVANIA	500	22,000	AC (FlexRig5)	1,500
TEXAS	501	22,000	AC (FlexRig5)	1,500
TEXAS	502	22,000	AC (FlexRig5)	1,500
TEXAS	503	22,000	AC (FlexRig5)	1,500
TEXAS	504	22,000	AC (FlexRig5)	1,500
TEXAS	505	22,000	AC (FlexRig5)	1,500
TEXAS	506	22,000	AC (FlexRig5)	1,500
TEXAS	507	22,000	AC (FlexRig5)	1,500
TEXAS	508	22,000	AC (FlexRig5)	1,500
TEXAS	509	22,000	AC (FlexRig5)	1,500
TEXAS	510	22,000	AC (FlexRig5)	1,500
TEXAS	519	22,000	AC (FlexRig5)	1,500
CONVENTIONAL RIGS
LOUISIANA	122	16,000	SCR	1,700
OKLAHOMA	162	18,000	SCR	1,500
LOUISIANA	79	20,000	SCR	2,000
TEXAS	80	20,000	SCR	1,500
OKLAHOMA	89	20,000	SCR	1,500
OKLAHOMA	92	20,000	SCR	1,500
OKLAHOMA	94	20,000	SCR	1,500
OKLAHOMA	98	20,000	SCR	1,500
TEXAS	137	26,000	SCR	2,000
TEXAS	149	26,000	SCR	2,000
LOUISIANA	72	30,000	SCR	3,000
OKLAHOMA	73	30,000	SCR	3,000
TEXAS	125	30,000	SCR	3,000
LOUISIANA	134	30,000	SCR	3,000
TEXAS	136	30,000	SCR	3,000
TEXAS	157	30,000	SCR	3,000
LOUISIANA	161	30,000	SCR	3,000
LOUISIANA	163	30,000	SCR	3,000

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Location			Rig Type

OFFSHORE PLATFORM RIGS
LOUISIANA	203	20,000	Self-Erecting	2,500
GULF OF MEXICO	205	20,000	Self-Erecting	2,000
GULF OF MEXICO	206	20,000	Self-Erecting	1,500
GULF OF MEXICO	100	30,000	Conventional	3,000
GULF OF MEXICO	105	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

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

	Years ended September 30,

	2008			2009			2010			2011			2012
U.S. Land Rigs
Number of rigs at end of period		185			201			220			248			282
Average rig utilization rate during period (1)		96	%		68	%		73	%		86	%		89	%
U.S. Offshore Platform Rigs
Number of rigs at end of period		9			9			9			9			9
Average rig utilization rate during period (1)		75	%		89	%		80	%		77	%		79	%

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

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The following table sets forth certain information concerning our international drilling rigs as of September 30, 2012:

Location			Rig Type

UAE	476	22,000	AC (FlexRig3)	1,500
UAE	484	22,000	AC (FlexRig3)	1,500
Argentina	335	8,000	AC (FlexRig4)	1,150
Argentina	336	8,000	AC (FlexRig4)	1,150
Argentina	337	8,000	AC (FlexRig4)	1,150
Argentina	338	8,000	AC (FlexRig4)	1,150
Argentina	123	26,000	SCR	2,100
Argentina	175	30,000	SCR	3,000
Argentina	177	30,000	SCR	3,000
Argentina	151	30,000+	SCR	3,000
Argentina	230	22,000	AC (FlexRig3)	1,500
Bahrain	291	8,000	AC (FlexRig4)	1,150
Bahrain	292	8,000	AC (FlexRig4)	1,150
Bahrain	301	8,000	AC (FlexRig4)	1,150
Bahrain	339	8,000	AC (FlexRig4)	1,150
Colombia	333	8,000	AC (FlexRig4)	1,150
Colombia	334	8,000	AC (FlexRig4)	1,150
Colombia	237	22,000	AC (FlexRig3)	1,500
Colombia	190	26,000	SCR	2,000
Colombia	133	30,000	SCR	3,000
Colombia	139	30,000+	SCR	3,000
Colombia	152	30,000+	SCR	3,000
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
Tunisia	228	22,000	AC (FlexRig3)	1,500
Tunisia	242	22,000	AC (FlexRig3)	1,500

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

	Years ended September 30,

	2008			2009			2010			2011			2012
Number of rigs at end of period		19			33			28			24			29
Average rig utilization rate during period (1)(2)		72	%		70	%		71	%		70	%		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 the United States for major modifications and upgrades.

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STOCK PORTFOLIO

Information required by this item regarding our stock portfolio may be found on, and is incorporated by reference to, page 12 of our Annual Report (Exhibit 13 to this Form 10-K) under the caption, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Item 3. LEGAL PROCEEDINGS

1. Pending Investigation by the U.S. Attorney .

In May 2010, one of our employees reported certain possible choke manifold testing irregularities at one offshore platform rig. Operations were promptly suspended on that rig after receiving the employee's report. The Minerals Management Service (now known as the Bureau of Ocean Energy Management, Regulation and Enforcement) was promptly notified of the employee's report and it conducted an initial investigation of this matter. Upon conclusion of the initial investigation, we were permitted to resume normal operations on the rig. Also, we promptly commenced an internal investigation of the employee's allegations. Our internal investigation found that certain employees on the rig failed to follow our policies and procedures, which resulted in termination of those employees. There were no spills or discharges to the environment.

The U.S. Attorney for the Eastern District of Louisiana has commenced a grand jury investigation, which is ongoing. We received, and have complied with, a subpoena for documents in connection with that investigation. Certain of our current and former employees have been interviewed by the government or have testified before the grand jury. In late April 2011, the Company was advised that it is a subject of this investigation.

Mr. Donald Hudson, former offshore platform rig manager, pleaded guilty to one felony charge of making false statements to a federal investigator concerning his participation in the testing irregularities that were reported in May 2010. He has been sentenced to two years probation and 120 hours community service. Mr. Hudson's employment was terminated by the Company in June 2010. We continue to cooperate with this government investigation. Although we presently believe that this matter will not have a material adverse effect on the Company, we can provide no assurances as to the timing or eventual outcome of this investigation.

2. Venezuela Expropriation .

Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A. filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. ("Petroleo") and PDVSA Petroleo, S.A. ("PDVSA"). We are seeking damages for the taking of our Venezuelan drilling business in violation of international law and for breach of contract. Additionally, we are participating in one arbitration against a third party not affiliated with the Venezuelan government, Petroleo or PDVSA in an attempt to collect an aggregate $50 million relating to the seizure of our property in Venezuela. The arbitration hearing is presently scheduled for late May 2013. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery.

In the fourth fiscal quarter of 2012, we settled an arbitration dispute with a third party not affiliated with the Venezuelan government, Petroleo or PDVSA related to the seizure of our property in Venezuela. Proceeds of $7.5 million were received and recorded as discontinued operations.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

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OUR EXECUTIVE OFFICERS

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


Hans Helmerich, 54		Chairman of the Board since January 2012; Chief Executive Officer since September 2012; President and Chief Executive Officer from 1989 to September 2012; Director since 1987
John W. Lindsay, 51		President and Chief Operating Officer since September 2012; Director since September 2012; Executive Vice President and Chief Operating Officer from 2010 to September 2012; Executive Vice President, U.S. and International Operations of Helmerich & Payne International Drilling Co. from 2006 to 2012; Vice President of U.S. Land Operations of Helmerich & Payne International Drilling Co. from 1997 to 2006
Steven R. Mackey, 61		Executive Vice President, Secretary, General Counsel and Chief Administrative Officer since March 2010; Executive Vice President, Secretary and General Counsel from June 2008 to March 2010; Secretary since 1990; Vice President from 1988 to 2010; General Counsel since 1988
Juan Pablo Tardio, 47		Vice President and Chief Financial Officer since April 2010; Director of Investor Relations from January 2008 to April 2010; Manager of Investor Relations from August 2005 to January 2008

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PART II

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

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

	2011				2012

Quarter	High		Low		High		Low
First	$	49.46	$	39.65	$	60.88	$	35.58
Second		69.72		47.53		68.60		51.69
Third		70.47		57.08		55.74		38.71
Fourth		73.40		40.60		51.71		41.82

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

	Paid per Share				Total Payment

	Fiscal				Fiscal
Quarter	2011		2012		2011		2012
First	$	.06	$	.07	$	6,376,282	$	7,522,280
Second		.06		.07		6,408,617		7,548,299
Third		.06		.07		6,438,106		7,549,986
Fourth		.07		.07		7,518,604		7,428,943

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

As of November 15, 2012, there were 620 record holders of our common stock as listed by our transfer agent's records.

Item 6. SELECTED FINANCIAL DATA

The following table summarizes selected financial information and should be read in conjunction with the Consolidated Financial Statements and the Notes thereto and the related Management's Discussion and Analysis of Financial Condition and Results of Operations contained on pages 3 through 56 of our Annual Report (Exhibit 13 to this Form 10-K). Amounts for fiscal years 2008 and 2009 have been restated to reflect the Venezuelan operations as discontinued operations. Refer to Part I, Item 1 above for additional information regarding discontinued operations.

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Five-year Summary of Selected Financial Data

	2008		2009			2010			2011			2012

	(in thousands except per share amounts)
Operating revenues	$	1,869,371	$	1,843,740		$	1,875,162		$	2,543,894		$	3,151,802
Income from continuing operations		420,258		380,546			286,081			434,668			573,609
Income (loss) from discontinued operations		41,480		(27,001	)		(129,769	)		(482	)		7,436
Net Income		461,738		353,545			156,312			434,186			581,045
Basic earnings per share from continuing operations		4.02		3.61			2.70			4.06			5.35
Basic earnings (loss) per share from discontinued operations		0.40		(0.26	)		(1.23	)		—			0.07
Basic earnings per share		4.42		3.35			1.47			4.06			5.42
Diluted earnings per share from continuing operations		3.93		3.56			2.66			3.99			5.27
Diluted earnings (loss) per share from discontinued operations		0.39		(0.25	)		(1.21	)		—			0.07
Diluted earnings per share		4.32		3.31			1.45			3.99			5.34
Total assets*		3,588,045		4,161,024			4,265,370			5,003,891			5,721,085
Long-term debt		475,000		420,000			360,000			235,000			195,000
Cash dividends declared per common share		0.1850		0.2000			0.2200			0.2600			0.2800

*: Total assets for all years include amounts related to discontinued operations.

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

Information required by this item may be found on, and is incorporated by reference to, pages 3 through 17 of our Annual Report (Exhibit 13 to this Form 10-K) under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information required by this item may be found under the caption "Risk Factors" beginning on page 6 of this Form 10-K and on, and is incorporated by reference to, the following pages of our Annual Report (Exhibit 13 to this Form 10-K) under Management's Discussion and Analysis of Financial Condition and Results of Operations and in the Notes to Consolidated Financial Statements:

Market Risk		Page

• Foreign Currency Exchange Rate Risk			16
• Commodity Price Risk			16
• Interest Rate Risk			16-17
• Equity Price Risk			17

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information required by this item may be found on, and is incorporated by reference to, pages 19 through 56 of our Annual Report (Exhibit 13 to this Form 10-K).

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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 Form 10-K, our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of September 30, 2012. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that:

•: our disclosure controls and procedures are effective at ensuring that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and
•: our disclosure controls and procedures operate such that important information flows to appropriate collection and disclosure points in a timely manner and are effective to ensure that such information is accumulated and communicated to our management, and made known to our Chief Executive Officer and Chief Financial Officer, particularly during the period when this Form 10-K was prepared, as appropriate to allow timely decision regarding the required disclosure.

b): Management's Report on Internal Control over Financial Reporting.

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

(i): pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
(ii): provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and the Board of Directors; and
(iii): provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

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

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of internal control over financial

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reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Although there are inherent limitations in the effectiveness of any system of internal control over financial reporting, based on this evaluation, management has concluded that our internal control over financial reporting was effective as of September 30, 2012.

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

c): Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during our fourth fiscal quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

* * *

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Report of Independent Registered Public Accounting Firm

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

We have audited Helmerich & Payne, Inc.'s internal control over financial reporting as of September 30, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Helmerich & Payne, Inc.'s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, Helmerich & Payne, Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2012, 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, 2012 and 2011 and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2012 and our report dated November 21, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
November 21, 2012

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Item 9B. OTHER INFORMATION

None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated herein by reference to the material under the captions "Proposal 1—Election of Directors," "Corporate Governance" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2013, to be filed with the SEC not later than 120 days after September 30, 2012. Information required under this item with respect to executive officers under Item 401 of Regulation S-K appears under "Our Executive Officers" in Part I of this Form 10-K.

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

Item 11. EXECUTIVE COMPENSATION

The information required by this item regarding executive compensation, as well as director compensation and compensation committee interlocks and insider participation is incorporated herein by reference to the material beginning with the caption "Executive Compensation Discussion and Analysis" and ending with the caption "Potential Payments Upon Termination", as well as under the captions "Director Compensation in Fiscal 2012" and "Compensation Committee Interlocks and Insider Participation" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2013, to be filed with the SEC not later than 120 days after September 30, 2012.

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

The information required by this item is incorporated herein by reference to the material under the captions "Summary of All Existing Equity Compensation Plans," "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Management" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2013, to be filed with the SEC not later than 120 days after September 30, 2012.

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

The information required by this item is incorporated herein by reference to the material under the captions "Transactions With Related Persons, Promoters and Certain Control Persons" and "Corporate Governance" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2013, to be filed with the SEC not later than 120 days after September 30, 2012.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated herein by reference to the material under the caption "Audit Fees" in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 6, 2013, to be filed with the SEC not later than 120 days after September 30, 2012.

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PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a): 1. Financial Statements : The following appear in our Annual Report to Stockholders (Exhibit 13 to this Form 10-K) on the pages indicated below and are incorporated herein by reference:

		Page

Report of Independent Registered Public Accounting Firm			18
Consolidated Statements of Income for the Years Ended September 30, 2012, 2011 and 2010			19
Consolidated Balance Sheets at September 30, 2012 and 2011			20-21
Consolidated Statements of Shareholders' Equity for the Years Ended September 30, 2012, 2011 and 2010			22
Consolidated Statements of Cash Flows for the Years Ended September 30, 2012, 2011 and 2010			23
Notes to Consolidated Financial Statements			24-56

2.: Financial Statement Schedules : All schedules are omitted as inapplicable or because the required information is contained in the financial statements or included in the notes thereto.
3.: Exhibits . The following documents are included as exhibits to this Form 10-K. Exhibits incorporated by reference are duly noted as such.


			3.1		Amended and Restated Certificate of Incorporation of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 3.1 of the Company's Form 8-K filed on March 14, 2012, SEC File No. 001-04221.
			3.2		Amended and Restated By-laws of Helmerich & Payne, Inc. are incorporated herein by reference to Exhibit 3.2 of the Company's Form 8-K filed on March 14, 2012, 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 Exhibit 1 of the Company's Form 8-K filed on January 18, 1996, SEC File No. 001-04221.
			4.2		Amendment to Rights Agreement dated December 8, 2005, between the Company and UMB Bank, N.A. is incorporated herein by reference to Exhibit 4 of the Company's Form 8-K filed on December 12, 2005, SEC File No. 001-04221.
			*10.1		Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Appendix "A" of the Company's Proxy Statement on Schedule 14A filed on January 26, 2001.
			*10.2		2012-1 Amendment to Helmerich & Payne, Inc. 2000 Stock Incentive Plan 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 March 31, 2012, SEC File No. 001-04221.

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			*10.3		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.
			*10.4		Form of Director Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.
			*10.5		Form of Change of Control Agreement for Helmerich & Payne, Inc. is incorporated herein by reference to Exhibits 10.2 and 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.
			10.6		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.
			10.7		Note Purchase Agreement dated as of June 15, 2009, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various Note purchasers is incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed on July 21, 2009, SEC File No. 001-04221.
			10.8		Credit Agreement dated May 25, 2012, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association is incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed on May 31, 2012, SEC File No. 001-04221.
			10.9		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.
			10.10		First Amendment to Lease between ASP, Inc. and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on May 29, 2008, SEC File No. 001-04221.
			10.11		Second Amendment to Office Lease dated December 13, 2011, between ASP, Inc. and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of Form 8-K filed by the Company on December 14, 2011, SEC File No. 001-04221.
			10.12		Third Amendment to Office Lease dated September 5, 2012, between ASP, Inc. and Helmerich & Payne, Inc.

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			*10.13		Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference to Exhibit 10.4 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended March 31, 2012, SEC File No. 001-04221.
			*10.14		Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan is incorporated herein by reference to Appendix "A" to the Company's Proxy Statement on Schedule 14A filed January 26, 2006.
			*10.15		2012-1 Amendment to Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan is incorporated herein by reference to Exhibit 10.6 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended March 31, 2012, SEC File No. 001-04221.
			*10.16		Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
			*10.17		Form of Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executives: Nonqualified Stock Option Agreement, Incentive Stock Option Agreement, and Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.3 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
			*10.18		Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executive officers are incorporated herein by reference to Exhibit 10.4 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
			*10.19		Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executive officers are incorporated herein by reference to Exhibit 10.5 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
			*10.20		Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan is incorporated herein by reference to Appendix "A" of the Company's Proxy Statement on Schedule 14A filed on January 26, 2011.
			*10.21		Form of Agreements for Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Award Agreement and (ii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on March 14, 2012, SEC File No. 001-04221.

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			*10.22		Form of Agreements for the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to participants other than certain executives: (i) Nonqualified Stock Option Award Agreement and (ii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on March 14, 2012, SEC File No. 001-04221.
			*10.23		Form of Agreements for the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to Directors: (i) Nonqualified Stock Option Award Agreement and (ii) Restricted Stock Award Agreement are incorporated by reference to Exhibit 10.3 of the Company's Form 8-K filed on March 14, 2012, SEC File No. 001-04221.
			10.24		Fabrication Contract between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 7, 2006, SEC File No. 001-04221.
			10.25		Contract dated July 18, 2007, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on July 18, 2007, SEC File No. 001-04221.
			10.26		Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.33 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221.
			10.27		Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.34 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221.
			10.28		Second Amendment to Contract dated March 26, 2010, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.24 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2011, SEC File No. 001-04221.
			10.29		Second Amendment to Contract dated March 26, 2010, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.25 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2011, SEC File No. 001-04221.
			10.30		Third Amendment to Contract dated August 4, 2011, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.26 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2011, SEC File No. 001-04221.

