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

FORM 10-K

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

 

 

For the fiscal year ended September 30, 2015

 

 

OR

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to          

Commission file number 1-4221

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

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  73-0679879
(I.R.S. Employer Identification No.)

1437 S. Boulder Ave., Suite 1400, Tulsa, Oklahoma
(Address of Principal Executive Offices)

 

74119-3623
(Zip Code)

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

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

Title of Each Class   Name of Each Exchange on Which Registered

Common Stock ($0.10 par value)

  New York Stock Exchange

Preferred Stock Purchase Rights

  New York Stock Exchange

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

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

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

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

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

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

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

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

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

         At March 31, 2015, the aggregate market value of the voting stock held by non-affiliates was approximately $7.1 billion.

         Number of shares of common stock outstanding at November 13, 2015:    107,787,205.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the Registrant's 2016 Proxy Statement for the Annual Meeting of Stockholders to be held on March 2, 2016 are incorporated by reference into Part III of this Form 10-K. The 2016 Proxy Statement will be filed with the U.S. Securities and Exchange Commission ("SEC") within 120 days after the end of the fiscal year to which this Form 10-K relates.


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DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

        This Annual Report on Form 10-K ("Form 10-K") 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 Form 10-K, 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 or results discussed in the forward-looking statements are disclosed in this Form 10-K under Item 1A—"Risk Factors", as well as in Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations." 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, expectations or otherwise, except as required by law.


Table of Contents

HELMERICH & PAYNE, INC.
FORM 10-K
YEAR ENDED SEPTEMBER 30, 2015
TABLE OF CONTENTS

 
   
  Page  

PART I

 

Item 1.

 

Business

   
1
 

Item 1A.

 

Risk Factors

    7  

Item 1B.

 

Unresolved Staff Comments

    17  

Item 2.

 

Properties

    18  

Item 3.

 

Legal Proceedings

    27  

Item 4.

 

Mine Safety Disclosures

    28  

 

Executive Officers of the Company

    28  

PART II

 

Item 5.

 

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

   
29
 

Item 6.

 

Selected Financial Data

    31  

Item 7.

 

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

    32  

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

    46  

Item 8.

 

Financial Statements and Supplementary Data

    47  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    99  

Item 9A.

 

Controls and Procedures

    99  

Item 9B.

 

Other Information

    102  

PART III

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

   
102
 

Item 11.

 

Executive Compensation

    102  

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

    102  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    102  

Item 14.

 

Principal Accountant Fees and Services

    102  

PART IV

 

Item 15.

 

Exhibits and Financial Statement Schedules

   
103
 

SIGNATURES

   
109
 

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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 2015, our U.S. Land operations drilled primarily in Oklahoma, California, Texas, Wyoming, Colorado, Louisiana, Mississippi, Pennsylvania, Ohio, Utah, New Mexico, Montana, North Dakota, West Virginia and Nevada. Offshore operations were conducted in the Gulf of Mexico and Equatorial Guinea. Our International Land segment conducted drilling operations in six international locations during fiscal 2015: Ecuador, Colombia, Argentina, Bahrain, United Arab Emirates ("UAE") and Mozambique.

        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"), continues to develop patented rotary steerable technology to enhance horizontal and directional drilling operations. TerraVici complements our existing drilling rig technology and allows us to offer directional drilling services to customers. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer.

    CONTRACT DRILLING

    General

        We believe that we are one of the major land and offshore 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 and national oil companies.

        In fiscal 2015, we received approximately 59 percent of our consolidated operating revenues from our ten largest contract drilling customers. BHP Billiton, Occidental Oil and Gas Corporation and EOG Resources (respectively, "BHP", "Oxy" and "EOG"), including their affiliates, are our three largest contract drilling customers. We perform drilling services for BHP in U.S. land operations, Oxy on a world-wide basis and EOG in U.S. land operations. Revenues from drilling services performed for BHP, Oxy and EOG in fiscal 2015 accounted for approximately 11 percent, 10 percent and 6 percent, respectively, of our consolidated operating revenues for the same period.

    Rigs, Equipment, R&D, Facilities, and Environmental Compliance

        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

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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 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 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

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of FlexRig3 combined with a bi-directional pad drilling system and equipment capacities suitable for wells in excess of 25,000 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 or decommissioned as we added new AC drive rigs to our fleet. The decommission 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. In fiscal 2015, we also decommissioned 23 of our 37 remaining SCR rigs including six of the eight 3,000 horsepower conventional rigs in our U.S. Land fleet, all six of our FlexRig1 SCR rigs and all 11 of our FlexRig2 SCR rigs.

        Since 1998, we have built 229 FlexRig3s, 88 FlexRig4s, and 49 FlexRig5s with 357 of those delivered to the field. Of the total 366 FlexRigs built through September 30, 2015, 186 have been built in the last five years. As of November 12, 2015, an additional six 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 (such as rotary steerable technology, discussed above) and develop new technology in the future. Our research and development expense totaled $16.1 million in fiscal 2015, $15.9 million in fiscal 2014 and $15.2 million in fiscal 2013.

        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. Additionally, we lease a 150,000 square foot industrial facility near Tulsa, Oklahoma, for the purpose of overhauling/repairing rig equipment and associated component parts.

