0001047469-12-010732.txt : 20121121 0001047469-12-010732.hdr.sgml : 20121121 20121121134055 ACCESSION NUMBER: 0001047469-12-010732 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 15 CONFORMED PERIOD OF REPORT: 20120930 FILED AS OF DATE: 20121121 DATE AS OF CHANGE: 20121121 FILER: COMPANY DATA: COMPANY CONFORMED NAME: HELMERICH & PAYNE INC CENTRAL INDEX KEY: 0000046765 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 730679879 STATE OF INCORPORATION: DE FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-04221 FILM NUMBER: 121220658 BUSINESS ADDRESS: STREET 1: UTICA AT 21ST ST CITY: TULSA STATE: OK ZIP: 74114 BUSINESS PHONE: 9187425531 MAIL ADDRESS: STREET 1: UTICA AT 21ST ST CITY: TULSA STATE: OK ZIP: 74114 10-K 1 a2211785z10-k.htm 10-K

Use these links to rapidly review the document
TABLE OF CONTENTS

Table of Contents

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


Table of Contents


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.

i


Table of Contents

HELMERICH & PAYNE, INC.
FORM 10-K
YEAR ENDED SEPTEMBER 30, 2012
TABLE OF CONTENTS

 
   
  Page  

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  

ii


Table of Contents


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.


Table of Contents

        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

2


Table of Contents

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

3


Table of Contents

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    
 
 
  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.

4


Table of Contents

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.

5


Table of Contents

    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.

6


Table of Contents

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.

7


Table of Contents

        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.

8


Table of Contents

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

9


Table of Contents

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

10


Table of Contents

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.

11


Table of Contents

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.

12


Table of Contents

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   Average
Depth (Feet)
  Rig Type   Drawworks:
Horsepower
 
FLEXRIGS                        

TEXAS

 

 

164

 

 

18,000

 

SCR (FlexRig1)

 

 

1,500

 
TEXAS     165     18,000   SCR (FlexRig1)     1,500  
TEXAS     166     18,000   SCR (FlexRig1)     1,500  
TEXAS     167     18,000   SCR (FlexRig1)     1,500  
TEXAS     168     18,000   SCR (FlexRig1)     1,500  
TEXAS     169     18,000   SCR (FlexRig1)     1,500  
NORTH DAKOTA     179     18,000   SCR (FlexRig2)     1,500  
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  

13


Table of Contents

Location
  Rig   Average
Depth (Feet)
  Rig Type   Drawworks:
Horsepower
 
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  

14


Table of Contents

Location
  Rig   Average
Depth (Feet)
  Rig Type   Drawworks:
Horsepower
 
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  

15


Table of Contents

Location
  Rig   Average
Depth (Feet)
  Rig Type   Drawworks:
Horsepower
 
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  

16


Table of Contents

Location
  Rig   Average
Depth (Feet)
  Rig Type   Drawworks:
Horsepower
 
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  

17


Table of Contents

Location
  Rig   Average
Depth (Feet)
  Rig Type   Drawworks:
Horsepower
 
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  

18


Table of Contents

Location
  Rig   Average
Depth (Feet)
  Rig Type   Drawworks:
Horsepower
 
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.

19


Table of Contents

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

Location
  Rig   Average
Depth (Feet)
  Rig Type   Drawworks:
Horsepower
 

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.

20


Table of Contents

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.

21


Table of Contents


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

22


Table of Contents


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.

23


Table of Contents


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).

24


Table of Contents


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

25


Table of Contents

      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.

* * *

26


Table of Contents


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

27


Table of Contents

Item 9B.    OTHER INFORMATION

        None.

28


Table of Contents


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.

29


Table of Contents


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.

30


Table of Contents

      *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.

31


Table of Contents

      *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.

32


Table of Contents

      *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.

33


Table of Contents

      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.

34


Table of Contents


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

35


Table of Contents


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.

36


Table of Contents

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.

37


Table of Contents

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.

38


Table of Contents

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.

39



EX-10.12 2 a2211785zex-10_12.htm EX-10.12

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, 6th 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:

 

 



EX-13 3 a2211785zex-13.htm EX-13
QuickLinks -- Click here to rapidly navigate through this document


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.

LOGO

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

                                                                   

2



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.

3


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.

4


        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.

5


        The following tables summarize operations by reportable operating segment.

Comparison of the years ended September 30, 2012 and 2011

 
  2012   2011   % Change  
 
  (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.

6


Comparison of the years ended September 30, 2012 and 2011

 
  2012   2011   % Change  
 
  (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   % Change  
 
  (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.

7


        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   % Change  
 
  (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.

8


        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   % Change  
 
  (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.

9


Comparison of the years ended September 30, 2011 and 2010

 
  2011   2010   % Change  
 
  (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