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			10.31		Third Amendment to Contract dated August 4, 2011, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.27 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2011, SEC File No. 001-04221.
			*10.32		Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
			*10.33		Supplemental Savings Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
			*10.34		Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
			13.		The Company's Annual Report to Stockholders for fiscal 2012.
			21.		List of Subsidiaries of the Company.
			23.1		Consent of Independent Registered Public Accounting Firm.
			31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
			32.		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
			101.		Financial statements from the annual report on Form 10-K of Helmerich & Payne, Inc. for the fiscal year ended September 30, 2012, filed on November 21, 2012, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Shareholders' Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements.

*: Management or Compensatory Plan or Arrangement.

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SIGNATURES

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


HELMERICH & PAYNE, INC.
By		/s/ HANS HELMERICH Hans Helmerich, Chief Executive Officer Date: November 21, 2012

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


By	/s/ WILLIAM L. ARMSTRONG William L. Armstrong, Director Date: November 21, 2012	By	/s/ RANDY A. FOUTCH Randy A. Foutch, Director Date: November 21, 2012
By	/s/ HANS HELMERICH Hans Helmerich, Director & CEO Date: November 21, 2012	By	/s/ JOHN W. LINDSAY John W. Lindsay, Director & President Date: November 21, 2012
By	/s/ PAULA MARSHALL Paula Marshall, Director Date: November 21, 2012	By	/s/ THOMAS A. PETRIE Thomas A. Petrie, Director Date: November 21, 2012
By	/s/ DONALD F. ROBILLARD, JR. Donald F. Robillard, Jr., Director Date: November 21, 2012	By	/s/ FRANCIS ROONEY Francis Rooney, Director Date: November 21, 2012
By	/s/ EDWARD B. RUST, JR. Edward B. Rust, Jr., Director Date: November 21, 2012	By	/s/ JOHN D. ZEGLIS John D. Zeglis, Director Date: November 21, 2012
By	/s/ JUAN PABLO TARDIO Juan Pablo Tardio (Principal Financial Officer) Date: November 21, 2012	By	/s/ GORDON K. HELM Gordon K. Helm (Principal Accounting Officer) Date: November 21, 2012

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Exhibit Index

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

Exhibit No.			Description

	3.1		Amended and Restated Certificate of Incorporation of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 3.1 of the Company's Form 8-K filed on March 14, 2012, SEC File No. 001-04221.
	3.2		Amended and Restated By-laws of Helmerich & Payne, Inc. are incorporated herein by reference to Exhibit 3.2 of the Company's Form 8-K filed on March 14, 2012, 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 Exhibit 1 of the Company's Form 8-K filed on January 18, 1996, SEC File No. 001-04221.
	4.2		Amendment to Rights Agreement dated December 8, 2005, between the Company and UMB Bank, N.A. is incorporated herein by reference to Exhibit 4 of the Company's Form 8-K filed on December 12, 2005, SEC File No. 001-04221.
	*10.1		Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Appendix "A" of the Company's Proxy Statement on Schedule 14A filed on January 26, 2001.
	*10.2		2012-1 Amendment to Helmerich & Payne, Inc. 2000 Stock Incentive Plan 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 March 31, 2012, SEC File No. 001-04221.
	*10.3		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.
	*10.4		Form of Director Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.
	*10.5		Form of Change of Control Agreement for Helmerich & Payne, Inc. is incorporated herein by reference to Exhibits 10.2 and 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.
	10.6		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.

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Exhibit No.			Description

	10.7		Note Purchase Agreement dated as of June 15, 2009, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and various Note purchasers is incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed on July 21, 2009, SEC File No. 001-04221.
	10.8		Credit Agreement dated May 25, 2012, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association is incorporated by reference to Exhibit 10.1 of the Company's Form 8-K filed on May 31, 2012, SEC File No. 001-04221.
	10.9		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.
	10.10		First Amendment to Lease between ASP, Inc. and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on May 29, 2008, SEC File No. 001-04221.
	10.11		Second Amendment to Office Lease dated December 13, 2011, between ASP, Inc. and Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of Form 8-K filed by the Company on December 14, 2011, SEC File No. 001-04221.
	10.12		Third Amendment to Office Lease dated September 5, 2012, between ASP, Inc. and Helmerich & Payne, Inc.
	*10.13		Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference to Exhibit 10.4 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended March 31, 2012, SEC File No. 001-04221.
	*10.14		Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan is incorporated herein by reference to Appendix "A" to the Company's Proxy Statement on Schedule 14A filed January 26, 2006.
	*10.15		2012-1 Amendment to Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan is incorporated herein by reference to Exhibit 10.6 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended March 31, 2012, SEC File No. 001-04221.
	*10.16		Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
	*10.17		Form of Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executives: Nonqualified Stock Option Agreement, Incentive Stock Option Agreement, and Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.3 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.

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Exhibit No.			Description

	*10.18		Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executive officers are incorporated herein by reference to Exhibit 10.4 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
	*10.19		Form of Amendment to Nonqualified Stock Option Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executive officers are incorporated herein by reference to Exhibit 10.5 of the Company's Form 8-K filed on December 7, 2009, SEC File No. 001-04221.
	*10.20		Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan is incorporated herein by reference to Appendix "A" of the Company's Proxy Statement on Schedule 14A filed on January 26, 2011.
	*10.21		Form of Agreements for Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Award Agreement and (ii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on March 14, 2012, SEC File No. 001-04221.
	*10.22		Form of Agreements for the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to participants other than certain executives: (i) Nonqualified Stock Option Award Agreement and (ii) Restricted Stock Award Agreement are incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on March 14, 2012, SEC File No. 001-04221.
	*10.23		Form of Agreements for the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to Directors: (i) Nonqualified Stock Option Award Agreement and (ii) Restricted Stock Award Agreement are incorporated by reference to Exhibit 10.3 of the Company's Form 8-K filed on March 14, 2012, SEC File No. 001-04221.
	10.24		Fabrication Contract between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on December 7, 2006, SEC File No. 001-04221.
	10.25		Contract dated July 18, 2007, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on July 18, 2007, SEC File No. 001-04221.
	10.26		Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.33 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221.
	10.27		Amendment to Contract dated August 8, 2008, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.34 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2008, SEC File No. 001-04221.
	10.28		Second Amendment to Contract dated March 26, 2010, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.24 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2011, SEC File No. 001-04221.

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Exhibit No.			Description

	10.29		Second Amendment to Contract dated March 26, 2010, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.25 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2011, SEC File No. 001-04221.
	10.30		Third Amendment to Contract dated August 4, 2011, between Helmerich & Payne International Drilling Co. and Southeast Texas Industries, Inc. is incorporated herein by reference to Exhibit 10.26 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2011, SEC File No. 001-04221.
	10.31		Third Amendment to Contract dated August 4, 2011, between Helmerich & Payne International Drilling Co. and Southeast Texas Industrial Services, Inc. is incorporated herein by reference to Exhibit 10.27 of the Company's Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 2011, SEC File No. 001-04221.
	*10.32		Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
	*10.33		Supplemental Savings Plan for Salaried Employees of Helmerich & Payne, Inc. is incorporated herein by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
	*10.34		Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended December 31, 2008, SEC File No. 001-04221.
	13.		The Company's Annual Report to Stockholders for fiscal 2012.
	21.		List of Subsidiaries of the Company.
	23.1		Consent of Independent Registered Public Accounting Firm.
	31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101.		Financial statements from the annual report on Form 10-K of Helmerich & Payne, Inc. for the fiscal year ended September 30, 2012, filed on November 21, 2012, formatted in XBRL: (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Shareholders' Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements.

*: Management or Compensatory Plan or Arrangement.

Exhibit 10.12

THIRD AMENDMENT TO OFFICE LEASE

This Third Amendment to Office Lease (this “Third Amendment”) is made and entered into by and between ASP, Inc., the managing partner of Boulder Tower Tenants in Common (“Landlord”), and HELMERICH & PAYNE, INC., a Delaware Corporation (the “Tenant”), effective on and as of the date on which Tenant executes this Third Amendment, as set forth on the signature page (the “Effective Date”).

W I T N E S SETH

WHEREAS, Landlord and Tenant previously entered into that certain Office Lease dated May 30, 2003, as amended by First Amendment to the Lease dated May 23, 2008 and Second Amendment to Lease dated December 13, 2011 (“Lease” ), pursuant to which Landlord leases to Tenant certain premises totaling 168,868 rentable square feet in the building commonly known as Boulder Towers (the “Building”) , located at 1437 South Boulder, Tulsa, Oklahoma 74119 (the “Existing Premises”) ; and

WHEREAS, Landlord and Tenant desire to expand the Premises, amend certain other terms of the Lease, and provide lease terms for the Fourth Amendment to Office Lease, all as more particularly provided hereinbelow;

NOW, THEREFORE, pursuant to the foregoing, and in consideration of the mutual covenants and agreements contained in the Lease and herein, the Lease is hereby modified and amended as set out below:

1. Definitions . All capitalized terms used herein shall have the same meaning as defined in the Lease, unless otherwise defined in this Third Amendment. The recitals above are incorporated herein by reference.

2. Expansion Space . Landlord and Tenant hereby confirm, stipulate and agree that, effective October 1, 2012 (or at such earlier time as Tenant occupies the Sixth Floor Expansion Space), the Existing Premises shall be expanded to include an additional 4,709 contiguous rentable square feet of office space (the “Sixth Floor Expansion Space”) as described on Exhibit “A” attached hereto. Except as otherwise provided in paragraph five of this Third Amendment, the term for the Sixth Floor Expansion Space shall expire on the later of March 31, 2015 or 30 days after substantial completion of Tenant improvements in the office space covered by the Fourth Amendment to Office Lease. The Annual Rental for the Sixth Floor Expansion Space payable by Tenant under the Lease shall be as follows:

Square Footage	Price/RSF		Annual Rent		Monthly Installment
4,709	$	12.00	$	56,508.00	$	4,709.00

Landlord shall deliver the Sixth Floor Expansion Space “AS IS” in its current condition except as follows:

On or before September 1, 2012, Landlord, at its sole cost, shall (i) replace all cracked window film on exterior windows and (ii) install “cool white” lamps in the space outlined in red on the attached Exhibit “A”.

Tenant may, at its sole cost, remodel any portion of the Sixth Floor Expansion Space other than the primary entrance and existing reception area, with Landlord’s written approval which shall not be unreasonably withheld. With the Sixth Floor Expansion Space, the total rentable square feet of the

Leased Premises is 173,577 rentable square feet and the total rentable area of the Building is 521,802 rentable square feet.

3. Parking . With respect to the Sixth Floor Expansion Space, Landlord shall provide Tenant with fourteen (14) parking spaces, including two (2) reserved covered spaces in the attached parking structure and twelve (12) on a non-reserved basis on the existing surface lots. After giving effect to the preceding sentence, Tenant shall have a total of four-hundred sixty-seven (467) parking spaces, which shall consist of one hundred twelve (112) reserved covered spaces in the attached parking structure and three hundred fifty-five (355) on a non-reserved basis on the existing surface lots. These spaces are free of charge. At the end of the lease term for the Sixth Floor Expansion Space the reserved parking spaces and the non-reserved parking spaces attributable thereto shall be surrendered along with the Sixth Floor Expansion Space.

4. Tenant’s Share and Operating Expense Base . Tenant’s Share attributable to the Sixth Floor Expansion Space shall be 0.90%. Tenant’s Share attributable to the entire Leased Premises after the addition of the Sixth Floor Expansion Space shall be 33.26%; provided, however, with respect to the Sixth Floor Expansion Space, Tenant shall pay no Operating Expenses for calendar 2012. The Operating Expense Base for the Sixth Floor Expansion Space shall mean the amount of Operating Expenses for the calendar year 2012. The 5% cap on increases in Tenant’s Share attributable to the Sixth Floor Expansion Space as to increases in Operating Expenses, as set forth in Section 4.02(g) of the H&P Lease, shall be applicable to the Sixth Floor Expansion Space and Tenant’s Share shall be made in reference to the base amount established in 2013.

5. Eighth Floor Space . The parties hereto acknowledge that Suite 850 (west wing of eighth floor) of the Building, which contains 6,319 rentable square feet, is presently leased to another tenant (“Existing Tenant”) through July 31, 2014 (the “Eighth Floor Space”). The Landlord and Tenant agree to cause their duly authorized representatives to execute the Fourth Amendment to Office Lease in form identical to Exhibit “B” on the later of August 1, 2014 or the date that the Existing Tenant vacates the Eighth Floor Space subject to the terms of this paragraph 5. In the event the Existing Tenant holds over past July 31, 2014, Landlord shall use its best efforts to vacate the Existing Tenant from the Eighth Floor Space. In the event Landlord is unable to vacate Existing Tenant from the Eighth Floor space by December 31, 2014, then Tenant shall have the continuing right thereafter, upon written notice, to terminate its obligation to lease the Eighth Floor Space, provided that such notice is received by Landlord prior to the vacation of Existing Tenant from the Eighth Floor Space. If Tenant terminates its obligation to lease the Eighth Floor Space as described above, then Tenant shall have 60 days from the date of its termination notice to provide Landlord its written election to extend the term of this Third Amendment.

Notwithstanding anything to the contrary in this Third Amendment, Tenant shall have the right to provide Landlord its written election to extend the term of this Third Amendment conditional upon Landlord receiving such election on or before January 31, 2015. In the event that Tenant elects to extend this Third Amendment as described in this paragraph 5, the (i) per square foot rent and lease term then applicable to the Existing Premises shall also apply to the Sixth Floor Expansion Space and (ii) Landlord will provide Tenant a $9.60 per square foot Tenant Improvement Allowance totaling $45,206.40 to reduce the cost of Tenant Improvements to be constructed in the Leased Premises (in the manner set forth in Exhibit “B” of the Lease).

6. Authority . Each of Landlord and Tenant represents and warrants to the other that the execution, delivery and performance of this Third Amendment by such party is within the requisite power of such party, has been duly authorized and is not in contravention of the terms of such party’s organizational or governmental documents.

7. Binding Effect . Each of Landlord and Tenant further represents and warrants to the other that this Third Amendment, when duly executed and delivered, will constitute a legal, valid, and binding obligation of Tenant, Landlord and all owners of the Building, fully enforceable in accordance with its respective terms, except as may be limited by bankruptcy, moratorium, arrangement, receivership, insolvency, reorganization or similar laws affecting the rights of creditors generally and the availability of specific performance or other equitable remedies.

8. Successors and Assigns . This Third Amendment will be binding on the parties’ successors and assigns.

9. Brokers . Tenant warrants that it has had no dealings with any broker or agent other than CB Richard Ellis/Oklahoma (the “Broker” ) in connection with the negotiation or execution of this Third Amendment. Landlord shall indemnify and hold Tenant harmless from and against any cost, expense or liability for commissions or other compensation or charges of Broker. Tenant agrees to indemnify Landlord and hold Landlord harmless from and against any and all costs, expenses or liability for commissions or other compensations or charges claimed to be owed by Tenant to any broker or agent, other than Broker, with respect to this Third Amendment or the transactions evidenced hereby.

10. Amendments . With the exception of those terms and conditions specifically modified and amended herein, the Lease shall remain in full force and effect in accordance with all its terms and conditions. In the event of any conflict between the terms and provisions of this Third Amendment and the terms and provisions of the Lease, the terms and provisions of this Third Amendment shall supersede and control.

11. Counterparts . This Third Amendment may be executed in any number of counterparts, each of which shall be deemed an original, and all of such counterparts shall constitute one agreement. To facilitate execution of this Third Amendment, the parties may execute and exchange facsimile counterparts of the signature pages and facsimile counterparts shall serve as originals.

12. Disclosure . Members of the Boulder Towers Tenants in Common are licensed real estate brokers in the State of Oklahoma and are affiliated with Commercial Realty, LLC dba CB Richard Ellis|Oklahoma; they are also partners in Boulder Towers Tenants in Common, the Landlord.

[SIGNATURE PAGE TO FOLLOW]

IN WITNESS WHEREOF, the parties hereto have executed this Third Amendment to be effective as of the day and year as set forth above.

		LANDLORD:

		By: ASP, Inc.

		Managing Partner of
		Boulder Towers Tenants in Common


		By:
		Name: William H. Mizener
		Title: President
		Date Executed:


		Helmerich & Payne, Inc.


		By:
		Name: Steven R. Mackey
		Title: Executive Vice President
		Date Executed:

Exhibit “X”

[insert space diagram]

Suite 660, 6 th Floor
4,709 Total RSF

Exhibit “B”

To Third Amendment to Office Lease

FOURTH AMENDMENT TO OFFICE LEASE

This Fourth Amendment to Office Lease (this “Fourth Amendment”) is made and entered into by and between ASP, Inc., the managing partner of Boulder Tower Tenants in Common (“Landlord”), and HELMERICH & PAYNE, INC., a Delaware Corporation (the “Tenant”), effective on and as of the date on which Tenant executes this Fourth Amendment, as set forth on the signature page (the “Effective Date”).

W I T N E S SETH

WHEREAS, Landlord and Tenant previously entered into that certain Office Lease dated May 30, 2003 , as amended by that certain First Amendment to the Lease dated as of May 23, 2008 and Second Amendment to Lease dated December 13, 2011 (“Lease”) ; pursuant to which Landlord leases to Tenant certain premises totaling 168,868 rentable square feet in the building commonly known as Boulder Towers (the “Building”), located at 1437 South Boulder, Tulsa, Oklahoma 74119 (the “Existing Premises”); and

WHEREAS, Landlord and Tenant entered into a Third Amendment to Office Lease dated August of 2012 (“Third Amendment”) to which this Fourth Amendment to Office Lease (“Fourth Amendment”) was attached as Exhibit “B”.

WHEREAS, the Third Amendment terminated simultaneously with the Landlord and Tenant’s execution of this Fourth Amendment.

WHEREAS, Landlord and Tenant desire to expand the Premises, and amend certain other terms of the Lease, all as more particularly provided hereinbelow;

NOW, THEREFORE, pursuant to the foregoing, and in consideration of the mutual covenants and agreements contained in the Lease and herein, the Lease is hereby modified and amended as set out below:

1. Definitions. All capitalized terms used herein shall have the same meaning as defined in the Lease, unless otherwise defined in this Fourth Amendment.