        Our business is subject to various federal, state and local laws enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. We do not anticipate that compliance with currently applicable environmental regulations and controls will significantly change our competitive position, capital spending or earnings during fiscal 2016. For further information on environmental laws and regulations applicable to our operations, see Item 1A—"Risk Factors".

    Industry / Competitive Conditions

        Our business largely depends on the level of capital spending by oil and gas companies for exploration, development and production activities. Sustained increases or decreases in the price of oil and natural gas generally have a material impact on the exploration, development and production activities of our customers. As such, significant declines in the price of oil and natural gas may have a material adverse effect on our business, financial condition and results of operations. Oil prices have declined significantly since the beginning of fiscal 2015. This decline in pricing has resulted in lower demand for our drilling services. Specifically, at the close of fiscal 2015, we had 170 contracted rigs, compared to 325 contracted rigs at the same time during the prior year. In addition, and in light of the price of oil and the status of the drilling industry and our rig fleet, we have performed an impairment evaluation of all our long-lived drilling assets in accordance with ASC 360, Property, Plant, and Equipment. Our evaluation resulted in $39.2 million of impairment charges to reduce the carrying value of seven SCR land rigs within our International Land segment to their estimated fair value. No additional impairments were identified for any other rigs in our domestic, international or offshore fleets. For further information concerning risks associated with our business, including volatility surrounding oil and natural gas prices and the impact of low oil prices on our business, see Item 1A—"Risk Factors" and Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this Form 10-K.

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        Our industry is highly competitive. The land drilling market is generally more competitive than the offshore market due to the larger number of drilling rigs and market participants. While we strive to differentiate our services based upon the quality of our FlexRigs and our engineering design expertise, operational efficiency, safety and environmental awareness, the number of available rigs generally exceeds demand in many of our markets, resulting in strong price competition. In all of our geographic markets the ability to deliver rigs with new technology and features is also a significant factor in determining which drilling contractor is awarded a job. In recent years, rigs equipped with moving systems and configured to accommodate drilling of multiple wells on a single site have offered a competitive advantage. Other factors include quality of service and safety record, the availability and condition of equipment, the availability of trained personnel possessing specialized skills, experience in operating in certain environments, and relationships with customers.

        We compete against many drilling companies and certain competitors are present in more than one of our operating regions. In the United States, we compete with Nabors Industries Ltd., Patterson-UTI Energy, Inc. and several hundred other competitors with regional operations. Internationally, we compete directly with various contractors at each location where we operate. We also have numerous competitors in the offshore contract drilling industry that have significant resources.

    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 2015, 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 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, 2015, we had 137 existing 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.

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    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, 2015 and 2014 was $3.1 billion and $5.0 billion, respectively. The decrease in backlog at September 30, 2015 from September 30, 2014, is primarily due to the revenue earned since September 30, 2014 and the expiration and termination of long-term contracts. Approximately 60.7 percent of the total September 30, 2015 backlog is not reasonably expected to be filled in fiscal 2016. 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, 2015 and 2014, and the percentage of the September 30, 2015 backlog not reasonably expected to be filled in fiscal 2016:

 
  Total Backlog Revenue    
 
 
  Percentage Not Reasonably
Expected to be Filled in Fiscal 2016
 
Reportable Segment
  9/30/2015   9/30/2014  
 
  (in billions)
   
 

U.S. Land

  $ 2.2   $ 3.8     55.7 %

Offshore

    0.1     0.1     58.0 %

International

    0.8     1.1     74.2 %

  $ 3.1   $ 5.0        

        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. Further, as noted above, under certain limited circumstances a customer is not required to pay an early termination fee. There may also be instances where a customer is financially unable or refuses to pay an early termination fee. Accordingly, the actual amount of revenue earned may vary from the backlog reported. For further information, see Item 1A—"Risk Factors".

    U.S. Land Drilling

        At the end of September 2015, 2014, and 2013, we had 343, 329 and 302, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2015 increased by a net of 14 rigs from the end of fiscal 2014. The net increase is due to 30 new FlexRigs completed and placed into service, nine new FlexRigs completed and ready for delivery, five FlexRigs transferred to the International Land segment, two FlexRigs transferred from the International Land segment, one conventional rig transferred from the International Land segment and 23 older rigs removed from service. Our U.S. Land operations contributed approximately 80 percent ($2.5 billion) of our consolidated operating revenues during fiscal 2015, compared with approximately 83 percent ($3.1 billion) of consolidated operating revenues during fiscal 2014 and approximately 82 percent ($2.8 billion) of consolidated operating revenues during fiscal 2013. Rig utilization was approximately 62 percent in fiscal 2015, approximately 86 percent in fiscal 2014 and approximately 82 percent in fiscal 2013. Our fleet of FlexRigs had an average utilization of approximately 63 percent during fiscal 2015, while our conventional 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 2015, 145 out of an available 343 land rigs were generating revenue.

    Offshore Drilling

        Our Offshore operations contributed approximately 8 percent in fiscal year 2015 ($241.0 million) of our consolidated operating revenues compared to approximately 7 percent ($250.8 million) of consolidated operating revenues during fiscal 2014 and 7 percent ($221.9 million) of consolidated

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operating revenues during fiscal 2013. Rig utilization in fiscal 2015 was approximately 93 percent compared to approximately 89 percent in fiscal 2014 and fiscal 2013. At the end of fiscal 2015 and 2014, 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 54 percent ($129.6 million) of offshore revenues during fiscal 2015.