2. Expansion Space . Landlord and Tenant hereby confirm, stipulate and agree that the Existing Premises shall be expanded as of the Term Commencement Date (“TCD”), to include an additional 6,319 rentable square feet of office space (the “Eighth Floor Expansion Space”) as described on Exhibit “A” attached hereto.

With such Eighth Floor Expansion Space, the total rentable square feet of the Leased Premises is 175,187 rentable square feet and the total rentable area of the Building is 521,802 rentable square feet.

3. Tenant’s Share and Operating Expense Base . Tenant’s Share attributable to the Expansion Space shall be 1.21%. Tenant’s Share attributable to the entire Leased Premises after the addition on the TCD of the Expansion Space shall be 33.57%; provided however, with respect to the Expansion Space, Tenant shall pay no Operating Expenses for calendar 2014 or for that portion of calendar 2015 prior to the TCD. The Operating Expense Base for the Expansion Space shall mean the amount of Operating Expenses for the calendar year 2015. From and after the TCD, the 5% cap on increases in Tenant’s Share attributable to the Expansion Space as to increases in Operating Expenses, as set for the in Section 4.02(g) of the H&P Lease, shall be applicable to the Expansion Space and Tenant’s Share shall be made in reference to the base amount established in 2015.

4. Rent and Term . The per square foot rental rate and lease term applicable to the Existing Premises on the TCD shall also apply to the Eighth Floor Expansion Space. The Rent for the Eighth Floor Expansion Space shall commence on the earlier of Substantial Completion or ninety (90) days after Landlord delivers the space to Tenant.

5. Tenant Improvement Allowance . The Landlord shall provide Tenant a $10.66 per rentable square foot Tenant Improvement Allowance totaling $67,361.00 to reduce the cost of Tenant Improvements to be constructed in the Expansion Space (in the same manner as set forth in Exhibit B of the Lease), inclusive of demolition, above ceiling modification, preliminary space planning and construction documents and construction. Landlord shall timely pay the cost of Tenant Improvements up to the amount of the Tenant Improvement Allowance. In the event that the total cost of Tenant Improvements is less than the Tenant Improvement Allowance, then the balance shall be used by Tenant to improve any area of the Leased Premises as long as the improvements are completed within two (2) years from the TCD. In the event that the total cost of Tenant Improvements is more than the Tenant Improvement Allowance, then Tenant shall pay such excess costs when such amounts become due and owing to the contractors.

6. Parking . With respect to the Expansion Space, the Landlord shall provide Tenant nineteen (19) parking spaces, including three (3) reserved covered spaces in the attached parking structure and sixteen (16) on a non-reserved basis on the existing surface lots. As of the TCD, Tenant shall have a total of four hundred seventy-two (472) parking spaces, which shall consist of one hundred thirteen (113) reserved covered spaces in the attached parking structure and three hundred fifty-nine (359) on a non-reserved basis on the existing surface lots. These spaces are free of charge. Notwithstanding the foregoing, in the event Tenant elects to extend the term of the Sixth Floor Expansion Space as described in paragraph 5 of the Third Amendment to Office Lease, then Tenant shall possess a total of four hundred eighty-six (486) parking spaces, including one hundred fifteen (115) reserved covered spaces in the attached parking structure and three hundred seventy-one (371) on a non-reserved basis on the existing surface lots.

7. Authority . Each of Landlord and Tenant represents and warrants to the other that the execution, delivery and performance of this Fourth Amendment by such party is within the requisite power of such party, has been duly authorized and is not in contravention the terms of such party’s organizational or governmental documents.

8. Binding Effect . Each of Landlord and Tenant further represents and warrants to the other that this Fourth Amendment, when duly executed and delivered, will constitute a legal, valid, and binding obligation of Tenant, Landlord and all owners of the Building, fully enforceable in accordance with its respective terms, except as may be limited by bankruptcy, moratorium, arrangement,

receivership, insolvency, reorganization or similar laws affecting the rights of creditors generally and the availability of specific performance or other equitable remedies.

9. Successors and Assigns . This Fourth Amendment will be binding on the parties’ successors and assigns.

10. Brokers . Tenant warrants that it has had no dealings with any broker or agent other than CB Richard Ellis/Oklahoma (the “Broker”) in connection with the negotiation or execution of this Fourth Amendment. Landlord shall indemnify and hold Tenant harmless from and against any cost, expenses or liability for commissions or other compensation or charges of Broker. Tenant agrees to indemnify Landlord and hold Landlord harmless from and against any and all costs, expenses or liability for commissions or other compensations or charges claimed to be owed by Tenant to any broker or agent, other than Broker, with respect to this Fourth Amendment or the transactions evidenced hereby.

11. Amendments . With the exception of those terms and conditions specifically modified and amended herein, the Lease shall remain in full force and effect in accordance with all its terms and conditions. In the event of any conflict between the terms and provisions of this Fourth Amendment and the terms and provisions of the Lease, the terms and provisions of this Fourth Amendment shall supersede and control.

12. Counterparts . This Fourth Amendment may be executed in any number of counterparts, each of which shall be deemed an original, and all of such counterparts shall constitute one agreement. To facilitate execution of this Fourth Amendment, the parties may execute and exchange facsimile counterparts of the signature pages and facsimile counterparts shall serve as originals.

13. Disclosure . Members of the Boulder Towers Tenants in Common are licensed real estate brokers in the State of Oklahoma and are affiliated with Commercial Realty, LLC dba CB Richard Ellis|Oklahoma; they are also partners in Boulder Towers Tenants in Common, the Landlord.

[SIGNATURE PAGE TO FOLLOW]

IN WITNESS WHEREOF, the parties hereto have executed this Fourth Amendment to be effective as of the day and year as set forth above.

		LANDLORD:

		By: ASP, Inc.

		Managing Partner of
		Boulder Towers Tenants in Common


		By:
		Name: William H. Mizener
		Title: President
		Date Executed:


		Helmerich & Payne, Inc.


		By:
		Name: Steven R. Mackey
		Title: Executive Vice President
		Date Executed:

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Exhibit 13

Helmerich & Payne, Inc.

Helmerich & Payne, Inc. is the holding Company for Helmerich & Payne International Drilling Co., a drilling contractor with land and offshore operations in the United States, South America, Africa and the Middle East. Holdings also include commercial real estate properties in the Tulsa, Oklahoma area, and an energy-weighted portfolio of securities valued at approximately $452 million as of September 30, 2012.

FINANCIAL HIGHLIGHTS

	Years Ended September 30,

	2012		2011		2010
	(in thousands, except per share amounts)
Operating Revenues	$	3,151,802	$	2,543,894	$	1,875,162
Net Income		581,045		434,186		156,312
Diluted Earnings per Share		5.34		3.99		1.45
Dividends Paid per Share		.280		.250		.210
Capital Expenditures		1,097,680		694,264		329,572
Total Assets		5,721,085		5,003,891		4,265,370

Financial & Operating Review
HELMERICH & PAYNE, INC.

	Years Ended September 30,

	2012		2011		2010		2009		2008		2007		2006		2005		2004			2003		2002
SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*†
Operating Revenues	$	3,151,802	$	2,543,894	$	1,875,162	$	1,843,740	$	1,869,371	$	1,502,380	$	1,140,219	$	733,902	$	532,759		$	472,407	$	472,865
Operating Costs, excluding depreciation		1,750,510		1,432,602		1,071,959		944,780		987,838		788,967		606,945		435,057		375,600			322,553		319,330
Depreciation**		387,549		315,468		262,658		227,535		195,343		137,187		93,363		88,483		139,591			76,748		56,208
General and Administrative Expense		107,307		91,452		81,479		58,822		56,429		47,401		51,873		41,015		37,661			41,003		36,563
Operating Income (Loss)		909,599		702,511		451,796		608,875		640,084		586,506		395,341		182,355		(14,698	)		35,845		61,946
Interest and Dividend Income		1,380		1,951		1,811		2,755		3,524		4,143		9,688		5,772		1,622			2,467		3,624
Gain on Sale of Investment Securities		—		913		—		—		21,994		65,458		19,866		26,969		25,418			5,529		24,820
Interest Expense		8,653		17,355		17,158		13,590		18,721		9,591		6,499		12,416		12,541			12,357		993
Income (Loss) from Continuing Operations		573,609		434,668		286,081		380,546		420,258		415,924		269,852		120,666		(1,016	)		16,417		55,017
Net Income		581,045		434,186		156,312		353,545		461,738		449,261		293,858		127,606		4,359			17,873		63,517
Diluted Earnings Per Common Share:
Income (Loss) from Continuing Operations		5.27		3.99		2.66		3.56		3.93		3.95		2.54		1.16		(0.01	)		0.17		0.54
Net Income		5.34		3.99		1.45		3.31		4.32		4.27		2.77		1.23		0.04			0.17		0.63

* $000's omitted, except per share data
† All data excludes discontinued operations except net income
** 2004 includes an asset impairment of $51,516 and depreciation of $88,075

SUMMARY FINANCIAL DATA*
Cash†	$	96,095	$	364,246	$	63,020	$	96,142	$	77,549	$	67,445	$	32,193	$	284,460	$	63,785		$	29,763	$	45,699
Working Capital†		511,574		537,034		417,888		157,103		274,519		209,766		126,540		378,496		157,266			82,712		87,584
Investments		451,144		347,924		320,712		356,404		199,266		223,360		218,309		178,452		161,532			158,770		150,175
Property, Plant, and Equipment, Net†		4,351,571		3,677,070		3,275,020		3,194,273		2,605,384		2,068,812		1,399,974		897,504		913,338			983,026		824,815
Total Assets		5,721,085		5,003,891		4,265,370		4,161,024		3,588,045		2,885,369		2,134,712		1,663,350		1,406,844			1,417,770		1,227,313
Long-term Debt		195,000		235,000		360,000		420,000		475,000		445,000		175,000		200,000		200,000			200,000		100,000
Shareholders' Equity		3,834,998		3,270,047		2,807,465		2,683,009		2,265,474		1,815,516		1,381,892		1,079,238		914,110			917,251		895,170
Capital Expenditures		1,097,680		694,264		329,572		876,839		697,906		885,583		521,847		78,677		86,057			233,850		298,295

* $000's omitted
† Excludes discontinued operations

Rig Fleet Summary †
Drilling Rigs—
U. S. Land—FlexRigs		264		221		182		163		146		118		73		50		48			43		26
U. S. Land—Highly Mobile		—		4		11		11		12		12		12		12		11			11		11
U. S. Land—Conventional		18		23		27		27		27		27		28		29		28			29		29
Offshore Platform		9		9		9		9		9		9		9		11		11			12		12
International Land†		29		24		28		33		19		16		16		14		19			21		19

Total Rig Fleet		320		281		257		243		213		182		138		116		117			116		97
Rig Utilization Percentage—
U. S. Land—FlexRigs		97		99		87		76		100		100		100		100		99			97		96
U. S. Land—Highly Mobile		0		0		0		29		83		93		100		99		91			89		97
U. S. Land—Conventional		14		16		17		39		80		87		95		82		67			58		70
U. S. Land—All Rigs		89		86		73		68		96		97		99		94		87			81		84
Offshore Platform		79		77		80		89		75		65		69		53		48			51		83
International Land†		77		70		71		70		72		89		95		80		47			42		59

† Excludes discontinued operations

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

Helmerich & Payne, Inc.

Risk Factors and Forward-Looking Statements

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

With the exception of historical information, the matters discussed in Management's Discussion & Analysis of Financial Condition and Results of Operations include forward-looking statements. These forward-looking statements are based on various assumptions. We caution that, while we believe such assumptions to be reasonable and make them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. We are including this cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by us or persons acting on our behalf. The factors identified in this cautionary statement and those factors discussed under Risk Factors beginning on page 6 of our Form 10-K are important factors (but not necessarily inclusive of all important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or persons acting on our behalf. Except as required by law, we undertake no duty to update or revise our forward-looking statements based on changes of internal estimates or expectations or otherwise.

Executive Summary

Helmerich & Payne, Inc. is primarily a contract drilling company with a total fleet of 320 drilling rigs at September 30, 2012. Our contract drilling segments consist of the U.S. Land segment with 282 rigs, the Offshore segment with 9 offshore platform rigs and the International Land segment with 29 rigs at September 30, 2012. We continued to expand our rig fleet and activity in 2012 even as pronounced volatility in oil and natural gas prices impacted drilling market conditions and prospects. Our position in the market is strengthened by our high quality fleet, our long-term contracts and our customer base. During 2012, we placed into service 48 new FlexRigs, all with fixed multi-year contracts. Two of these new FlexRigs were sent to an international location. At September 30, 2012, we had 264 active rigs, as compared to 250 active rigs at the same time during the prior year.

As we begin 2013, we expect our customers to continue to become more focused in their efforts to enhance drilling efficiencies to reduce total well costs. We believe that our superior field performance and safety record will allow us to continue to gain market share over the coming years.

As further discussed in Note 2 of the Consolidated Financial Statements, our Venezuelan subsidiary was classified as discontinued operations on June 30, 2010, after the seizure of our drilling assets in that country by the Venezuelan government. Except as specifically discussed, the following results of operations pertains only to our continuing operations. Unless otherwise indicated, references to 2012, 2011 and 2010 in the following discussion are referring to our fiscal year 2012, 2011 and 2010.

Results of Operations

All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net income for 2012 was $581.0 million ($5.34 per share), compared with $434.2 million ($3.99 per share) for 2011 and $156.3 million ($1.45 per share) for 2010. Included in our net income for 2011 was an after-tax gain from the sale of an investment in a limited partnership of $0.6 million ($0.01 per share). Net income also includes after-tax gains from the sale of assets of $12.3 million ($0.11 per share) in 2012, $8.8 million ($0.08 per share) in 2011 and $3.3 million ($0.03 per share) in 2010.

Consolidated operating revenues were $3.2 billion in 2012, $2.5 billion in 2011 and $1.9 billion in 2010. As 2012 progressed, commodity price volatility and our customers' desire to stay within their 2012 budgets caused our active rig count to decline late in the fiscal year after experiencing increases since early 2010 through the first three quarters of fiscal 2012. As a result, our U.S. land rig utilization was 89 percent in 2012, 86 percent in 2011 and 73 percent in 2010. The average number of U.S. land rigs available was 266 rigs in 2012, 237 rigs in 2011 and 207 rigs in 2010. Revenue in the Offshore segment declined in 2012, after remaining steady in 2011 and 2010. Rig utilization for offshore rigs was 79 percent in 2012, compared to 77 percent in 2011 and 80 percent in 2010. Revenue in the International Land segment increased in 2012 after declining in 2011 from 2010. Rig utilization in our International Land segment was 77 percent in 2012, 70 percent in 2011 and 71 percent in 2010.

In 2011, we had a $0.9 million gain from the sale of investment securities. We did not sell any investment securities in 2012 or 2010. Interest and dividend income was $1.4 million, $2.0 million and $1.8 million in 2012, 2011 and 2010, respectively.

Direct operating costs in 2012 were $1.8 billion or 56 percent of operating revenues, compared with $1.4 billion or 56 percent of operating revenues in 2011 and $1.1 billion or 57 percent of operating revenues in 2010.

Depreciation expense was $387.5 million in 2012, $315.5 million in 2011 and $262.7 million in 2010. Included in depreciation are abandonments of equipment of $16.4 million in 2012, $4.9 million in 2011 and $4.2 million in 2010. Depreciation expense, exclusive of the abandonments, increased over the three-year period as we placed into service 48 new rigs in 2012, 36 in 2011 and 23 in 2010. Depreciation expense in 2013 is expected to increase from 2012 from new rigs placed into service during 2012 and additional rigs placed into service during 2013. (See Liquidity and Capital Resources.)

As conditions warrant, management performs an analysis of the industry market conditions impacting its long-lived assets in each drilling segment. Based on this analysis, management determines if any impairment is required. In 2012, 2011 and 2010, no impairment was recorded.

General and administrative expenses totaled $107.3 million in 2012, $91.5 million in 2011 and $81.5 million in 2010. The $15.8 million increase in 2012 from 2011 is due to increases in salaries, bonuses, and stock-based compensation of approximately $12.5 million associated with growth in the number of employees and increases in wages in comparative periods. The remaining increase is primarily due to higher professional services and to other corporate overhead associated with supporting continued growth of our drilling business.

Interest expense was $8.7 million in 2012, $17.4 million in 2011 and $17.2 million in 2010. Interest expense is primarily attributable to the fixed-rate debt outstanding. Interest expense decreased in 2012 from 2011 primarily due to a reduction in outstanding debt balances, a reduction in interest related to uncertain tax positions, interest accrued for settlement of a lawsuit in 2011 not incurred in 2012 and an increase in capitalized interest. Capitalized interest was $12.9 million, $8.2 million and $6.4 million in 2012, 2011 and 2010, respectively. All of the capitalized interest is attributable to our rig construction program.

The provision for income taxes totaled $329.0 million in 2012, $252.4 million in 2011 and $152.2 million in 2010. The effective income tax rate was 36 percent in 2012 compared to 37 percent in 2011 and 35 percent in 2010. Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets is based on management's judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future. (See Note 4 of the Consolidated Financial Statements for additional income tax disclosures.)

During 2012, 2011 and 2010, we incurred $16.1 million, $15.8 million and $12.3 million, respectively, of research and development expenses primarily related to the ongoing development of the rotary steerable system tools. We anticipate research and development expenses to continue during 2013.

In 2012, we had income from discontinued operations of $7.4 million compared to a loss from discontinued operations in 2011 and 2010 of $0.5 million and $129.8 million, respectively. In the fourth fiscal quarter of 2012, we settled an arbitration dispute with a third party not affiliated with the Venezuelan government, Petroleos de Venezuela, S.A. ("Petroleo") or PDVSA Petroleo, S.A. ("PDVSA") related to the seizure of our property in Venezuela. Proceeds of $7.5 million were received and recorded as discontinued operations. The loss from discontinued operations in 2011 and 2010 was the result of our Venezuelan drilling business, including eleven rigs and associated real and personal property, being seized by the Venezuelan government on June 30, 2010. In 2010, we derecognized our Venezuela property and equipment and warehouse inventory and wrote off other accounts where future cash inflows and outflows associated with them were no longer expected to occur.

Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleo and PDVSA. Our subsidiaries seek damages for the taking of their Venezuelan drilling business in violation of international law and for breach of contract. Additionally, we are participating in another arbitration against a third party not affiliated with the Venezuelan government, Petroleo or PDVSA in an attempt to collect an aggregate $50 million relating to the seizure of our property in Venezuela. The arbitration hearing is presently scheduled for late May 2013.

While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No gain contingencies are recognized in our Consolidated Financial Statements.

The following tables summarize operations by reportable operating segment.

Comparison of the years ended September 30, 2012 and 2011

	2012			2011

	(in thousands, except operating statistics)
*U.S. LAND OPERATIONS*
Operating revenues	$	2,678,475		$	2,100,508		27.5	%
Direct operating expenses		1,407,986			1,119,700		25.7
General and administrative expense		30,798			25,066		22.9
Depreciation		332,723			264,127		26.0

Segment operating income	$	906,968		$	691,615		31.1

Operating Statistics:
Revenue days		86,340			73,905		16.8	%
Average rig revenue per day	$	27,737		$	25,809		7.5
Average rig expense per day	$	13,022		$	12,538		3.9
Average rig margin per day	$	14,715		$	13,271		10.9
Number of rigs at end of period		282			248		13.7
Rig utilization		89	%		86	%	3.5

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $283,640 and $193,093 for 2012 and 2011, respectively.

Operating income in the U.S. Land segment increased to $907.0 million in 2012 from $691.6 million in 2011. Included in U.S. land revenues for 2012 and 2011 is approximately $10.1 million and $5.4 million, respectively, from early termination revenue. Excluding early termination related revenue, the average revenue per day for 2012 increased by $1,885 to $27,620 from $25,735 in 2011, primarily attributable to increases in dayrates in 2012 compared to 2011.

Direct operating expenses increased 25.7 percent in 2012 from 2011; however, the expense as a percentage of revenue was 53 percent in both 2012 and 2011.

Rig utilization increased to 89 percent in 2012 from 86 percent in 2011. The total number of rigs at September 30, 2012 was 282 compared to 248 rigs at September 30, 2011. The net increase is due to 46 new FlexRigs having been completed and placed into service, 3 FlexRigs transferred to the International Land segment, 3 idle conventional rigs sold, and four older mechanical highly mobile rigs and two older conventional rigs removed from service.

Depreciation includes charges for abandoned equipment of $15.9 million and $3.8 million in 2012 and 2011, respectively. Excluding the abandonment amounts, depreciation in 2012 increased 22 percent from 2011 due to the increase in available rigs.

We expect to complete and deliver approximately four rigs per month through early calendar 2013. Like those completed in fiscal 2012, each of these new rigs is committed to work for an exploration and production company under a fixed multi-year term contract, performing drilling services on a daywork contract basis. As a result of the new FlexRigs added in fiscal 2012 and additional rigs scheduled for completion in fiscal 2013, we anticipate depreciation expense to continue to increase in fiscal 2013.

At September 30, 2012, 231 out of 282 existing rigs in the U.S. Land segment were generating revenue. Of the 231 rigs generating revenue, 158 were under fixed-term contracts, and 73 were working in the spot market. At November 15, 2012, the number of existing rigs under fixed-term contracts in the segment was 159 and the number of rigs working in the spot market increased to 78.

Comparison of the years ended September 30, 2012 and 2011

	2012			2011

	(in thousands, except operating statistics)
*OFFSHORE OPERATIONS*
Operating revenues	$	189,086		$	201,417		(6.1	)%
Direct operating expenses		126,470			135,368		(6.6	)
General and administrative expense		7,386			6,074		21.6
Depreciation		13,455			14,684		(8.4	)

Segment operating income	$	41,775		$	45,291		(7.8	)

Operating Statistics:
Revenue days		2,625			2,544		3.2	%
Average rig revenue per day	$	53,927		$	51,794		4.1
Average rig expense per day	$	33,051		$	29,379		12.5
Average rig margin per day	$	20,876		$	22,415		(6.9	)
Number of rigs at end of period		9			9		—
Rig utilization		79	%		77	%	2.6

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $18,346 and $33,718 for 2012 and 2011, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense.

Segment operating income and average rig margin per day in our Offshore segment declined in 2012 from 2011 partly because our rig previously working offshore Trinidad completed its contract in the first quarter of fiscal 2012, returned to the U.S. during the second quarter of fiscal 2012 and was idle the remainder of the fiscal year. Additionally, a second rig was on standby for five months during 2012 compared to working all of 2011.

Comparison of the years ended September 30, 2012 and 2011

	2012			2011

	(in thousands, except operating statistics)
*INTERNATIONAL LAND OPERATIONS*
Operating revenues	$	270,027		$	226,849		19.0	%
Direct operating expenses		215,642			175,728		22.7
General and administrative expense		3,318			3,392		(2.2	)
Depreciation		30,701			28,018		9.6

Segment operating income	$	20,366		$	19,711		3.3

Operating Statistics:
Revenue days		7,343			6,406		14.6	%
Average rig revenue per day	$	32,998		$	31,633		4.3
Average rig expense per day	$	25,524		$	23,416		9.0
Average rig margin per day	$	7,474		$	8,217		(9.0	)
Number of rigs at end of period		29			24		20.8
Rig utilization		77	%		70	%	10.0

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $27,720 and $24,207 for 2012 and 2011, respectively. Also excluded are the effects of currency revaluation expense.

The International Land segment had operating income of $20.4 million for 2012 compared to $19.7 million for 2011.

Revenues in 2012 increased by $43.2 million from 2011 in our international land operations with rig utilization increasing to 77 percent in 2012 from 70 percent in 2011. The total number of rigs at September 30, 2012 was 29 compared to 24 rigs at September 30, 2011. The increase was due to two new FlexRigs having been completed and placed into service and three FlexRigs transferred from the U.S. Land segment.

Segment operating income and average margin per day decreased in 2012 compared to 2011 primarily due to early termination revenue earned in 2011 and higher operating expenses in 2012.

Comparison of the years ended September 30, 2011 and 2010

	2011			2010

	(in thousands, except operating statistics)
*U.S. LAND OPERATIONS*
Operating revenues	$	2,100,508		$	1,412,495		48.7	%
Direct operating expenses		1,119,700			772,766		44.9
General and administrative expense		25,066			23,799		5.3
Depreciation		264,127			211,652		24.8

Segment operating income	$	691,615		$	404,278		71.1

Operating Statistics:
Revenue days		73,905			55,051		34.2	%
Average rig revenue per day	$	25,809		$	23,909		7.9
Average rig expense per day	$	12,538		$	12,288		2.0
Average rig margin per day	$	13,271		$	11,621		14.2
Number of rigs at end of period		248			220		12.7
Rig utilization		86	%		73	%	17.8

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $193,093 and $96,304 for 2011 and 2010, respectively. Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2010.

Operating income in the U.S. Land segment increased to $691.6 million in 2011 from $404.3 million in 2010. Included in U.S. land revenues for 2011 and 2010 was approximately $5.4 million and $41.2 million, respectively, from early termination revenue and revenue from customers that requested delivery delays for new FlexRigs. Excluding early termination related revenue and customer requested delivery delay revenue for new FlexRigs, the average revenue per day for 2011 increased by $2,574 to $25,735 from $23,161 in 2010, primarily attributable to increases in dayrates in 2011 compared to 2010.

Direct operating expenses increased 44.9 percent in 2011 from 2010; however, the expense as a percentage of revenue decreased to 53 percent in 2011 from 55 percent in 2010. The average rig expense per day increased by only $250 during 2011.

Rig utilization increased to 86 percent in 2011 from 73 percent in 2010. The total number of rigs at September 30, 2011 was 248 compared to 220 rigs at September 30, 2010. The net increase was due to 35 new FlexRigs completed and placed into service, five transferred from the International Land segment, one transferred to the International Land segment, four sold and seven old mechanical highly mobile rigs removed from service.

Depreciation includes charges for abandoned equipment of $3.8 million and $3.5 million in 2011 and 2010, respectively. Excluding the abandonment amounts, depreciation in 2011 increased 25 percent from 2010 due to the increase in available rigs.

Comparison of the years ended September 30, 2011 and 2010

	2011			2010

	(in thousands, except operating statistics)
*OFFSHORE OPERATIONS*
Operating revenues	$	201,417		$	202,734		(0.6	)%
Direct operating expenses		135,368			131,325		3.1
General and administrative expense		6,074			5,821		4.3
Depreciation		14,684			12,519		17.3

Segment operating income	$	45,291		$	53,069		(14.7	)

Operating Statistics:
Revenue days		2,544			2,642		(3.7	)%
Average rig revenue per day	$	51,794		$	47,534		9.0
Average rig expense per day	$	29,379		$	24,653		19.2
Average rig margin per day	$	22,415		$	22,881		(2.0	)
Number of rigs at end of period		9			9		—
Rig utilization		77	%		80	%	(3.8	)

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $33,718 and $37,594 for 2011 and 2010, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense.

Segment operating income in our Offshore segment declined by 14.7 percent in 2011 from 2010 primarily due to a decrease in revenue days. The decrease in revenue days was primarily due to the temporary stacking of a rig in early fiscal 2011 compared to the same rig working all of 2010.

Comparison of the years ended September 30, 2011 and 2010

	2011			2010

	(in thousands, except operating statistics)
*INTERNATIONAL LAND OPERATIONS*
Operating revenues	$	226,849		$	247,179		(8.2	)%
Direct operating expenses		175,728			166,021		5.8
General and administrative expense		3,392			2,949		15.0
Depreciation		28,018			29,938		(6.4	)

Segment operating income	$	19,711		$	48,271		(59.2	)

Operating Statistics:
Revenue days		6,406			7,254		(11.7	)%
Average rig revenue per day	$	31,633		$	32,451		(2.5	)
Average rig expense per day	$	23,416		$	21,142		10.8
Average rig margin per day	$	8,217		$	11,309		(27.3	)
Number of rigs at end of period		24			28		(14.3	)
Rig utilization		70	%		71	%	(1.4	)

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $24,207 and $11,779 for 2011 and 2010, respectively. Also excluded are the effects of currency revaluation expense.

The International Land segment had operating income of $19.7 million for 2011 compared to $48.3 million for 2010.

Rig utilization for International land operations decreased to 70 percent in 2011 from 71 percent in 2010. The total number of rigs at September 30, 2011 was 24 compared to 28 rigs at September 30, 2010. The decrease was due to five rigs transferred to the U.S. Land segment and one rig transferred from the U.S. Land segment.

Segment operating income and average margin per day decreased in 2011 compared to 2010 primarily due to labor union interruptions in one country and idle rigs incurring fixed expenses.

LIQUIDITY AND CAPITAL RESOURCES

Our capital spending was $1.1 billion in 2012, $694.3 million in 2011 and $329.6 million in 2010. Net cash provided from operating activities was $1.0 billion in 2012, $977.6 million in 2011 and $462.3 million in 2010. Our 2013 capital spending is currently estimated at $740 million. In addition to capital maintenance requirements, tubulars and other special projects, this annual estimate includes the completion of new FlexRigs that are already under long-term contracts and capital components and spares to either service existing rigs or be used to build additional rigs.

Historically, we have financed operations primarily through internally generated cash flows. In periods when internally generated cash flows are not sufficient to meet liquidity needs, we will either borrow from available credit sources or we may sell portfolio securities. Likewise, if we are generating excess cash flows, we may invest in short-term money market securities.

We manage a portfolio of marketable securities that, at the close of fiscal 2012, had a fair value of $451.6 million. Our investments in Atwood Oceanics, Inc. ("Atwood") and Schlumberger, Ltd. made up 96 percent of the portfolio's fair value on September 30, 2012. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding our investments in limited partnerships carried at cost, the portfolio is recorded at fair value on our balance sheet.

We generated cash proceeds from the sale of an investment in a limited partnership of $3.9 million in 2011. We did not sell any portfolio securities in 2012 or 2010. Subsequent to September 30, 2012, we sold our share in three limited partnerships that were primarily invested in international equities. Proceeds of approximately $18.1 million were received during the first quarter of fiscal 2013.

Our proceeds from asset sales totaled $39.9 million in 2012, $26.8 million in 2011 and $7.9 million in 2010. Income from asset sales in 2012 totaled $19.2 million which includes the sale of three conventional rigs. In each year we also had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business.

We have $75 million of intermediate-term unsecured debt obligations that mature in August 2014. The interest rate through maturity will be 6.56 percent. The terms of the debt obligations require that we maintain a ratio of debt to total capitalization of less than 55 percent.

We have $160 million senior unsecured fixed-rate notes outstanding at September 30, 2012 that mature over a period from July 2013 to July 2016. Interest on the notes is paid semi-annually based on an annual rate of 6.10 percent. Annual principal repayments of $40 million are due July 2013 through July 2016. Financial covenants require that we maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00.

On May 25, 2012, we entered into an agreement with a multi-bank syndicate for a $300 million unsecured revolving credit facility that will mature May 25, 2017. We anticipate that the majority of any borrowings under the facility will accrue interest at a spread over the London Interbank Offered Rate (LIBOR). We will also pay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined according to a scale based on a ratio of our total debt to total capitalization. The LIBOR spread ranges from 1.125 percent to 1.75 percent per annum and commitment fees range from .15 percent to .35 percent per annum. Based on our debt to total capitalization on September 30, 2012, the LIBOR spread and commitment fees would be 1.125 percent and .15 percent, respectively. Financial covenants in the facility require us to maintain a funded leverage ratio (as defined) of less than 50 percent and interest coverage ratio (as defined) of not less than 3.00 to 1.00. The credit facility contains additional terms, conditions, restrictions and covenants that we believe are usual and customary in unsecured debt arrangements for companies of similar size and credit quality. As of September 30, 2012, there were no borrowings and one letter of credit outstanding in the amount of $3.5 million. The $3.5 million letter of credit was issued to guarantee a separate line of credit for an international subsidiary. At September 30, 2012, we had $296.5 million available to borrow under our $300 million unsecured credit facility.

At September 30, 2012, we had two collateral trusts totaling $26.1 million that were classified as restricted cash and included in prepaid expense and other in the Consolidated Balance Sheet. Subsequent to September 30, 2012, we terminated both collateral trusts and proceeds totaling $26.1 million were returned to us. We replaced the collateral trusts with two letters of credit totaling $27.2 million. This reduced the amount available to borrow under the $300 million unsecured credit facility to approximately $269.3 million.

At September 30, 2012, we had two stand-by letters of credit that were issued separately from the $300 million unsecured credit facility. One letter of credit for $0.1 million was issued by a bank on our behalf to support customs and transportation guaranties that were required to move a rig between two international locations. The second letter of credit for $0.2 million was issued by a bank on our behalf to guarantee payment of certain expenses incurred by an international transportation vendor. Subsequent to September 30, 2012, we issued two letters of credit totaling $12 million to a bank for the purposes of issuing two performance guaranties required under an international drilling contract. These letters of credit were issued separate from the $300 million credit facility and therefore did not reduce that borrowing capacity.

The applicable agreements for all of the unsecured debt described above contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for

companies that are similar in size and credit quality. At September 30, 2012, we were in compliance with all debt covenants.

At September 30, 2012, we had 176 existing rigs with contracts under fixed terms with original term durations ranging from six months to seven years, with some expiring in fiscal 2013. The contracts provide for termination at the election of the customer, with an early termination payment to be paid if a contract is terminated prior to the expiration of the fixed term. While most of our customers are primarily major oil companies and large independent oil companies, a risk exists that a customer, especially a smaller independent oil company, may become unable to meet its obligations and may exercise its early termination election in the future and not be able to pay the early termination fee. Although not expected at this time, our future revenue and operating results could be negatively impacted if this were to happen.

Our operating cash requirements, scheduled debt repayments, any stock repurchases and estimated capital expenditures, including our rig construction program, for fiscal 2013 are expected to be funded through current cash, cash provided from operating activities and, possibly, from funds available under our credit facility and from sales of available-for-sale securities.

The current ratio was 2.4 at September 30, 2012 and 2.3 at September 30, 2011. The long-term debt to total capitalization ratio, including the current portion of long-term debt, was six percent at September 30, 2012 compared to ten percent at September 30, 2011.

During 2012, we purchased 1,747,819 common shares at an aggregate cost of $77.6 million, which are held as treasury shares. During 2012, we paid dividends of $0.28 per share, or a total of $30.0 million, representing the 40th consecutive year of dividend increases.

STOCK PORTFOLIO HELD

September 30, 2012	Number of Shares		Cost Basis		Market Value

	(in thousands, except share amounts)
Atwood Oceanics, Inc.		8,000,000	$	121,498	$	363,600
Schlumberger, Ltd.		967,500		7,685		69,979
Other				9,350		18,026

Total			$	138,533	$	451,605

Material Commitments

We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations as of September 30, 2012, are summarized in the table below in thousands:

	Payments due by year

Contractual Obligations	Total		2013		2014		2015		2016		2017		After 2017
Long-term debt and estimated interest (a)	$	267,139	$	54,205	$	126,564	$	44,405	$	41,965	$	—	$	—
Operating leases (b)		34,430		5,728		3,942		3,027		2,412		2,380		16,941
Purchase obligations (b)		193,789		193,789		—		—		—		—		—

Total contractual obligations	$	495,358	$	253,722	$	130,506	$	47,432	$	44,377	$	2,380	$	16,941

(a): Interest on fixed-rate debt was estimated based on principal maturities. See Note 3 "Debt" to our Consolidated Financial Statements.
(b): See Note 14 "Commitments and Contingencies" to our Consolidated Financial Statements.

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

In 2012, we contributed $8.3 million to the pension plan. Based on current information available from plan actuaries, we estimate contributing at least $0.1 million in 2013 to meet the minimum contribution required by law. We expect to make additional contributions in 2013 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond 2013 are difficult to estimate due to multiple variables involved.

At September 30, 2012, we had $14.6 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in Note 4 to the Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Property, Plant and Equipment Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed as incurred. Interest costs applicable to the construction of qualifying assets is capitalized as a component of the cost of such assets. We account for the depreciation of property, plant and equipment using the straight-line method over the estimated useful lives of the assets considering the estimated salvage value of the property, plant and equipment. Both the estimated useful lives and salvage values require the use of management estimates. Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation. Management believes that these estimates have been materially accurate in the past. For the years presented in this report, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.