    International Land Drilling

    General

        Our International Land operations contributed approximately 12 percent ($386.7 million) of our consolidated operating revenues during fiscal 2015, compared with approximately 10 percent ($355.5 million) of consolidated operating revenues during fiscal 2014 and 11 percent ($366.8 million) of consolidated operating revenues during fiscal 2013. Rig utilization in fiscal 2015 was 53 percent, 76 percent in fiscal 2014 and 82 percent in fiscal 2013. Our international operations are subject to various political, economic and other uncertainties not typically encountered in U.S. operations. For further information on various risks associated with doing business in foreign countries, see Item 1A—"Risk Factors.

    Argentina

        At the end of fiscal 2015, we had 19 rigs in Argentina. Our utilization rate was approximately 56 percent during fiscal 2015, approximately 80 percent during fiscal 2014 and approximately 62 percent during fiscal 2013. Revenues generated by Argentine drilling operations contributed approximately 5 percent in fiscal 2015 ($169.4 million) of our consolidated operating revenues compared to approximately 3 percent ($107.9 million) of our consolidated operating revenues during fiscal 2014 and approximately 2 percent ($73.2 million) of our consolidated operating revenues during fiscal 2013. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 4 percent of consolidated operating revenues and approximately 30 percent of international operating revenues during fiscal 2015. The Argentine drilling contracts are primarily with large international or national oil companies.

    Colombia

        At the end of fiscal 2015, we had eight rigs in Colombia. Our utilization rate was approximately 52 percent during fiscal 2015, approximately 63 percent during fiscal 2014 and approximately 82 percent during fiscal 2013. Revenues generated by Colombian drilling operations contributed approximately 2 percent in fiscal 2015 ($74.3 million) of our consolidated operating revenues compared to approximately 2 percent ($85.2 million) of our consolidated operating revenues during fiscal 2014 and approximately 3 percent ($100.1 million) of our consolidated operating revenues during fiscal 2013. Revenues from drilling services performed for our two customers in Colombia totaled approximately 2 percent of consolidated operating revenues and approximately 19 percent of international operating revenues during fiscal 2015. The Colombian drilling contracts are primarily with large international or national oil companies.

    Ecuador

        At the end of fiscal 2015, we had six rigs in Ecuador. The utilization rate in Ecuador was 34 percent in fiscal 2015, compared to 85 percent in fiscal 2014 and 95 percent in fiscal 2013. Revenues generated by Ecuadorian drilling operations contributed approximately 1 percent in fiscal 2015 ($34.2 million) of our consolidated operating revenues compared to approximately 2 percent in fiscal 2014 and fiscal 2013 of our consolidated operating revenues ($69.2 million and $67.9 million,

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respectively). Revenues from drilling services performed for our two largest customers in Ecuador totaled approximately 1 percent of consolidated operating revenues and approximately 7 percent of international operating revenues during fiscal 2015. 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 2015 we had three rigs in Bahrain and two rigs in the UAE.

    FINANCIAL

        For information relating to revenues, total assets and operating income by reportable operating segments, see Note 14—"Segment Information" included in Item 8—"Financial Statements and Supplementary Data" of this Form 10-K.

    EMPLOYEES

        We had 5,803 employees within the United States (11 of which were part-time employees) and 935 employees in international operations as of September 30, 2015.

    AVAILABLE INFORMATION

        Our website is located at www.hpinc.com. Annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, earnings releases, and financial statements are made available free of charge on the investor relations section of our website as soon as reasonably practicable after we electronically file such materials with, or furnish it to, the SEC. The information contained on our website, or available by hyperlink from our website, is not incorporated into this Form 10-K or other documents we file with, or furnish to, the SEC. Annual reports, quarterly reports, current reports, amendments to those reports, earnings releases, financial statements and our various corporate governance documents are also available free of charge upon written request.

Item 1A.    RISK FACTORS

        In addition to the risk factors discussed elsewhere in this Form 10-K, we caution that the following "Risk Factors" could have a material adverse effect on our business, financial condition and results of operations.

Our business depends on the level of activity in the oil and natural gas industry, which is significantly impacted by the volatility of oil and natural gas prices and other factors.

        Our business depends on the conditions of the land and offshore oil and natural gas industry. Demand for our services depends on oil and natural gas industry exploration and production activity and expenditure levels, which are directly affected by trends in oil and natural gas prices. Oil and natural gas prices, and market expectations regarding potential changes to these prices, significantly affect oil and natural gas industry activity.

        Oil prices declined significantly during the second half of 2014 and continued in 2015. For example, in July of 2014 oil prices exceeded $100 per barrel. Oil prices in recent months have been below $50 per barrel. In response, many of our customers announced significant reductions in their 2015 capital spending budgets. As such, demand for our drilling services significantly declined. At December 31, 2014, 294 out of an available 337 land rigs were working in the U.S. Land segment. In contrast, at September 30, 2015, 145 out of an available 343 land rigs were contracted in the U.S. Land

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segment. After giving effect to new FlexRigs placed into service and additional rig releases since September 30, 2015, as of November 12, 2015, 132 rigs remain contracted in the U.S. Land segment. In the event oil prices remain depressed for a sustained period, or decline further, our U.S. Land, International Land and Offshore segments may experience further, significant declines in both drilling activity and spot dayrate pricing which could have a material adverse effect on our business, financial condition and results of operations.