Impairment of Long-lived Assets Management assesses the potential impairment of our long-lived assets whenever events or changes in conditions indicate that the carrying value of an asset may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts and/or overall changes in general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair market value of the asset. The fair value of drilling rigs is determined based upon estimated discounted future cash flows or estimated fair market value, if available. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig's marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics due to lower industry utilization. Fair value is estimated, if applicable, considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors. Use of different assumptions could result in an impairment charge different from that reported.

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

Self-Insurance Accruals We self-insure a significant portion of expected losses relating to worker's compensation, general liability, employer's liability and automobile liability. Generally, deductibles range from $1 million to $3 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates are recorded for incurred outstanding liabilities for worker's compensation, general liability claims and for claims that are incurred but not reported. Estimates are based on adjusters' estimates, historic experience and statistical methods that we believe are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

Our wholly-owned captive insurance company finances a significant portion of the physical damage risk on company-owned drilling rigs as well as international casualty deductibles. With the exception of "named wind storm" risk in the Gulf of Mexico, we insure rig and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self-insure a $5 million per occurrence deductible, as well as 20 percent of the estimated replacement cost of offshore rigs and 30 percent of the estimated replacement cost for land rigs and equipment. We have two insurance policies covering eight offshore platform rigs for "named windstorm" risk in the Gulf of Mexico. The first policy covers four rigs and has a $75 million aggregate insurance limit over a $3 million deductible. The second policy covers four rigs and has a $40 million aggregate limit and a $3.5 million deductible. We maintain certain other insurance coverage with deductibles as high as $2.5 million. Excess insurance is purchased over these coverage amounts to limit our exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred and, using adjuster's estimates, our historical loss experience or estimation methods that are believed to be reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense and related liabilities. We self-insure a number of other risks including loss of earnings and business interruption.

Pension Costs and Obligations Our pension benefit costs and obligations are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan

assets. Our discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was lowered from 4.33 percent to 4.06 percent as of September 30, 2012 to reflect changes in the market conditions for high-quality fixed-income investments. The expected return on plan assets is determined based on historical portfolio results and future expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated from future periods. We anticipate pension expense to be approximately $1.2 million in 2013.

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

The fair value of restricted stock awards is determined based on the closing price of our common stock on the date of grant. We amortize the fair value of restricted stock awards to compensation expense on a straight-line basis over the vesting period. At September 30, 2012, unrecognized compensation cost related to unvested restricted stock was $13.3 million. The cost is expected to be recognized over a weighted-average period of 2.6 years.

Revenue Recognition Contract drilling revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

NEW ACCOUNTING STANDARDS

On October 1, 2011, we adopted the provisions of Accounting Standards Update ("ASU") No. 2010-06, Fair Value Measurements and Disclosures (Topic 820)— Improving Disclosures about Fair Value Measurements , requiring a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments. The adoption had no impact on the Consolidated Financial Statements.

On May 12, 2011, the Financial Accounting Standards Board ("FASB") issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and

Disclosure Requirements in U.S. GAAP and IFRSs . ASU No. 2011-04 is intended to create consistency between U.S. GAAP and International Financial Reporting Standards ("IFRS") on the definition of fair value and on the guidance on how to measure fair value and on what to disclose about fair value measurements. ASU No. 2011-04 will be effective for financial statements issued for fiscal periods beginning after December 15, 2011, with early adoption prohibited for public entities. We do not expect the adoption of these provisions to have a material impact on the Consolidated Financial Statements.

On June 16, 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income . ASU No. 2011-05 was issued to increase the prominence of other comprehensive income ("OCI") in financial statements. The guidance provides two options for presenting OCI. An OCI statement can be included with the net income statement, which together will make a statement of total comprehensive income. Alternatively, an OCI statement can be separate from a net income statement but the two statements will have to appear consecutively within a financial report. ASU No. 2011-05 will be applied retrospectively and is effective for fiscal periods beginning after December 15, 2011 with early adoption permitted. We are currently evaluating the method of presentation but the adoption on October 1, 2012 will have no impact on the Consolidated Financial Statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Foreign Currency Exchange Rate Risk We have operations in several South American countries, Africa and the Middle East. Our exposure to currency valuation losses is usually immaterial due to the fact that virtually all invoice billings and receipts in other countries are in U.S. dollars.

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

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

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

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

causing increased prices in materials and supplies could have a material adverse effect on future operating costs.

Interest Rate Risk Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our commercial banks. Because all of our debt at September 30, 2012 has fixed-rate interest obligations, there is no current risk due to interest rate fluctuation.

The following tables provide information as of September 30, 2012 and 2011 about our interest rate risk sensitive instruments:

INTEREST RATE RISK AS OF SEPTEMBER 30, 2012 (dollars in thousands)

	2013			2014			2015			2016			2017			After 2017			Total			Fair Value 9/30/12

Fixed-Rate Debt	$	40,000		$	115,000		$	40,000		$	40,000		$	—		$	—		$	235,000		$	252,705
Average Interest Rate		6.1	%		6.5	%		6.1	%		6.1	%		—	%		—	%		6.3	%
Variable Rate Debt	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
Average Interest Rate

INTEREST RATE RISK AS OF SEPTEMBER 30, 2011 (dollars in thousands)

	2012			2013			2014			2015			2016			After 2016			Total			Fair Value 9/30/11

Fixed-Rate Debt	$	115,000		$	40,000		$	115,000		$	40,000		$	40,000		$	—		$	350,000		$	376,882
Average Interest Rate		6.4	%		6.1	%		6.5	%		6.1	%		6.1	%		—	%		6.3	%
Variable Rate Debt	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
Average Interest Rate

Equity Price Risk On September 30, 2012, we had a portfolio of securities with a total fair value of $451.6 million. The total fair value of the portfolio of securities was $348.5 million at September 30, 2011. The fair value in Atwood and Schlumberger, Ltd. was $433.6 million or 96 percent of the portfolio's fair value at September 30, 2012. We make no specific plans to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the fair value of our holdings. Except for our investments in limited partnerships carried at cost, the portfolio is recorded at fair value on the balance sheet with changes in unrealized after-tax value reflected in the equity section of the balance sheet. Subsequent to September 30, 2012, we sold our share in the limited partnerships. At November 15, 2012, the total fair value of the remaining securities had increased to approximately $437.9 million with an estimated after-tax value of $278.1 million. Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements.

Report of Independent Registered Public Accounting Firm

HELMERICH & PAYNE, INC.

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

We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2012 and 2011, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helmerich & Payne, Inc. at September 30, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helmerich & Payne, Inc.'s internal control over financial reporting as of September 30, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 21, 2012 expressed an unqualified opinion thereon.


		/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
November 21, 2012

Consolidated Statements of Income

HELMERICH & PAYNE, INC.

	Years Ended September 30,

	2012			2011			2010
	(in thousands, except per share amounts)
Operating revenues
Drilling—U.S. Land	$	2,678,475		$	2,100,508		$	1,412,495
Drilling—Offshore		189,086			201,417			202,734
Drilling—International Land		270,027			226,849			247,179
Other		14,214			15,120			12,754

		3,151,802			2,543,894			1,875,162

Operating costs and expenses
Operating costs, excluding depreciation		1,750,510			1,432,602			1,071,959
Depreciation		387,549			315,468			262,658
Research and development		16,060			15,764			12,262
General and administrative		107,307			91,452			81,479
Income from asset sales		(19,223	)		(13,903	)		(4,992	)

		2,242,203			1,841,383			1,423,366

Operating income from continuing operations		909,599			702,511			451,796
Other income (expense)
Interest and dividend income		1,380			1,951			1,811
Interest expense		(8,653	)		(17,355	)		(17,158	)
Gain on sale of investment securities		—			913			—
Other		254			(953	)		1,787

		(7,019	)		(15,444	)		(13,560	)

Income from continuing operations before income taxes		902,580			687,067			438,236
Income tax provision		328,971			252,399			152,155

Income from continuing operations		573,609			434,668			286,081
Income (loss) from discontinued operations before income taxes		7,355			(487	)		(125,944	)
Income tax provision (benefit)		(81	)		(5	)		3,825

Income (loss) from discontinued operations		7,436			(482	)		(129,769	)

NET INCOME	$	581,045		$	434,186		$	156,312

Basic earnings per common share:
Income from continuing operations	$	5.35		$	4.06		$	2.70
Income (loss) from discontinued operations	$	0.07		$	—		$	(1.23	)

Net income	$	5.42		$	4.06		$	1.47

Diluted earnings per common share:
Income from continuing operations	$	5.27		$	3.99		$	2.66
Income (loss) from discontinued operations	$	0.07		$	—		$	(1.21	)

Net income	$	5.34		$	3.99		$	1.45

Weighted average shares outstanding (in thousands):
Basic		106,819			106,643			105,711
Diluted		108,377			108,632			107,404

The accompanying notes are an integral part of these statements.

Consolidated Balance Sheets

HELMERICH & PAYNE, INC.

Assets

	September 30,

	2012		2011
	(in thousands)
CURRENT ASSETS:
Cash and cash equivalents	$	96,095	$	364,246
Accounts receivable, less reserve of $942 in 2012 and $776 in 2011		620,489		460,540
Inventories		78,777		54,407
Deferred income taxes		17,555		19,855
Prepaid expenses and other		74,693		49,736
Current assets of discontinued operations		7,619		7,529

Total current assets		895,228		956,313

INVESTMENTS		451,144		347,924

PROPERTY, PLANT AND EQUIPMENT, at cost:
Contract drilling equipment		5,743,354		4,834,985
Construction in progress		215,754		232,703
Real estate properties		62,177		61,476
Other		284,813		211,897

		6,306,098		5,341,061
Less-Accumulated depreciation		1,954,527		1,663,991

Net property, plant and equipment		4,351,571		3,677,070

NONCURRENT ASSETS:
Other assets		23,142		22,584

TOTAL ASSETS	$	5,721,085	$	5,003,891

The accompanying notes are an integral part of these statements.

Consolidated Balance Sheets (Continued)

HELMERICH & PAYNE, INC.

Liabilities and Shareholders' Equity

	September 30,

	2012		2011
	(in thousands, except share data and per share amounts)
CURRENT LIABILITIES:
Accounts payable	$	159,420	$	103,852
Accrued liabilities		176,615		192,898
Long-term debt due within one year		40,000		115,000
Current liabilities of discontinued operations		5,129		4,979

Total current liabilities		381,164		416,729

NONCURRENT LIABILITIES:
Long-term debt		195,000		235,000
Deferred income taxes		1,209,040		975,280
Other		98,393		104,285
Noncurrent liabilities of discontinued operations		2,490		2,550

Total noncurrent liabilities		1,504,923		1,317,115

SHAREHOLDERS' EQUITY:
Common stock, $.10 par value, 160,000,000 shares authorized, 107,598,889 and 107,243,473 shares issued as of September 30, 2012 and 2011, respectively, and 105,697,693 and 107,086,324 shares outstanding as of September 30, 2012 and 2011, respectively		10,760		10,724
Preferred stock, no par value, 1,000,000 shares authorized, no shares issued		—		—
Additional paid-in capital		236,240		210,909
Retained earnings		3,505,295		2,954,210
Accumulated other comprehensive income		166,807		98,908

		3,919,102		3,274,751
Less treasury stock, 1,901,196 shares in 2012 and 157,149 shares in 2011, at cost		84,104		4,704

Total shareholders' equity		3,834,998		3,270,047

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	5,721,085	$	5,003,891

The accompanying notes are an integral part of these statements.

Consolidated Statements of Shareholders' Equity

HELMERICH & PAYNE, INC.

	Common Stock										Accumulated Other Comprehensive Income (Loss)			Treasury Stock

	Common Stock				Additional Paid-In Capital			Retained Earnings						Treasury Stock
	Shares		Amount		Additional Paid-In Capital			Retained Earnings						Shares			Amount			Total
	(in thousands, except per share amounts)
Balance, September 30, 2009		107,058	$	10,706	$	176,039		$	2,414,942		$	112,451			1,572		$	(31,129	)	$	2,683,009
Comprehensive Income:
Net income									156,312												156,312
Other comprehensive loss:
Unrealized losses on available-for-sale securities, net												(22,885	)								(22,885	)
Amortization of net periodic benefit costs—net of actuarial loss												(5,459	)								(5,459	)

Total other comprehensive loss																					(28,344	)

Total comprehensive income																					127,968

Dividends declared ($.22 per share)									(23,337	)											(23,337	)
Exercise of stock options						(2,721	)								(263	)		2,519			(202	)
Tax benefit of stock-based awards, including excess tax benefits of $3.9 million						4,172															4,172
Treasury stock issued for vested restricted stock						(1,445	)								(70	)		1,445			—
Stock-based compensation						15,855															15,855

Balance, September 30, 2010		107,058		10,706		191,900			2,547,917			84,107			1,239			(27,165	)		2,807,465
Comprehensive Income:
Net income									434,186												434,186
Other comprehensive income (loss):
Unrealized gains on available-for-sale securities, net												18,414									18,414
Amortization of net periodic benefit costs—net of actuarial loss												(3,613	)								(3,613	)

Total other comprehensive income																					14,801

Total comprehensive income																					448,987

Dividends declared ($.26 per share)									(27,893	)											(27,893	)
Exercise of stock options		185		18		(3,942	)								(948	)		19,365			15,441
Tax benefit of stock-based awards, including excess tax benefits of $13.4 million						13,946															13,946
Treasury stock issued for vested restricted stock						(3,096	)								(134	)		3,096			—
Stock-based compensation						12,101															12,101

Balance, September 30, 2011		107,243		10,724		210,909			2,954,210			98,908			157			(4,704	)		3,270,047
Comprehensive Income:
Net income									581,045												581,045
Other comprehensive income
Unrealized gains on available-for-sale securities, net												63,725									63,725
Amortization of net periodic benefit costs—net of actuarial gain												4,174									4,174

Total other comprehensive income																					67,899

Total comprehensive income																					648,944

Dividends declared ($.28 per share)									(29,960	)											(29,960	)
Exercise of stock options		315		32		5,398									47			(2,757	)		2,673
Tax benefit of stock-based awards, including excess tax benefits of $3.6 million						4,340															4,340
Treasury stock issued for vested restricted stock, net of shares withheld for employee taxes		41		4		(2,485	)								(51	)		967			(1,514	)
Repurchase of common stock															1,748			(77,610	)		(77,610	)
Stock-based compensation						18,078															18,078

Balance, September 30, 2012		107,599	$	10,760	$	236,240		$	3,505,295		$	166,807			1,901		$	(84,104	)	$	3,834,998

The accompanying notes are an integral part of these statements.

Consolidated Statements of Cash Flows

HELMERICH & PAYNE, INC.

	Years Ended September 30,

	2012			2011			2010
	(in thousands)
OPERATING ACTIVITIES:
Net income	$	581,045		$	434,186		$	156,312
Adjustment for (income) loss from discontinued operations		(7,436	)		482			129,769

Income from continuing operations		573,609			434,668			286,081
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		387,549			315,468			262,658
Provision for bad debt		205			106			206
Stock-based compensation		18,078			12,101			15,855
Gain on sale of investment securities		—			(913	)		—
Income from asset sales		(19,223	)		(13,903	)		(4,992	)
Deferred income tax expense		196,931			187,651			105,691
Other		—			—			79
Change in assets and liabilities:
Accounts receivable		(160,154	)		(2,987	)		(223,916	)
Inventories		(22,170	)		(11,005	)		(3,858	)
Prepaid expenses and other		(27,758	)		12,623			(12,800	)
Accounts payable		54,906			17,362			16,760
Accrued liabilities		195			20,483			14,031
Deferred income taxes		(180	)		251			2,453
Other noncurrent liabilities		(1,592	)		6,129			8,402

Net cash provided by operating activities from continuing operations		1,000,396			978,034			466,650
Net cash used in operating activities from discontinued operations		(64	)		(482	)		(4,362	)

Net cash provided by operating activities		1,000,332			977,552			462,288

INVESTING ACTIVITIES:
Capital expenditures		(1,097,680	)		(694,264	)		(329,572	)
Acquisition of TerraVici Drilling Solutions		—			(4,000	)		—
Proceeds from asset sales		39,894			26,795			7,867
Purchase of short-term investments		—			—			(16	)
Proceeds from sale of investments		—			3,932			12,516

Net cash used in investing activities from continuing operations		(1,057,786	)		(667,537	)		(309,205	)
Net cash provided by (used in) investing activities from discontinued operations		7,500			—			(55	)

Net cash used in investing activities		(1,050,286	)		(667,537	)		(309,260	)

FINANCING ACTIVITIES:
Decrease in long-term debt		(115,000	)		—			—
Proceeds from line of credit		20,000			10,000			895,000
Payments on line of credit		(20,000	)		(20,000	)		(1,060,000	)
Decrease in bank overdraft		—			—			(2,038	)
Repurchase of common stock		(77,610	)		—			—
Dividends paid		(30,049	)		(26,741	)		(22,254	)
Exercise of stock options		2,673			15,441			(202	)
Tax withholdings related to net share settlements of restricted stock operations		(1,514	)		—			—
Excess tax benefit from stock-based compensation		3,303			12,511			3,344

Net cash used in financing activities		(218,197	)		(8,789	)		(186,150	)

Net increase (decrease) in cash and cash equivalents		(268,151	)		301,226			(33,122	)
Cash and cash equivalents, beginning of period		364,246			63,020			96,142

Cash and cash equivalents, end of period	$	96,095		$	364,246		$	63,020

The accompanying notes are an integral part of these statements.

Notes to Consolidated Financial Statements

HELMERICH & PAYNE, INC.

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

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

BASIS OF PRESENTATION

We classified our former Venezuelan operation, an operating segment within the International Land segment, as a discontinued operation in the third quarter of fiscal 2010, as more fully described in Note 2. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates only to our continuing operations.

FOREIGN CURRENCIES

The functional currency for all our foreign operations is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the year. Gains and losses from remeasurement of foreign currency financial statements and foreign currency translations into U.S. dollars are included in direct operating costs. Included in direct operating costs are aggregate foreign currency remeasurement and transaction gains of $0.3 million in fiscal 2012 and losses totalling $1.2 million and $0.5 million in fiscal 2011 and 2010, respectively.