        Oil and natural gas prices are impacted by many factors beyond our control, including:

    the demand for oil and natural gas;

    the cost of exploring for, developing, producing and delivering oil and natural gas;

    the worldwide economy;

    expectations about future oil and natural gas prices;

    the desire and ability of The Organization of Petroleum Exporting Countries ("OPEC") to set and maintain production levels and pricing;

    the level of production by OPEC and non-OPEC countries;

    domestic and international tax policies;

    political and military conflicts in oil producing regions or other geographical areas or acts of terrorism in the U.S. or elsewhere;

    technological advances;

    the development and exploitation of alternative fuels;

    legal and other limitations or restrictions on exportation and/or importation of oil and natural gas;

    local and international political, economic and weather conditions; and

    the environmental and other laws and governmental regulations regarding exploration and development of oil and natural gas reserves.

The level of land and offshore exploration, development and production activity and the price for oil and natural gas is volatile and is likely to continue to be volatile in the future. Higher oil and natural gas prices do not necessarily translate into increased activity because demand for our services is typically driven by our customer's expectations of future commodity prices. However, a sustained decline in worldwide demand for oil and natural gas or prolonged low oil or natural gas prices would likely result in reduced exploration and development of land and offshore areas and a decline in the demand for our services, which could have a material adverse effect on our business, financial condition and results of operations.

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.

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        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 customers 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 and other third parties 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 and other third parties by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on 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 policies. However, we self-insure large deductibles under these policies. 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.

        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 2016, 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.

A tepid or deteriorating global economy may affect our business.

        As a result of volatility in oil and natural gas prices and a tepid global economic environment, we are unable to determine whether our customers will maintain or increase spending on exploration and

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development drilling or whether customers and/or vendors and suppliers will be able to access financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations. In the event the global economic environment remains tepid or deteriorates, industry fundamentals may be impacted and result in stagnant or reduced demand for drilling rigs. Furthermore, these factors may result in certain of our customers experiencing an inability to pay vendors, including us. The global economic environment in the past has experienced significant deterioration in a relatively short period of time and there can be no assurance that the global economic environment will not quickly deteriorate again due to one or more factors. These conditions could have a material adverse effect on our business, financial condition and results of operations.

The contract drilling business is highly competitive and an excess of available drilling rigs may adversely affect our rig utilization and profit margins.

        Competition in contract drilling involves such factors as price, rig availability and excess rig capacity in the industry, 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. However, development of new drilling technology by competitors has increased in recent years and future improvements in operational efficiency and safety by our competitors could further negatively affect our ability to differentiate our services. Also, the strategy of differentiation is less effective during low commodity price environments when lower demand for drilling services intensifies price competition and makes it more difficult or impossible to compete on any basis other than price. The oil and natural gas services industry in the United States, for example, has experienced downturns in demand during the last decade, including a significant downturn that started in 2014. During these periods there have been substantially more drilling rigs available than necessary to meet demand. As a result of the current excess of available and more competitive drilling rigs, we may have difficulty sustaining rig utilization and profit margins, we may lose market share and price may become the primary factor in the award of contracts for drilling services.

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

        In fiscal 2015, we received approximately 59 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 27 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.

New technologies may cause our drilling methods and equipment to become less competitive, higher levels of capital expenditures may be necessary to keep pace with the bifurcation of the drilling industry, and growth through the building of new drilling rigs and improvement of existing rigs is not assured.

        The market for our services is characterized by continual technological developments that have resulted in, and will likely continue to result in, substantial improvements in the functionality and performance of rigs and equipment. Our customers increasingly demand the services of newer, higher

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specification drilling rigs. This results in a bifurcation of the drilling fleet and is evidenced by the higher specification drilling rigs (e.g., AC rigs) generally operating at higher overall utilization levels and day rates than the lower specification drilling rigs (e.g., mechanical or SCR rigs). In addition, a significant number of lower specification rigs are being stacked and/or removed from service. As a result of this bifurcation, a higher level of capital expenditures will be required to maintain and improve existing rigs and equipment and purchase and construct newer, higher specification drilling rigs to meet the increasingly sophisticated needs of our customers.

        Since the late 1990's we have increased our drilling rig fleet through new construction. 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. There can be no assurance that we will:

    have sufficient capital resources to build new, technologically advanced drilling rigs or to improve existing rigs;

    avoid cost overruns inherent in large construction projects resulting from numerous factors such as shortages of equipment, materials and skilled labor, unscheduled delays in delivery of ordered equipment and materials, unanticipated increases in costs of equipment, materials and labor, design and engineering problems, and financial or other difficulties;

    successfully integrate additional drilling rigs;

    effectively manage the growth and increased size of our organization and drilling fleet;

    successfully deploy idle, stacked or additional drilling rigs;

    maintain crews necessary to operate additional drilling rigs; or

    successfully improve our financial condition, results of operations, business or prospects as a result of building new drilling rigs.

        If we are not successful in building new rigs and equipment or upgrading our existing rigs and equipment in a timely and cost-effective manner, we could lose market share. One or more technologies that we may implement in the future may not work as we expect and we may be adversely affected. Additionally, new technologies, services or standards could render some of our services, drilling rigs or equipment obsolete, which could have a material adverse impact on our business, financial condition and results of operation.

New legislation and regulatory initiatives relating to hydraulic fracturing or other aspects of the oil and gas industry could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the drilling services we provide.

        It is a common practice in our industry for our customers to recover natural gas and oil from shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations using water, sand and other additives pumped under high pressure into the formation. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure, waste disposal and/or well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Members of the U.S. Congress and a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing and the possibility of more stringent regulation. Further, we conduct drilling activities in numerous states, including

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Oklahoma. In recent years, Oklahoma has experienced an increase in earthquakes. Some parties believe that there is a correlation between hydraulic fracturing related activities and the increased occurrence of seismic activity. The extent of this correlation, if any, is the subject of studies of both state and federal agencies the results of which remain uncertain. Depending on the outcome of these or other studies pertaining to the impact of hydraulic fracturing, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing activities. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques, operational delays or increased operating and compliance costs in the production of oil and natural gas from shale plays, added difficulty in performing hydraulic fracturing, and potentially a decline in the completion of new oil and gas wells.

        We do not engage in any hydraulic fracturing activities. However, any new laws, regulations or permitting requirements regarding hydraulic fracturing could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the drilling services we provide. 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.

Failure to comply with the terms of our plea agreement with the United States Department of Justice may adversely affect our business.

        On November 8, 2013, the United States District Court for the Eastern District of Louisiana approved the previously disclosed October 30, 2013 plea agreement between our wholly owned subsidiary, Helmerich & Payne International Drilling Co. ("H&PIDC"), and the United States Department of Justice, United States Attorney's Office for the Eastern District of Louisiana ("DOJ"). The court's approval of the plea agreement resolved the DOJ's investigation into certain choke manifold testing irregularities that occurred in 2010 at one of H&PIDC's offshore platform rigs in the Gulf of Mexico. As part of the plea agreement, H&PIDC agreed, during a three-year probationary period, to not commit any further criminal violations and to fulfill the terms of an environmental compliance plan ("ECP") whose purpose is to develop and implement additional training and safety programs. Our ability to comply with the terms of the plea agreement is dependent, in part, on our successful implementation of the additional training and safety programs set forth in the ECP. While not anticipated, a failure to comply with the terms of the plea agreement, including the ECP, could result in prosecution and other regulatory sanctions, and could otherwise adversely affect our business. We have been engaged in discussions with the Inspector General's office of the Department of Interior regarding the same events that were the subject of the DOJ's investigation. Although we presently believe that the outcome of our discussions will not have a material adverse effect on us, we can provide no assurances as to the timing or eventual outcome of these discussions. Refer to Item 3—"Legal Proceedings" and Note 13—"Commitments and Contingencies" included in Item 8—"Financial Statements and Supplementary Data" of this Form 10-K for additional discussion of this subject.

We are subject to the political, economic and social instability risks and local laws associated with doing business in certain foreign countries.

        We currently have operations in South America, the Middle East and Africa. In the future, we may further expand the geographic reach of our operations. As a result, we are exposed to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of social unrest, strikes, terrorism, war, kidnapping of employees, nationalization, forced negotiation or modification of contracts, difficulty resolving disputes and enforcing contract provisions, expropriation of equipment as well as expropriation of oil and gas exploration and drilling rights, taxation policies, foreign exchange restrictions and restrictions on repatriation of income and capital, currency rate

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fluctuations, increased governmental ownership and regulation of the economy and industry in the markets in which we operate, economic and financial instability of national oil companies, and restrictive governmental regulation, bureaucratic delays and general hazards associated with foreign sovereignty over certain areas in which operations are conducted. South American countries, in particular, have historically experienced uneven periods of economic growth, as well as recession, periods of high inflation and general economic and political instability. From time to time these risks have impacted our business. For example, on June 30, 2010, the Venezuelan government expropriated 11 rigs and associated real and personal property owned by our Venezuelan subsidiary. Prior thereto, we also experienced currency devaluation losses in Venezuela and difficulty repatriating U.S. dollars to the United States.

        Additionally, 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 2015, approximately 12 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2015, 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. The future occurrence of one or more international events arising from the types of risks described above could have a material adverse impact on our business, financial condition and results of operation.

Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti-bribery legislation could adversely affect our business.

        The U.S. Foreign Corrupt Practices Act ("FCPA") and similar anti-bribery laws in other jurisdictions, including the United Kingdom Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices and impact our business. Although we have programs in place covering compliance with anti-bribery legislation, any failure to comply with the FCPA or other anti-bribery legislation could subject us to civil and criminal penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operation. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs or other assets.

Failure to comply with governmental 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

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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.

Our current backlog of contract drilling revenue may continue to decline and may not be ultimately realized as 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, a customer may be unable or may refuse to pay the early termination payment. We also may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, such as depressed market conditions. As of September 30, 2015, our contract drilling backlog was approximately $3.1 billion for future revenues under firm commitments. Our contract drilling backlog may continue to decline as contract term coverage over time may not be offset by new term contracts as a result of the decline in the price of oil and capital spending reductions by our customers. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse impact 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, 2015, we had a portfolio of securities with a total fair value of approximately $91.5 million, consisting of Atwood Oceanics, Inc. and Schlumberger, Ltd. These securities are subject to a wide variety of market-related risks that could substantially reduce or increase the fair value of our holdings. 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. At November 12, 2015, the fair value of the portfolio had increased to approximately $98.7 million.