USE OF ESTIMATES

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

RECENTLY ADOPTED ACCOUNTING STANDARDS

On October 1, 2011, we adopted the provisions of Accounting Standards Update ("ASU") No. 2010-06, Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements , requiring a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments. The adoption had no impact on the Consolidated Financial Statements.

CASH AND CASH EQUIVALENTS

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

outstanding in excess of related book cash balances are included in accounts payable where applicable and included as a financing activity in the Consolidated Statements of Cash Flows.

RESTRICTED CASH AND CASH EQUIVALENTS

We had restricted cash and cash equivalents of $31.0 million and $18.0 million at September 30, 2012 and 2011, respectively. Restricted cash consists of $26.2 million for two trusts established to collateralize self-insurance programs and $4.8 million for the purpose of potential insurance claims in our wholly-owned captive insurance company. Of the total at September 30, 2012, $2.0 million is from the initial capitalization of the captive company and management has elected to restrict an additional $2.8 million. The restricted amounts are primarily invested in short-term money market securities.

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

	September 30,

	2012		2011
	(in thousands)
Other current assets	$	28,989	$	16,015
Other assets	$	2,000	$	2,000

INVENTORIES AND SUPPLIES

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

INVESTMENTS

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

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

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost less accumulated depreciation. Substantially all property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets (contract drilling equipment, 4-15 years; real estate buildings and equipment, 10-45 years; and other, 2-23 years). Depreciation in the Consolidated Statements of Income includes abandonments of $16.4 million, $4.9 million and $4.2 million for fiscal 2012, 2011 and 2010, respectively. The cost of maintenance and repairs is charged to direct operating cost, while betterments and refurbishments are capitalized. Effective September 30, 2012, we decommissioned four idle mechanical highly mobile rigs and two idle conventional rigs.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

CAPITALIZATION OF INTEREST

We capitalize interest on major projects during construction. Interest is capitalized based on the average interest rate on related debt. Capitalized interest for fiscal 2012, 2011 and 2010 was $12.9 million, $8.2 million and $6.4 million, respectively.

VALUATION OF LONG-LIVED ASSETS

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

SELF-INSURANCE ACCRUALS

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

DRILLING REVENUES

Contract drilling revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized on a straight-line basis over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs. Reimbursements for fiscal 2012, 2011 and 2010 were $329.7 million, $251.0 million and $145.7 million, respectively. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

RENT REVENUES

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

	Years Ended September 30,

	2012		2011		2010
	(in thousands)
Minimum rents	$	8,757	$	8,941	$	8,613
Overage and percentage rents	$	1,485	$	1,135	$	1,241

At September 30, 2012, minimum future rental income to be received on noncancelable operating leases was as follows:

Fiscal Year	Amount

	(in thousands)
2013	$	7,530
2014		6,802
2015		5,579
2016		4,223
2017		3,326
Thereafter		7,306

Total	$	34,766

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

At September 30, 2012 and 2011, the cost and accumulated depreciation for real estate properties were as follows:

	September 30,

	2012			2011
	(in thousands)
Real estate properties	$	62,177		$	61,476
Accumulated depreciation		(40,882	)		(39,665	)

	$	21,295		$	21,811

INCOME TAXES

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

EARNINGS PER SHARE

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

STOCK-BASED COMPENSATION

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

TREASURY STOCK

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

NEW ACCOUNTING STANDARDS

On May 12, 2011, the Financial Accounting Standards Board ("FASB") issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. ASU No. 2011-04 is intended to create consistency between U.S. GAAP and International Financial Reporting Standards ("IFRS") on the definition of fair value and on the guidance on how to measure fair value and on what to disclose about fair value measurements. ASU No. 2011-04 will be effective for financial statements issued for fiscal periods beginning after December 15, 2011, with early adoption prohibited for public entities. We do not expect the adoption of these provisions to have a material impact on the Consolidated Financial Statements.

On June 16, 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. ASU No. 2011-05 was issued to increase the prominence of

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

other comprehensive income ("OCI") in financial statements. The guidance provides two options for presenting OCI. An OCI statement can be included with the net income statement, which together will make a statement of total comprehensive income. Alternatively, an OCI statement can be separate from a net income statement but the two statements will have to appear consecutively within a financial report. ASU No. 2011-05 will be applied retrospectively and is effective for fiscal years beginning after December 15, 2011 with early adoption permitted. We are currently evaluating the method of presentation which will be the only impact on the Consolidated Financial Statements when adopted October 1, 2012.

NOTE 2 DISCONTINUED OPERATIONS

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

Summarized operating results from discontinued operations are as follows:

	Years Ended September 30,

	2012			2011			2010
	(in thousands)
Revenue	$	—		$	—		$	13,534
Income (loss) before income taxes		7,355			(487	)		(125,944	)
Income tax provision (benefit)		(81	)		(5	)		3,825

Income (loss) from discontinued operations	$	7,436		$	(482	)	$	(129,769	)

Income from discontinued operations in fiscal 2012 is attributable to proceeds from arbitration, as more fully described in Note 14, net of expenses incurred for in-country obligations.

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

	September 30,

	2012		2011
	(in thousands)
Other current assets	$	7,619	$	7,529

Total assets	$	7,619	$	7,529

Total current liabilities	$	5,129	$	4,979
Total noncurrent liabilities		2,490		2,550

Total liabilities	$	7,619	$	7,529

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 2 DISCONTINUED OPERATIONS (Continued)

Other current assets consist of restricted cash to meet remaining in-country current obligations. Liabilities consist of municipal and income taxes payable and social obligations due within the country of Venezuela.

NOTE 3 DEBT

At September 30, 2012 and 2011, we had $195 million and $235 million, respectively, in unsecured long-term debt outstanding at rates and maturities shown in the following table:

	September 30,

	2012		2011
	(in thousands)
Unsecured intermediate debt issued August 15, 2002:
Series C, due August 15, 2012, 6.46%	$	—	$	75,000
Series D, due August 15, 2014, 6.56%		75,000		75,000
Unsecured senior notes issued July 21, 2009:
Due July 21, 2012, 6.10%		—		40,000
Due July 21, 2013, 6.10%		40,000		40,000
Due July 21, 2014, 6.10%		40,000		40,000
Due July 21, 2015, 6.10%		40,000		40,000
Due July 21, 2016, 6.10%		40,000		40,000
Unsecured revolving credit facility due May 25, 2017		—		—

	$	235,000	$	350,000
Less long-term debt due within one year		40,000		115,000

Long-term debt	$	195,000	$	235,000

The intermediate unsecured debt outstanding at September 30, 2012 matures August 15, 2014 and carries an interest rate of 6.56 percent, which is paid semi-annually. The terms require that we maintain a ratio of debt to total capitalization of less than 55 percent. The debt is held by various entities.

We have $160 million senior unsecured fixed-rate notes outstanding at September 30, 2012 that mature over a period from July 2013 to July 2016. Interest on the notes is paid semi-annually based on an annual rate of 6.10 percent. Annual principal repayments of $40 million are due July 2013 through July 2016. We have complied with our financial covenants which require us to maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00.

Our $400 million senior unsecured credit facility matured in December 2011 and was allowed to expire. On May 25, 2012, we entered into an agreement with a multi-bank syndicate for a $300 million unsecured revolving credit facility that will mature May 25, 2017. We anticipate that the majority of any borrowings under the facility will accrue interest at a spread over the London Interbank Offered Rate (LIBOR). We will also pay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined according to a scale based on a ratio of our total debt to total capitalization. The LIBOR spread ranges from 1.125 percent to 1.75 percent per annum and commitment fees range from .15 percent to .35 percent per annum. Based on our debt to total capitalization on September 30, 2012, the LIBOR spread and commitment fees would be 1.125 percent

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 3 DEBT (Continued)

and .15 percent, respectively. Financial covenants in the facility require us to maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The credit facility contains additional terms, conditions, restrictions, and covenants that we believe are usual and customary in unsecured debt arrangements for companies of similar size and credit quality. As of September 30, 2012, there were no borrowings and one letter of credit was outstanding in the amount of $3.5 million. The $3.5 million letter of credit was issued to guarantee a separate line of credit for an international subsidiary. At September 30, 2012, we had $296.5 million available to borrow under our $300 million unsecured credit facility.

During the first fiscal quarter of 2012, we funded two collateral trusts totaling $26.1 million and terminated two letters of credit. The September 30, 2012 balances of the collateral trusts are classified as restricted cash and are included in prepaid expense and other in the Consolidated Balance Sheet. Subsequent to September 30, 2012, we terminated both collateral trusts and proceeds totaling $26.1 million were returned to us. We replaced the collateral trusts with two letters of credit totaling $27.2 million. This reduced the amount available to borrow under the $300 million unsecured credit facility to approximately $269.3 million.

At September 30, 2012, we had two letters of credit outstanding that were issued separately from the $300 million unsecured credit facility. One letter of credit for $0.1 million was issued by a bank on our behalf to support customs and transportation guaranties that were required to move a rig between two international locations. The second letter of credit for $0.2 million was issued by a bank on our behalf to guarantee payment of certain expenses incurred by an international transportation vendor. Subsequent to September 30, 2012, we issued two letters of credit totaling $12 million to a bank for the purposes of issuing two performance guaranties required under an international drilling contract. These letters of credit were issued separate from the $300 million credit facility and therefore did not reduce our borrowing capacity discussed above.

The applicable agreements for all unsecured debt described in this Note 3 contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2012, we were in compliance with all debt covenants.

At September 30, 2012, aggregate maturities of long-term debt are as follows (in thousands):

Years ending September 30,

2013	$	40,000
2014		115,000
2015		40,000
2016		40,000

	$	235,000

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 4 INCOME TAXES

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

	Years Ended September 30,

	2012			2011			2010
	(in thousands)
Current:
Federal	$	108,297		$	42,377		$	31,312
Foreign		13,201			14,259			13,215
State		10,542			8,112			1,937

		132,040			64,748			46,464

Deferred:
Federal		196,373			185,076			100,206
Foreign		(6,484	)		(4,117	)		7,846
State		7,042			6,692			(2,361	)

		196,931			187,651			105,691

Total provision	$	328,971		$	252,399		$	152,155

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

	Years Ended September 30,

	2012		2011		2010
	(in thousands)
Domestic	$	886,484	$	666,073	$	389,383
Foreign		16,096		20,994		48,853

	$	902,580	$	687,067	$	438,236

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 4 INCOME TAXES (Continued)

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

	September 30,

	2012		2011
	(in thousands)
Deferred tax liabilities:
Property, plant and equipment	$	1,103,769	$	898,657
Available-for-sale securities		154,463		119,464
Other		4		62

Total deferred tax liabilities		1,258,236		1,018,183

Deferred tax assets:
Pension reserves		9,482		14,260
Self-insurance reserves		7,737		8,344
Net operating loss and foreign tax credit carryforwards		59,730		54,967
Financial accruals		39,833		36,672
Other		6,533		3,224

Total deferred tax assets		123,315		117,467
Valuation allowance		56,564		54,709

Net deferred tax assets		66,751		62,758

Net deferred tax liabilities	$	1,191,485	$	955,425

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

As of September 30, 2012, we had state and foreign net operating loss carryforwards for income tax purposes of $21.4 million and $34.7 million, respectively, and foreign tax credit carryforwards of approximately $49.9 million (of which $46.0 million is reflected as a deferred tax asset in our Consolidated Financial Statements prior to consideration of our valuation allowance) which will expire in years 2013 through 2022. The valuation allowance is primarily attributable to state and foreign net operating loss carryforwards of $1.6 million and $11.4 million, respectively, and foreign tax credit carryforwards of $43.5 million which more likely than not will not be utilized.

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

	Years Ended September 30,

	2012			2011			2010
U.S. Federal income tax rate		35	%		35	%		35	%
Effect of foreign taxes		1			1			1
State income taxes		0			1			(1	)

Effective income tax rate		36	%		37	%		35	%

We recognize accrued interest related to unrecognized tax benefits in interest expense, and penalties in other expense in the Consolidated Statements of Income. As of September 30, 2012 and 2011, we had accrued interest and penalties of $6.1 million and $5.4 million, respectively.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 4 INCOME TAXES (Continued)

A reconciliation of the change in our gross unrecognized tax benefits for the fiscal year ended September 30, 2012 and 2011 is as follows:

	September 30,

	2012			2011
	(in thousands)
Unrecognized tax benefits at October 1,	$	6,878		$	5,549
Gross decreases—tax positions in prior periods		(4	)		(249	)
Gross increases—tax positions in prior periods		2,632			2,561
Gross increases—current period effect of tax positions		(242	)		434
Expiration of statute of limitations for assessments		(826	)		(1,417	)

Unrecognized tax benefits at September 30,	$	8,438		$	6,878

As of September 30, 2012 and September 30, 2011, our liability for unrecognized tax benefits was $8.4 million and $6.9 million, respectively, which would affect the effective tax rate if recognized. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in our Consolidated Balance Sheets.

For the next 12 months, we cannot predict with certainty whether we will achieve ultimate resolution of any uncertain tax position associated with our international operations that could result in increases or decreases of our unrecognized tax benefits. However, we believe it is reasonably possible that the reserve for uncertain tax positions may increase by approximately $7.0 million to $9.5 million during the next 12 months due to an international matter.

We file a consolidated U.S. federal income tax return, as well as income tax returns in various states and foreign jurisdictions. The tax years that remain open to examination by U.S. federal and state jurisdictions include fiscal years 2008 through 2011. Audits in foreign jurisdictions are generally complete through fiscal year 2000.

NOTE 5 SHAREHOLDERS' EQUITY

On September 30, 2012, we had 105,697,693 outstanding preferred stock purchase rights ("Rights") pursuant to the terms of the Rights Agreement dated January 8, 1996, as amended by Amendment No. 1 dated December 8, 2005. As adjusted for the two-for-one stock splits in fiscals 1998 and 2006, and as long as the Rights are not separately transferable, one-half Right attaches to each share of our common stock. Under the terms of the Rights Agreement each Right entitles the holder thereof to purchase one full unit consisting of one one-thousandth of a share of Series A Junior Participating Preferred Stock ("Preferred Stock"), without par value, at a price of $250 per unit. The exercise price and the number of units of Preferred Stock issuable on exercise of the Rights are subject to adjustment in certain cases to prevent dilution. The Rights will be attached to the common stock certificates and are not exercisable or transferable apart from the common stock, until ten business days after a person acquires 15 percent or more of the outstanding common stock or ten business days following the commencement of a tender offer or exchange offer that would result in a person owning 15 percent or more of the outstanding common stock. In that event, each holder of a Right (other than the acquiring person) shall have the right to receive, upon exercise of the Right, common stock of the Company having a value equal to two times the exercise price of the Right. In the event we are acquired in a

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 5 SHAREHOLDERS' EQUITY (Continued)

merger or certain other business combination transactions (including one in which we are the surviving corporation), or more than 50 percent of our assets or earning power is sold or transferred, each holder of a Right shall have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the exercise price of the Right. The Rights are redeemable under certain circumstances at $0.01 per Right and will expire, unless earlier redeemed, on January 31, 2016.

The Company has authorization from the Board of Directors for the repurchase of up to four million common shares in any calendar year. The repurchases may be made using our cash and cash equivalents or other available sources. During fiscal 2012, we purchased 1,747,819 common shares at an aggregate cost of $77.6 million, which are held as treasury shares.

NOTE 6 STOCK-BASED COMPENSATION

On March 2, 2011, the 2010 Long-Term Incentive Plan (the "2010 Plan") was approved by our stockholders. The 2010 Plan, among other things, authorizes the Board of Directors to grant nonqualified stock options, restricted stock awards and stock appreciation rights to selected employees and to non-employee Directors. Restricted stock may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than market price of the underlying stock on the date of grant. Stock options expire ten years after the grant date. We have the right to satisfy option exercises from treasury shares and from authorized but unissued shares. There were 455,900 nonqualified stock options and 243,600 shares of restricted stock awards granted under the 2010 Plan during fiscal 2012. Awards outstanding in the 2005 Long-Term Incentive Plan (the "2005 Plan") and one prior equity plan remain subject to the terms and conditions of those plans.

On December 1, 2009, we amended the forms of agreement under the 2005 Plan for awards of nonqualified stock options, incentive stock options and restricted stock. We also amended existing stock option and restricted stock award agreements under the 2005 Plan. The amendments provided for continued vesting (and accelerated vesting upon death) of restricted stock and stock options effective upon a participant becoming retirement eligible. A participant meets the definition of retirement eligible if the participant attains age 55 and has 15 or more years of continuous service as a full-time employee. The amendments were applied retroactively. As a result of the continued vesting provisions, we incurred additional compensation cost of approximately $4.9 million in fiscal 2010.

A summary of compensation cost for stock-based payment arrangements recognized in general and administrative expense in fiscal 2012, 2011 and 2010 is as follows:

	September 30,

	2012		2011		2010
	(in thousands)
Compensation expense
Stock options	$	9,791	$	7,224	$	11,475
Restricted stock		8,287		4,877		4,380

	$	18,078	$	12,101	$	15,855

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 6 STOCK-BASED COMPENSATION (Continued)

Benefits of tax deductions in excess of recognized compensation cost of $3.3 million, $12.5 million and $3.3 million are reported as a financing cash flow in the Consolidated Statements of Cash Flows for fiscal 2012, 2011 and 2010, respectively.