Legal proceedings could have a negative impact on our business.

        The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. Lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations. Any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.

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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, our ability to construct, maintain or improve drilling rigs could be impaired, 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 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 business and results of operations may be adversely affected by foreign currency restrictions and devaluation.

        Our contracts for work in foreign countries generally provide for payment in U.S. dollars. However, in Argentina we are paid in Argentine pesos. The Argentine branch of one of our second-tier subsidiaries remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars. In the future, other contracts or applicable law may require payments to be made in foreign currencies. As such, there can be no assurance that we will not experience in Argentina or elsewhere a devaluation of foreign currency, foreign exchange restrictions or other difficulties repatriating U.S. dollars even if we are able to negotiate contract provisions designed to mitigate such risks. We may incur currency devaluations which could have a material adverse impact on our business, financial condition and results of operations.

We may have additional tax liabilities.

        We are subject to income taxes in the United States and numerous other jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes. In the ordinary course of our business, there are many transactions and calculations where the ultimate tax determination is uncertain. We are regularly audited by tax authorities. Although we believe our tax estimates are reasonable, the final determination of tax audits and any related litigation could be materially different than what is reflected in income tax provisions and accruals. An audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows in the period or periods challenged. It is also possible that future changes to tax laws (including tax treaties) could impact our ability to realize the tax savings recorded to date.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

        Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by major U.S. credit rating agencies. Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, commodity pricing levels

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and other considerations. A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.

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 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. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse impact on our business, financial condition and results of operations. Further, to the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of or access to capital. Climate change and GHG regulation could also reduce the demand for hydrocarbons and, ultimately, demand for our services.

Reliance on management and competition for experienced personnel may negatively impact our operations or financial results.

        We greatly depend on the efforts of our executive officers and other key employees to manage our operations. The loss of members of management could have a material effect on our business. Similarly, 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.

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.

Our business is subject to cybersecurity risks.

        Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Cybersecurity attacks could include, but are not limited to, malicious software, attempts to gain unauthorized access to our data and the unauthorized release, corruption or loss of our data and personal information, loss of our intellectual property, theft of our FlexRig and other technology, loss or damage to our data delivery systems, other electronic security breaches that could lead to disruptions in our critical systems, and increased costs to prevent, respond to or mitigate cybersecurity events. It is possible that our business, financial and other systems could be compromised, which might not be noticed for some period of time. Although we utilize various procedures and controls to mitigate our exposure to such risk, cybersecurity attacks are evolving and unpredictable. The occurrence of such an attack could lead to financial losses and have a material adverse effect on our

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business, financial condition and results of operations. We are not aware that any material cybersecurity breaches have occurred to date.

Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.

        Efforts may be made from time to time to unionize portions of our workforce. In addition, we may in the future be subject to strikes or work stoppages and other labor disruptions. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.

Any future implementation of price controls on oil and natural gas would affect our operations.

        The United States Congress may in the future impose some form of price controls on either oil, natural gas, or both. Any future limits on the price of oil or natural gas could negatively affect the demand for our services and, consequently, have a material adverse effect on our business, financial condition and results of operations.

Covenants in our debt agreements restrict our ability to engage in certain activities.

        Our debt agreements pertaining to certain long-term unsecured debt and our unsecured revolving credit facility contain various covenants that may in certain instances restrict our ability to, among other things, incur, assume or guarantee additional indebtedness, incur liens, make loans or certain types of investments, sell or otherwise dispose of assets, enter into new lines of business, and merge or consolidate. In addition, our debt agreements also require us to maintain minimum current, funded leverage and interest coverage ratios. Such restrictions may limit our ability to successfully execute our business plans, which may have adverse consequences on our 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 SEC that were issued 180 days or more preceding the end of our 2015 fiscal year and that remain unresolved.

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Item 2.    PROPERTIES

    CONTRACT DRILLING

        The following table sets forth certain information concerning our U.S. land and offshore drilling rigs as of September 30, 2015:

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

FLEXRIGS

                       

TEXAS

   
212
   
22,000
 

AC (FlexRig3)

   
1,500
 

TEXAS

    214     22,000   AC (FlexRig3)     1,500  

WYOMING

    215     22,000   AC (FlexRig3)     1,500  

TEXAS

    216     22,000   AC (FlexRig3)     1,500  

TEXAS

    218     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  

TEXAS

    223     22,000   AC (FlexRig3)     1,500  

PENNSYLVANIA

    225     22,000   AC (FlexRig3)     1,500  

TEXAS

    226     22,000   AC (FlexRig3)     1,500  

TEXAS

    227     22,000   AC (FlexRig3)     1,500  

TEXAS

    228     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

    236     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    239     22,000   AC (FlexRig3)     1,500  

TEXAS

    240     22,000   AC (FlexRig3)     1,500  

PENNSYLVANIA

    241     22,000   AC (FlexRig3)     1,500  

TEXAS

    242     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  

NEW MEXICO

    251     22,000   AC (FlexRig3)     1,500  

TEXAS

    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  

NEW MEXICO

    260     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    261     22,000   AC (FlexRig3)     1,500  