STOCK OPTIONS

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

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



Risk-free interest rate	1.0	%	1.9	%	2.3	%
Expected stock volatility	53.3	%	51.6	%	49.9	%
Dividend yield	0.4	%	0.5	%	0.5	%
Expected term (in years)	5.5		5.5		5.8

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

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

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

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

Based on these calculations, the weighted-average fair value per option granted to acquire a share of common stock was $27.70, $22.20 and $17.64 per share for fiscal 2012, 2011 and 2010, respectively.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 6 STOCK-BASED COMPENSATION (Continued)

The following summary reflects the stock option activity for our common stock and related information for fiscal 2012, 2011 and 2010 (shares in thousands):

	2012					2011					2010

	Options			Weighted-Average Exercise Price		Options			Weighted-Average Exercise Price		Options			Weighted-Average Exercise Price
Outstanding at October 1,		4,589		$	25.84		5,572		$	22.82		5,401		$	20.55
Granted		456			59.68		324			47.94		570			38.02
Exercised		(314	)		17.24		(1,289	)		18.24		(397	)		13.63
Forfeited/Expired		(41	)		42.21		(18	)		34.06		(2	)		38.02

Outstanding on September 30,		4,690		$	29.56		4,589		$	25.84		5,572		$	22.82

Exercisable on September 30,		3,575		$	24.66		3,287		$	22.35		3,888		$	19.68

Shares available to grant		5,082					6,000					761

The following table summarizes information about stock options at September 30, 2012 (shares in thousands):

	Outstanding Stock Options						Exercisable Stock Options

Range of Exercise Prices	Options		Weighted-Average Remaining Life		Weighted-Average Exercise Price		Options		Weighted-Average Exercise Price
$11.3318 to $16.01		1,269		1.3	$	14.18		1,269	$	14.18
$21.05 to $30.2375		1,571		4.9	$	25.00		1,371	$	25.57
$35.105 to $59.76		1,850		7.6	$	43.98		935	$	37.55

$11.3318 to $59.76		4,690		4.8	$	29.56		3,575	$	24.66

At September 30, 2012, the weighted-average remaining life of exercisable stock options was 3.8 years and the aggregate intrinsic value was $82.3 million with a weighted-average exercise price of $24.66 per share.

The number of options vested or expected to vest at September 30, 2012 was 4,648,528 with an aggregate intrinsic value of $89.4 million and a weighted-average exercise price of $28.38 per share.

As of September 30, 2012, the unrecognized compensation cost related to the stock options was $12.1 million. That cost is expected to be recognized over a weighted-average period of 2.6 years.

The total intrinsic value of options exercised during fiscal 2012, 2011 and 2010 was $12.0 million, $50.5 million and $11.3 million, respectively.

The grant date fair value of shares vested during fiscal 2012, 2011 and 2010 was $8.1 million, $7.9 million and $7.0 million, respectively.

RESTRICTED STOCK

Restricted stock awards consist of our common stock and are time vested over three to six years. We recognize compensation expense on a straight-line basis over the vesting period. The fair value of restricted stock awards under the 2010 Plan is determined based on the closing price of our shares on the grant date. As of September 30, 2012, there was $13.3 million of total unrecognized compensation

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 6 STOCK-BASED COMPENSATION (Continued)

cost related to unvested restricted stock awards. That cost is expected to be recognized over a weighted-average period of 2.6 years.

A summary of the status of our restricted stock awards as of September 30, 2012, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2012, 2011 and 2010, is as follows (share amounts in thousands):

	2012					2011					2010

	Shares			Weighted-Average Grant Date Fair Value per Share		Shares			Weighted-Average Grant Date Fair Value per Share		Shares			Weighted-Average Grant Date Fair Value per Share
Outstanding at October 1,		323		$	42.38		289		$	35.23		177		$	30.06
Granted		244			59.76		169			47.94		182			38.02
Vested (1)		(119	)		40.21		(134	)		33.92		(70	)		29.36
Forfeited/Expired		(18	)		49.75		(1	)		47.94		—			—

Outstanding on September 30,		430		$	52.52		323		$	42.38		289		$	35.23

(1): The number of restricted stock awards vested includes shares that we withheld on behalf of our employees to satisfy the statutory tax withholding requirements.

NOTE 7 EARNINGS PER SHARE

ASC 260, Earnings per Share , requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share. We have granted and expect to continue to grant to employees restricted stock grants that contain non-forfeitable rights to dividends. Such grants are considered participating securities under ASC 260. As such, we are required to include these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.

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

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 7 EARNINGS PER SHARE (Continued)

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

	September 30,

	2012			2011			2010
	(in thousands)
Numerator:
Income from continuing operations	$	573,609		$	434,668		$	286,081
Income (loss) from discontinued operations		7,436			(482	)		(129,769	)

Net income		581,045			434,186			156,312
Adjustment for basic earnings per share
Earnings allocated to unvested shareholders		(2,246	)		(1,295	)		(404	)

Numerator for basic earnings per share:
From continuing operations		571,363			433,373			285,677
From discontinued operations		7,436			(482	)		(129,769	)

		578,799			432,891			155,908
Adjustment for diluted earnings per share:
Effect of reallocating undistributed earnings of unvested shareholders		31			22			6
Numerator for diluted earnings per share:
From continuing operations		571,394			433,395			285,683
From discontinued operations		7,436			(482	)		(129,769	)

	$	578,830		$	432,913		$	155,914

Denominator:
Denominator for basic earnings per share—weighted-average shares		106,819			106,643			105,711
Effect of dilutive shares from stock options and restricted stock		1,558			1,989			1,693

Denominator for diluted earnings per share—adjusted weighted-average shares		108,377			108,632			107,404

Basic earnings per common shares:
Income from continuing operations	$	5.35		$	4.06		$	2.70
Income (loss) from discontinued operations		0.07			—			(1.23	)

Net income	$	5.42		$	4.06		$	1.47

Diluted earnings per common shares:
Income from continuing operations	$	5.27		$	3.99		$	2.66
Income (loss) from discontinued operations		0.07			—			(1.21	)

Net income	$	5.34		$	3.99		$	1.45

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 7 EARNINGS PER SHARE (Continued)

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

	2012		2011		2010

	(in thousands, except per share amounts)
Shares excluded from calculation of diluted earnings per share		446		310		554
Weighted-average price per share	$	59.68	$	47.94	$	38.02

NOTE 8 FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENT

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

	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value

	(in thousands)
Equity Securities:
September 30, 2012	$	129,183	$	304,396	$	—	$	433,579
September 30, 2011	$	129,183	$	203,486	$	—	$	332,669

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

The investments in the limited partnerships carried at cost were approximately $9.4 million at September 30, 2012 and 2011. The estimated fair value of the limited partnerships was $18.0 million and $15.8 million at September 30, 2012 and 2011, respectively. During fiscal 2011, we sold our investment in a limited partnership that was carried at a cost of approximately $3.0 million and had a fair value of approximately $3.9 million at the date of the sale. A gross realized gain of approximately $0.9 million is included in the Consolidated Statements of Income. Subsequent to September 30, 2012, we sold our shares in three limited partnerships that were primarily invested in international equities. Proceeds of approximately $18.1 million were received during the first quarter of fiscal 2013.

The assets held in a Non-qualified Supplemental Savings Plan are carried at fair market value which totaled $8.2 million and $5.9 million at September 30, 2012 and 2011, respectively.

The majority of cash equivalents are invested in money-market mutual funds invested primarily in direct or indirect obligations of the U.S. Government. The carrying amount of cash and cash equivalents approximates fair value due to the short maturity of those investments.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 8 FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENT (Continued)

The carrying value of other assets, accrued liabilities and other liabilities approximated fair value at September 30, 2012 and 2011.

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

•: Level 1—Observable inputs that reflect quoted prices in active markets for identical assets or liabilities in active markets.
•: Level 2—Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
•: Level 3—Valuations based on inputs that are unobservable and not corroborated by market data.

At September 30, 2012, our financial assets utilizing Level 1 inputs include cash equivalents, equity securities with active markets and money market funds we have elected to classify as restricted assets that are included in other current assets and other assets. Also included is cash denominated in a foreign currency we have elected to classify as restricted that is included in current assets of discontinued operations and limited to remaining liabilities of discontinued operations. For these items, quoted current market prices are readily available.

At September 30, 2012, Level 2 inputs include a bank certificate of deposit, which is included in current assets.

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

The following table summarizes our assets measured at fair value on a recurring basis presented in our Consolidated Balance Sheets as of September 30, 2012:

	Total Measured at Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

	(in thousands)
Assets:
Cash and cash equivalents	$	96,095	$	96,095	$	—	$	—
Investments		433,579		433,579		—		—
Other current assets		36,608		36,358		250		—
Other assets		2,000		2,000		—		—

Total assets measured at fair value	$	568,282	$	568,032	$	250	$	—

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 8 FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENT (Continued)

The following information presents the supplemental fair value information about long-term fixed-rate debt at September 30, 2012 and September 30, 2011.

	September 30,

	2012		2011
	(in thousands)
Carrying value of long-term fixed-rate debt	$	235.0	$	350.0
Fair value of long-term fixed-rate debt	$	252.7	$	376.9

The fair value for fixed-rate debt was estimated using discounted cash flows at rates reflecting current interest rates at similar maturities plus credit spread which was estimated using the outstanding market information on debt instruments with a similar credit profile to us. The debt was valued using a Level 2 input.

NOTE 9 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of other comprehensive income (loss) for the years ended September 30, 2012, 2011 and 2010 were as follows:

	Years Ended September 30,

	2012		2011			2010
	(in thousands)
Unrealized appreciation (depreciation) on securities, net of tax of $37,185, $11,047 and $(13,730)	$	63,725	$	18,414		$	(22,885	)
Amortization of net periodic benefit costs—net of actuarial gain (loss), net of tax of $2,436, $(2,167) and $(3,276)		4,174		(3,613	)		(5,459	)

	$	67,899	$	14,801		$	(28,344	)

The components of accumulated other comprehensive income (loss) at September 30, 2012 and 2011, net of applicable tax effects, were as follows:

	September 30,

	2012			2011
	(in thousands)
Unrealized appreciation on securities	$	189,851		$	126,126
Unrecognized actuarial loss and prior service cost		(23,044	)		(27,218	)

	$	166,807		$	98,908

NOTE 10 EMPLOYEE BENEFIT PLANS

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 10 EMPLOYEE BENEFIT PLANS (Continued)

The following table provides a reconciliation of the changes in the pension benefit obligations and fair value of Pension Plan assets over the two-year period ended September 30, 2012 and a statement of the funded status as of September 30, 2012 and 2011:

	2012			2011

	(in thousands)
Accumulated Benefit Obligation	$	112,062		$	104,911
Changes in projected benefit obligations
Projected benefit obligation at beginning of year	$	104,911		$	102,097
Interest cost		4,498			4,519
Actuarial gain		5,990			2,411
Benefits paid		(3,337	)		(4,116	)

Projected benefit obligation at end of year	$	112,062		$	104,911

Change in plan assets
Fair value of plan assets at beginning of year	$	67,284		$	61,388
Actual return on plan assets		14,495			(1,323	)
Employer contribution		8,276			11,335
Benefits paid		(3,337	)		(4,116	)

Fair value of plan assets at end of year	$	86,718		$	67,284

Funded status of the plan at end of year	$	(25,344	)	$	(37,627	)

The amounts recognized in the Consolidated Balance Sheets are as follows (in thousands):


Accrued liabilities	$	(95	)	$	(68	)
Noncurrent liabilities-other		(25,249	)		(37,559	)

Net amount recognized	$	(25,344	)	$	(37,627	)

The amounts recognized in Accumulated Other Comprehensive Income at September 30, 2012 and 2011, and not yet reflected in net periodic benefit cost, are as follows (in thousands):


Net actuarial loss	$	(37,172	)	$	(43,781	)
Prior service cost		(1	)		(2	)

Total	$	(37,173	)	$	(43,783	)

The amount recognized in Accumulated Other Comprehensive Income and not yet reflected in periodic benefit cost expected to be amortized in next year's periodic benefit cost is a net actuarial loss of $2.7 million.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 10 EMPLOYEE BENEFIT PLANS (Continued)

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

	Years Ended September 30,

	2012			2011			2010
Discount rate for net periodic benefit costs		4.33	%		4.48	%		5.42	%
Discount rate for year-end obligations		4.06	%		4.33	%		4.48	%
Expected return on plan assets		7.16	%		8.00	%		8.00	%

We contributed $8.3 million to the Pension Plan in fiscal 2012 to fund distributions in lieu of liquidating pension assets. We estimate contributing at least $0.1 million in fiscal 2013 to meet the minimum contribution required by law and expect to make additional contributions in fiscal 2013 if needed to fund unexpected distributions.

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

	Years Ended September 30,

	2012			2011			2010
	(in thousands)
Interest cost	$	4,498		$	4,519		$	4,825
Expected return on plan assets		(5,463	)		(5,050	)		(4,552	)
Amortization of prior service cost		2			—			—
Recognized net actuarial loss		3,567			2,976			2,295
Settlement/curtailment		—			28			—

Net pension expense (benefit)	$	2,604		$	2,473		$	2,568

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

Years Ended September 30,

2013		2014		2015		2016		2017		2018 - 2022		Total
$	6,477	$	5,555	$	5,997	$	6,593	$	6,350	$	36,900	$	67,872

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

INVESTMENT STRATEGY AND ASSET ALLOCATION

Our investment policy and strategies are established with a long-term view in mind. The investment strategy is intended to help pay the cost of the Plan while providing adequate security to meet the benefits promised under the Plan. We maintain a diversified asset mix to minimize the risk of a material loss to the portfolio value that might occur from devaluation of any single investment. In determining the appropriate asset mix, our financial strength and ability to fund potential shortfalls are considered. Plan assets are invested in portfolios of diversified public-market equity securities and fixed income securities. The Plan does not directly hold securities of the Company.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 10 EMPLOYEE BENEFIT PLANS (Continued)

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

The target allocation for 2013 and the asset allocation for the Pension Plan at the end of fiscal 2012 and 2011, by asset category, follows:

	Target Allocation			Percentage of Plan Assets At September 30,

Asset Category	2013			2012			2011
U.S. equities		56	%		55	%		56	%
International equities		14			12			13
Fixed income		25			25			30
Real estate and other		5			8			1

Total		100	%		100	%		100	%

PLAN ASSETS

The fair value of Plan assets at September 30, 2012 and 2011, summarized by level within the fair value hierarchy described in Note 8, are as follows:

	Fair Value as of September 30, 2012

	Total		Level 1		Level 2		Level 3
	(in thousands)
Short-term investments	$	7,233	$	7,233	$	—	$	—
Mutual funds:
Domestic stock funds		36,209		36,209		—		—
Bond funds		21,458		21,458		—		—
International stock funds		10,069		10,069		—		—

Total mutual funds		67,736		67,736		—		—
Domestic common stock		10,543		10,543		—		—
Foreign equity stock		907		907		—		—
Oil and gas properties		299		—		—		299

Total	$	86,718	$	86,419	$	—	$	299

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 10 EMPLOYEE BENEFIT PLANS (Continued)

	Fair Value as of September 30, 2011

	Total		Level 1		Level 2		Level 3
	(in thousands)
Short-term investments	$	691	$	691	$	—	$	—
Mutual funds:
Domestic stock funds		28,288		28,288		—		—
Bond funds		20,127		20,127		—		—
International stock funds		8,848		8,848		—		—

Total mutual funds		57,263		57,263		—		—
Domestic common stock		8,252		8,252		—		—
Foreign equity stock		803		803		—		—
Oil and gas properties		275		—		—		275

Total	$	67,284	$	67,009	$	—	$	275

The Plan's financial assets utilizing Level 1 inputs are valued based on quoted prices in active markets for identical securities. The Plan has no assets utilizing Level 2. The Plan's assets utilizing Level 3 inputs consist of oil and gas properties. The fair value of oil and gas properties is determined by Wells Fargo Bank, N.A., based upon actual revenue received for the previous twelve-month period and experience with similar assets.

The following table sets forth a summary of changes in the fair value of the Plan's Level 3 assets for the years ended September 30, 2012 and 2011:

	Oil and Gas Properties

	Years Ended September 30,
	2012		2011
	(in thousands)
Balance, beginning of year	$	275	$	275
Unrealized gains relating to property still held at the reporting date		24		—

Balance, end of year	$	299	$	275

DEFINED CONTRIBUTION PLAN

Substantially all employees on the United States payroll may elect to participate in the 401(k)/Thrift Plan by contributing a portion of their earnings. We contribute an amount equal to 100 percent of the first five percent of the participant's compensation subject to certain limitations. The annual expense incurred for this defined contribution plan was $26.7 million, $21.0 million and $14.2 million in fiscal 2012, 2011 and 2010, respectively.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 11 SUPPLEMENTAL BALANCE SHEET INFORMATION

The following reflects the activity in our reserve for bad debt for 2012, 2011 and 2010:

	September 30,

	2012			2011			2010
	(in thousands)
Reserve for bad debt:
Balance at October 1,	$	776		$	830		$	659
Provision for (recovery of) bad debt		205			106			206
Write-off of bad debt		(39	)		(160	)		(35	)

Balance at September 30,	$	942		$	776		$	830

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

	September 30,

	2012		2011
Prepaid expenses and other:
Restricted cash	$	28,989	$	16,015
Prepaid insurance		15,522		10,117
Deferred mobilization		19,809		8,512
Prepaid value added tax		1,470		3,884
Other		8,903		11,208

Total prepaid expenses and other	$	74,693	$	49,736

Accrued liabilities:
Accrued operating costs	$	37,645	$	50,415
Payroll and employee benefits		52,187		43,077
Taxes payable, other than income tax		35,842		37,789
Accrued income taxes		1,325		17,075
Deferred mobilization		13,351		11,281
Self-insurance liabilities		5,611		5,452
Deferred income		11,280		4,073
Other		19,374		23,736

Total accrued liabilities	$	176,615	$	192,898

Noncurrent liabilities—Other:
Pension and other non-qualified retirement plans	$	40,142	$	50,225
Self-insurance liabilities		12,385		13,780
Deferred mobilization		19,364		12,033
Deferred income		6,766		10,569
Uncertain tax positions including interest and penalties		12,184		9,829
Other		7,552		7,849

Total noncurrent liabilities—other	$	98,393	$	104,285

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 12 SUPPLEMENTAL CASH FLOW INFORMATION

	Years Ended September 30,

	2012		2011		2010
	(in thousands)
Cash payments:
Interest paid, net of amounts capitalized	$	10,711	$	16,107	$	16,721
Income taxes paid	$	144,959	$	19,621	$	104,028

Capital expenditures on the Consolidated Statements of Cash Flows for the years ended September 30, 2012, 2011 and 2010 do not include additions which have been incurred but not paid for as of the end of the year. The following table reconciles total capital expenditures incurred to total capital expenditures in the Consolidated Statements of Cash Flows:

	September 30,

	2012			2011			2010
	(in thousands)
Capital expenditures incurred	$	1,082,678		$	730,347		$	345,264
Additions incurred prior year but paid for in current year		61,591			25,508			9,816
Additions incurred but not paid for as of the end of the year		(46,589	)		(61,591	)		(25,508	)

Capital expenditures per Consolidated Statements of Cash Flows	$	1,097,680		$	694,264		$	329,572

NOTE 13 RISK FACTORS

CONCENTRATION OF CREDIT

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

VOLATILITY OF MARKET

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 13 RISK FACTORS (Continued)

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

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

SELF-INSURANCE

We self-insure a significant portion of expected losses relating to worker's compensation, general liability and automobile liability. Generally, deductibles range from $1 million to $3 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates are recorded for incurred outstanding liabilities for worker's compensation, general liability claims and claims that are incurred but not reported. Estimates are based on adjusters' estimates, historic experience and statistical methods that we believe are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

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

INTERNATIONAL DRILLING OPERATIONS

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 13 RISK FACTORS (Continued)

transactions included in current results of operations. As such, if a foreign economy is considered highly inflationary, there would be no impact on the Consolidated Financial Statements.

NOTE 14 COMMITMENTS AND CONTINGENCIES

PURCHASE OBLIGATIONS

During fiscal 2012, we announced agreements to build and operate 29 new FlexRigs. As of November 15, 2012, nine new FlexRigs with customer commitments remained under construction. During construction, rig construction cost is included in construction in progress and then transferred to contract drilling equipment when the rig is placed in the field for service. Equipment, parts and supplies are ordered in advance to promote efficient construction progress. At September 30, 2012, we had purchase orders outstanding of approximately $193.8 million for the purchase of drilling equipment.

LEASES

At September 30, 2012, we were leasing approximately 174,000 square feet of office space near downtown Tulsa, Oklahoma. We also lease other office space and equipment for use in operations. For operating leases that contain built-in pre-determined rent escalations, rent expense is recognized on a straight-line basis over the life of the lease. Leasehold improvements are capitalized and amortized over the lease term. Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of a year at September 30, 2012 are as follows:

Fiscal Year	Amount

	(in thousands)
2013	$	5,728
2014		3,942
2015		3,027
2016		2,412
2017		2,380
Thereafter		16,941

Total	$	34,430

Total rent expense was $8.5 million, $5.8 million and $5.4 million for fiscal 2012, 2011 and 2010, respectively.

CONTINGENCIES

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

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 14 COMMITMENTS AND CONTINGENCIES (Continued)

During the ordinary course of our business, contingencies arise resulting from an existing condition, situation, or set of circumstances involving an uncertainty as to the realization of a possible gain contingency. We account for gain contingencies in accordance with the provisions of ASC 450, Contingencies , and, therefore, we do not record gain contingencies and recognize income until realized. As discussed in Note 2, Discontinued Operations, property and equipment of our Venezuelan subsidiary was seized by the Venezuelan government on June 30, 2010. Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. ("Petroleo") and PDVSA Petroleo, S.A. ("PDVSA"). Our subsidiaries seek damages for the taking of their Venezuelan drilling business in violation of international law and for breach of contract. Additionally, we are participating in an arbitration against a third party not affiliated with the Venezuelan government, Petroleo or PDVSA in an attempt to collect an aggregate $50 million relating to the seizure of our property in Venezuela. The arbitration hearing is presently scheduled for late May 2013.

In the fourth fiscal quarter of 2012, we settled another arbitration dispute with a third party not affiliated with the Venezuelan government, Petroleo or PDVSA related to the seizure of our property in Venezuela. Proceeds of $7.5 million were received and recorded in discontinued operations.

NOTE 15 SEGMENT INFORMATION

We operate principally in the contract drilling industry. Our contract drilling business includes the following reportable operating segments: U.S. Land, Offshore and International Land. The contract drilling operations consist mainly of contracting Company-owned drilling equipment primarily to large oil and gas exploration companies. To provide information about the different types of business activities in which we operate, we have included Offshore and International Land, along with our U.S. Land reportable operating segment, as separate reportable operating segments. Additionally, each reportable operating segment is a strategic business unit which is managed separately. Our primary international areas of operation include Colombia, Ecuador, Argentina, Tunisia, Bahrain, Abu Dhabi and other South American countries. Other includes additional non-reportable operating segments. Revenues included in Other consist primarily of rental income. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

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

•: revenues from external and internal customers
•: direct operating costs
•: depreciation and
•: allocated general and administrative costs

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 15 SEGMENT INFORMATION (Continued)

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

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 15 SEGMENT INFORMATION (Continued)

Summarized financial information of our reportable segments for continuing operations for each of the years ended September 30, 2012, 2011 and 2010 is shown in the following table:

(in thousands)	External Sales		Inter- Segment			Total Sales			Segment Operating Income (Loss)			Depreciation		Total Assets		Additions to Long-Lived Assets

2012
Contract Drilling
U.S. Land	$	2,678,475	$	—		$	2,678,475		$	906,968		$	332,723	$	4,422,297	$	991,966
Offshore		189,086		—			189,086			41,775			13,455		160,135		8,547
International Land		270,027		—			270,027			20,366			30,701		467,538		52,864

		3,137,588		—			3,137,588			969,109			376,879		5,049,970		1,053,377
Other		14,214		841			15,055			(8,824	)		10,670		663,496		29,301

		3,151,802		841			3,152,643			960,285			387,549		5,713,466		1,082,678
Eliminations		—		(841	)		(841	)		—			—		—		—

Total	$	3,151,802	$	—		$	3,151,802		$	960,285		$	387,549	$	5,713,466	$	1,082,678

2011
Contract Drilling
U.S. Land	$	2,100,508	$	—		$	2,100,508		$	691,615		$	264,127	$	3,719,387	$	694,249
Offshore		201,417		—			201,417			45,291			14,684		151,656		7,092
International Land		226,849		—			226,849			19,711			28,018		333,142		20,638

		2,528,774		—			2,528,774			756,617			306,829		4,204,185		721,979
Other		15,120		829			15,949			(7,682	)		8,639		792,177		8,368

		2,543,894		829			2,544,723			748,935			315,468		4,996,362		730,347
Eliminations		—		(829	)		(829	)		—			—		—		—

Total	$	2,543,894	$	—		$	2,543,894		$	748,935		$	315,468	$	4,996,362	$	730,347

2010
Contract Drilling
U.S. Land	$	1,412,495	$	—		$	1,412,495		$	404,278		$	211,652	$	3,257,382	$	305,206
Offshore		202,734		—			202,734			53,069			12,519		132,342		9,982
International Land		247,179		—			247,179			48,271			29,938		411,339		23,865

		1,862,408		—			1,862,408			505,618			254,109		3,801,063		339,053
Other		12,754		814			13,568			(6,765	)		8,549		454,037		6,211

		1,875,162		814			1,875,976			498,853			262,658		4,255,100		345,264
Eliminations		—		(814	)		(814	)		—			—		—		—

Total	$	1,875,162	$	—		$	1,875,162		$	498,853		$	262,658	$	4,255,100	$	345,264

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 15 SEGMENT INFORMATION (Continued)

The following table reconciles segment operating income to income from continuing operations before income taxes as reported on the Consolidated Statements of Income:

	Years Ended September 30,

	2012			2011			2010
	(in thousands)
Segment operating income	$	960,285		$	748,935		$	498,853
Income from asset sales		19,223			13,903			4,992
Corporate general and administrative costs and corporate depreciation		(69,909	)		(60,327	)		(52,049	)

Operating income		909,599			702,511			451,796
Other income (expense)
Interest and dividend income		1,380			1,951			1,811
Interest expense		(8,653	)		(17,355	)		(17,158	)
Gain on sale of investment securities		—			913			—
Other		254			(953	)		1,787

Total unallocated amounts		(7,019	)		(15,444	)		(13,560	)

Income from continuing operations before income taxes	$	902,580		$	687,067		$	438,236

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

	Years Ended September 30,

	2012		2011		2010
	(in thousands)
Revenues
United States	$	2,864,570	$	2,276,118	$	1,572,139
Colombia		82,247		74,504		57,533
Argentina		54,317		44,205		55,855
Ecuador		56,448		42,598		52,115
Other Foreign		94,220		106,469		137,520

Total	$	3,151,802	$	2,543,894	$	1,875,162

Long-Lived Assets
United States	$	4,039,770	$	3,423,185	$	2,973,712
Argentina		81,886		78,221		91,322
Colombia		84,389		67,369		59,798
Ecuador		38,265		28,439		27,772
Other Foreign		107,261		79,856		122,416

Total	$	4,351,571	$	3,677,070	$	3,275,020

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

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 15 SEGMENT INFORMATION (Continued)

Revenues from one customer accounted for approximately 12.0 percent of total operating revenues during the year ended September 30, 2012, and 12.5 percent for years ended September 30, 2011 and 2010. Revenues from another customer accounted for approximately 10.2 percent, 4.5 percent and 4.6 percent of total operating revenues during the years ended September 30, 2012, 2011 and 2010, respectively. Collectively, the receivables from these customers were approximately $108.4 million and $70.5 million at September 30, 2012 and 2011, respectively.

NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

	(in thousands, except per share amounts)

2012	1 ^st Quarter		2 ^nd Quarter		3 ^rd Quarter		4 ^th Quarter
Operating revenues	$	732,588	$	769,982	$	819,785	$	829,447
Operating income		230,539		207,025		232,655		239,380
Income from continuing operations		144,297		129,763		149,943		149,606
Net income		144,286		129,719		149,925		157,115
Basic earnings per common share:
Income from continuing operations		1.34		1.20		1.40		1.41
Net income		1.34		1.20		1.40		1.48
Diluted earnings per common share:
Income from continuing operations		1.32		1.18		1.38		1.39
Net income		1.32		1.18		1.38		1.46

2011	1 ^st Quarter		2 ^nd Quarter		3 ^rd Quarter		4 ^th Quarter

Operating revenues	$	594,642	$	604,406	$	644,095	$	700,751
Operating income		170,726		164,265		174,418		193,102
Income from continuing operations		104,365		98,961		109,828		121,514
Net income		104,150		98,790		109,826		121,420
Basic earnings per common share:
Income from continuing operations		0.98		0.92		1.02		1.13
Net income		0.98		0.92		1.02		1.13
Diluted earnings per common share:
Income from continuing operations		0.96		0.91		1.01		1.11
Net income		0.96		0.91		1.01		1.11

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

In the first quarter of fiscal 2012, net income includes an after-tax gain from the sale of assets of $3.0 million, $0.03 per share on a diluted basis.

In the second quarter of fiscal 2012, net income includes an after-tax gain from the sale of assets of $4.9 million, $0.05 per share on a diluted basis.

In the third quarter of fiscal 2012, net income includes an after-tax gain from the sale of assets of $1.3 million, $0.01 per share on a diluted basis.

Notes to Consolidated Financial Statements (Continued)

HELMERICH & PAYNE, INC.

NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (Continued)

In the fourth quarter of fiscal 2012, net income includes an after-tax gain from the sale of assets of $3.0 million, $0.03 per share on a diluted basis.

In the first quarter of fiscal 2011, net income includes an after-tax gain from the sale of assets of $1.7 million, $0.02 per share on a diluted basis.

In the second quarter of fiscal 2011, net income includes an after-tax gain from the sale of assets of $2.6 million, $0.02 per share on a diluted basis.

In the third quarter of fiscal 2011, net income includes an after-tax gain from the sale of assets of $2.2 million, $0.02 per share on a diluted basis, and an after-tax gain from the sale of investment securities of $0.6 million, $0.01 per share on a diluted basis.

In the fourth quarter of fiscal 2011, net income includes an after-tax gain from the sale of assets of $2.4 million, $0.02 per share on a diluted basis.

Directors		Officers

Hans Helmerich Chairman of the Board and Chief Executive Officer Tulsa, Oklahoma William L. Armstrong() President Colorado Christian University Lakewood, Colorado Randy A. Foutch(*) Chairman and Chief Executive Officer Laredo Petroleum, Inc. Tulsa, Oklahoma John W. Lindsay President and Chief Operating Officer Tulsa, Oklahoma Paula Marshall(*) Chief Executive Officer The Bama Companies, Inc. Tulsa, Oklahoma Thomas A. Petrie(**) Chairman Petrie Partners, LLC Denver, Colorado Donald F. Robillard, Jr.(**) Chief Financial Officer Hunt Consolidated, Inc. Dallas, Texas Hon. Francis Rooney(**) Chief Executive Officer, Rooney Holdings, Inc. Former U.S. Ambassador to the Holy See, 2005 - 2008 Tulsa, Oklahoma Edward B. Rust, Jr.(*) Chairman, President and Chief Executive Officer State Farm Mutual Automobile Insurance Company Bloomington, Illinois John D. Zeglis(***) Chairman and Chief Executive Officer, Retired AT&T Wireless Services, Inc. Basking Ridge, New Jersey		Hans Helmerich Chairman of the Board and Chief Executive Officer John W. Lindsay President and Chief Operating Officer Steven R. Mackey Executive Vice President, Secretary, General Counsel & Chief Administrative Officer Juan Pablo Tardio Vice President and Chief Financial Officer Gordon K. Helm Vice President and Controller John R. Bell Vice President, Human Resources		Stockholders' Meeting The annual meeting of stockholders will be held on March 6, 2013. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 24, 2013, and the proxy statement and form of proxy will be made available via the Internet on that date. Stock Exchange Listing Helmerich & Payne, Inc. Common Stock is traded on the New York Stock Exchange with the ticker symbol "HP." The newspaper abbreviation most commonly used for financial reporting is "HelmP." Options on the Company's stock are also traded on the New York Stock Exchange. Stock Transfer Agent and Registrar As of November 15, 2012, there were 620 record holders of Helmerich & Payne, Inc. Common Stock as listed by the transfer agent's records. Our transfer agent is responsible for our shareholder records, issuance of stock certificates, and distribution of our dividends and the IRS Form 1099. Your requests, as shareholders, concerning these matters are most efficiently answered by corresponding directly with the transfer agent at the following address: Computershare Trust Company, N.A. Investor Services P.O. Box 43078 Providence, RI 02940-3078 Telephone: (800) 884-4225 (781) 575-4706 Available Information Annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, earnings releases, and financial statements are made available free of charge on the investor relations section of the Company's website as soon as reasonably practicable after the Company electronically files such materials with, or furnishes it to, the SEC. Also located on the investor relations section of the Company's website are certain corporate governance documents, including the following: the charters of the committees of the Board of Directors; the Company's Corporate Governance Guidelines and Code of Business Conduct and Ethics; the Code of Ethics for Principal Executive Officer and Senior Financial Officers; the Related Person Transaction Policy; the Foreign Corrupt Practices Act Compliance Policy; certain Audit Committee Practices and a description of the means by which employees and other interested persons may communicate certain concerns to the Company's Board of Directors, including the communication of such concerns confidentially and anonymously via the Company's ethics hotline at 1-800-205-4913. Annual reports, quarterly reports, current reports, amendments to those reports, earnings releases, financial statements and the various corporate governance documents are also available free of charge upon written request. Direct Inquiries To: Investor Relations Helmerich & Payne, Inc. 1437 South Boulder Avenue Tulsa, Oklahoma 74119 Telephone: (918) 742-5531 Internet Address: http://www.hpinc.com

*: Member, Audit Committee
**: Member, Human Resources Committee
***: Member, Nominating and Corporate Governance Committee

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Exhibit 13

Helmerich & Payne, Inc.
Management's Discussion & Analysis of Financial Condition and Results of Operations
Helmerich & Payne, Inc.
Report of Independent Registered Public Accounting Firm HELMERICH & PAYNE, INC.
Consolidated Statements of Income HELMERICH & PAYNE, INC.
Consolidated Balance Sheets HELMERICH & PAYNE, INC.
Consolidated Statements of Shareholders' Equity HELMERICH & PAYNE, INC.
Consolidated Statements of Cash Flows HELMERICH & PAYNE, INC.
Notes to Consolidated Financial Statements HELMERICH & PAYNE, INC.

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Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

Helmerich & Payne, Inc.

Subsidiaries of Helmerich & Payne, Inc.

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

Subsidiaries of Helmerich & Payne International Drilling Co.

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

Subsidiary of Helmerich & Payne (Boulder) Drilling Co.

Helmerich and Payne Mexico Drilling, S. De R.L. de C.V. (Incorporated in Mexico)

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

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

Subsidiaries of Utica Square Shopping Center, Inc.

Fishercorp, Inc. (Incorporated in Oklahoma)

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Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in this Annual Report on Form 10-K of Helmerich & Payne, Inc. of our report dated November 21, 2012, with respect to the consolidated financial statements of Helmerich & Payne, Inc., included in the 2012 Annual Report to Shareholders of Helmerich & Payne, Inc. filed as Exhibit 13.

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

(1): Registration Statement (Form S-8 No. 333-63124) pertaining to the Helmerich & Payne, Inc. 2000 Stock Incentive Plan,
(2): Registration Statement (Form S-8 No. 333-137144) pertaining to the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan, and
(3): Registration Statement (Form S-8 No. 333-176911) pertaining to the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan;

of our reports dated November 21, 2012, with respect to the consolidated financial statements of Helmerich & Payne, Inc. incorporated by reference in this Annual Report on Form 10-K and the effectiveness of internal control over financial reporting of Helmerich & Payne, Inc. included in this Annual Report on Form 10-K of Helmerich & Payne, Inc. for the year ended September 30, 2012.


		/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
November 21, 2012

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

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Exhibit 31.1

CERTIFICATION

I, Hans Helmerich, certify that:

1.

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

2.

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

3.

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

4.

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

(a): Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b): Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c): Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d): Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

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

(a): All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b): Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 21, 2012


		/s/ HANS HELMERICH Hans Helmerich Chief Executive Officer

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Exhibit 31.1

CERTIFICATION

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Exhibit 31.2

CERTIFICATION

I, Juan Pablo Tardio, certify that:

1.

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

2.

3.

4.

(a): Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b): Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c): Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d): Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

(a): All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b): Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 21, 2012


		/s/ JUAN PABLO TARDIO Juan Pablo Tardio Vice President and Chief Financial Officer

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Exhibit 31.2

CERTIFICATION

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Exhibit 32

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

In connection with the Annual Report of Helmerich & Payne, Inc. (the "Company") on Form 10-K for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Hans Helmerich, as Chief Executive Officer of the Company, and Juan Pablo Tardio, as Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that:

(1) The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

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


/s/ HANS HELMERICH Hans Helmerich Chief Executive Officer Date: November 21, 2012		/s/ JUAN PABLO TARDIO Juan Pablo Tardio Vice President and Chief Financial Officer Date: November 21, 2012

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Exhibit 32

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