TEXAS

    262     22,000   AC (FlexRig3)     1,500  

TEXAS

    263     22,000   AC (FlexRig3)     1,500  

TEXAS

    264     22,000   AC (FlexRig3)     1,500  

18


Table of Contents

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

TEXAS

    265     22,000   AC (FlexRig3)     1,500  

TEXAS

    266     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    267     22,000   AC (FlexRig3)     1,500  

TEXAS

    268     22,000   AC (FlexRig3)     1,500  

TEXAS

    269     22,000   AC (FlexRig3)     1,500  

WYOMING

    271     18,000   AC (FlexRig4)     1,500  

NORTH DAKOTA

    272     18,000   AC (FlexRig4)     1,500  

COLORADO

    273     18,000   AC (FlexRig4)     1,500  

TEXAS

    274     18,000   AC (FlexRig4)     1,500  

COLORADO

    275     18,000   AC (FlexRig4)     1,500  

COLORADO

    276     18,000   AC (FlexRig4)     1,500  

COLORADO

    277     18,000   AC (FlexRig4)     1,500  

COLORADO

    278     18,000   AC (FlexRig4)     1,500  

TEXAS

    279     18,000   AC (FlexRig4)     1,500  

COLORADO

    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  

PENNSYLVANIA

    285     18,000   AC (FlexRig4)     1,500  

NORTH DAKOTA

    286     18,000   AC (FlexRig4)     1,500  

PENNSYLVANIA

    287     18,000   AC (FlexRig4)     1,500  

TEXAS

    288     18,000   AC (FlexRig4)     1,500  

TEXAS

    289     18,000   AC (FlexRig4)     1,500  

COLORADO

    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  

OKLAHOMA

    297     18,000   AC (FlexRig4)     1,500  

COLORADO

    298     18,000   AC (FlexRig4)     1,500  

TEXAS

    299     18,000   AC (FlexRig4)     1,500  

TEXAS

    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  

COLORADO

    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  

19


Table of Contents

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

COLORADO

    318     18,000   AC (FlexRig4)     1,500  

COLORADO

    319     18,000   AC (FlexRig4)     1,500  

NORTH DAKOTA

    320     18,000   AC (FlexRig4)     1,500  

COLORADO

    321     18,000   AC (FlexRig4)     1,500  

COLORADO

    322     18,000   AC (FlexRig4)     1,500  

TEXAS

    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  

NEW MEXICO

    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  

TEXAS

    348     8,000   AC (FlexRig4)     1,150  

TEXAS

    349     8,000   AC (FlexRig4)     1,150  

TEXAS

    351     8,000   AC (FlexRig4)     1,150  

TEXAS

    352     8,000   AC (FlexRig4)     1,150  

NORTH DAKOTA

    353     18,000   AC (FlexRig4)     1,500  

PENNSYLVANIA

    354     18,000   AC (FlexRig4)     1,500  

TEXAS

    355     8,000   AC (FlexRig4)     1,150  

TEXAS

    356     8,000   AC (FlexRig4)     1,150  

TEXAS

    360     8,000   AC (FlexRig4)     1,150  

TEXAS

    361     8,000   AC (FlexRig4)     1,150  

TEXAS

    362     8,000   AC (FlexRig4)     1,150  

TEXAS

    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  

TEXAS

    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  

TEXAS

    379     22,000   AC (FlexRig3)     1,500  

TEXAS

    380     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    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  

20


Table of Contents

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

PENNSYLVANIA

    385     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    386     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    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  

NEW MEXICO

    415     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    416     22,000   AC (FlexRig3)     1,500  

TEXAS

    417     22,000   AC (FlexRig3)     1,500  

TEXAS

    418     22,000   AC (FlexRig3)     1,500  

TEXAS

    419     22,000   AC (FlexRig3)     1,500  

TEXAS

    420     22,000   AC (FlexRig3)     1,500  

TEXAS

    421     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    422     22,000   AC (FlexRig3)     1,500  

TEXAS

    423     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    424     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    425     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    426     22,000   AC (FlexRig3)     1,500  

TEXAS

    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  

OKLAHOMA

    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  

21


Table of Contents

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

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  

TEXAS

    474     22,000   AC (FlexRig3)     1,500  

TEXAS

    475     22,000   AC (FlexRig3)     1,500  

TEXAS

    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

    489     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    490     22,000   AC (FlexRig3)     1,500  

LOUISIANA

    491     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    492     22,000   AC (FlexRig3)     1,500  

TEXAS

    493     22,000   AC (FlexRig3)     1,500  

TEXAS

    494     22,000   AC (FlexRig3)     1,500  

TEXAS

    495     22,000   AC (FlexRig3)     1,500  

TEXAS

    496     22,000   AC (FlexRig3)     1,500  

TEXAS

    497     22,000   AC (FlexRig3)     1,500  

TEXAS

    498     22,000   AC (FlexRig3)     1,500  

TEXAS

    499     22,000   AC (FlexRig3)     1,500  

22


Table of Contents

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

PENNSYLVANIA

    500     25,000   AC (FlexRig5)     1,500  

TEXAS

    501     25,000   AC (FlexRig5)     1,500  

TEXAS

    502     25,000   AC (FlexRig5)     1,500  

TEXAS

    503     25,000   AC (FlexRig5)     1,500  

TEXAS

    504     25,000   AC (FlexRig5)     1,500  

TEXAS

    505     25,000   AC (FlexRig5)     1,500  

TEXAS

    506     25,000   AC (FlexRig5)     1,500  

TEXAS

    507     25,000   AC (FlexRig5)     1,500  

TEXAS

    508     25,000   AC (FlexRig5)     1,500  

TEXAS

    509     25,000   AC (FlexRig5)     1,500  

TEXAS

    510     25,000   AC (FlexRig5)     1,500  

TEXAS

    511     25,000   AC (FlexRig5)     1,500  

TEXAS

    512     25,000   AC (FlexRig5)     1,500  

TEXAS

    513     25,000   AC (FlexRig5)     1,500  

TEXAS

    514     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    515     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    516     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    517     25,000   AC (FlexRig5)     1,500  

TEXAS

    518     25,000   AC (FlexRig5)     1,500  

TEXAS

    519     25,000   AC (FlexRig5)     1,500  

WYOMING

    520     25,000   AC (FlexRig5)     1,500  

PENNSYLVANIA

    521     25,000   AC (FlexRig5)     1,500  

COLORADO

    522     25,000   AC (FlexRig5)     1,500  

TEXAS

    523     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    524     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    525     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    526     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    527     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    528     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    529     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    530     25,000   AC (FlexRig5)     1,500  

OHIO

    531     25,000   AC (FlexRig5)     1,500  

TEXAS

    532     25,000   AC (FlexRig5)     1,500  

TEXAS

    533     25,000   AC (FlexRig5)     1,500  

LOUISIANA

    534     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    535     25,000   AC (FlexRig5)     1,500  

NEW MEXICO

    536     25,000   AC (FlexRig5)     1,500  

TEXAS

    537     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    538     25,000   AC (FlexRig5)     1,500  

TEXAS

    539     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    540     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    541     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    542     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    543     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    544     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    545     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    547     25,000   AC (FlexRig5)     1,500  

TEXAS

    552     25,000   AC (FlexRig5)     1,500  

TEXAS

    556     25,000   AC (FlexRig5)     1,500  

23


Table of Contents

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

TEXAS

    600     22,000   AC (FlexRig3)     1,500  

TEXAS

    601     22,000   AC (FlexRig3)     1,500  

TEXAS

    602     22,000   AC (FlexRig3)     1,500  

TEXAS

    603     22,000   AC (FlexRig3)     1,500  

TEXAS

    604     22,000   AC (FlexRig3)     1,500  

TEXAS

    605     22,000   AC (FlexRig3)     1,500  

TEXAS

    606     22,000   AC (FlexRig3)     1,500  

TEXAS

    607     22,000   AC (FlexRig3)     1,500  

PENNSYLVANIA

    608     22,000   AC (FlexRig3)     1,500  

TEXAS

    609     22,000   AC (FlexRig3)     1,500  

TEXAS

    610     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    611     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    612     22,000   AC (FlexRig3)     1,500  

TEXAS

    613     22,000   AC (FlexRig3)     1,500  

TEXAS

    614     22,000   AC (FlexRig3)     1,500  

TEXAS

    615     22,000   AC (FlexRig3)     1,500  

TEXAS

    616     22,000   AC (FlexRig3)     1,500  

TEXAS

    617     22,000   AC (FlexRig3)     1,500  

TEXAS

    618     22,000   AC (FlexRig3)     1,500  

TEXAS

    619     22,000   AC (FlexRig3)     1,500  

TEXAS

    620     22,000   AC (FlexRig3)     1,500  

TEXAS

    621     22,000   AC (FlexRig3)     1,500  

TEXAS

    622     22,000   AC (FlexRig3)     1,500  

TEXAS

    623     22,000   AC (FlexRig3)     1,500  

TEXAS

    624     22,000   AC (FlexRig3)     1,500  

TEXAS

    625     22,000   AC (FlexRig3)     1,500  

TEXAS

    626     22,000   AC (FlexRig3)     1,500  

TEXAS

    627     22,000   AC (FlexRig3)     1,500  

OHIO

    628     22,000   AC (FlexRig3)     1,500  

TEXAS

    629     22,000   AC (FlexRig3)     1,500  

TEXAS

    630     22,000   AC (FlexRig3)     1,500  

TEXAS

    631     22,000   AC (FlexRig3)     1,500  

TEXAS

    632     22,000   AC (FlexRig3)     1,500  

TEXAS

    633     22,000   AC (FlexRig3)     1,500  

TEXAS

    634     22,000   AC (FlexRig3)     1,500  

TEXAS

    635     22,000   AC (FlexRig3)     1,500  

TEXAS

    636     22,000   AC (FlexRig3)     1,500  

TEXAS

    637     22,000   AC (FlexRig3)     1,500  

TEXAS

    638     22,000   AC (FlexRig3)     1,500  

TEXAS

    639     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    640     22,000   AC (FlexRig3)     1,500  

TEXAS

    641     22,000   AC (FlexRig3)     1,500  

TEXAS

    642     22,000   AC (FlexRig3)     1,500  

TEXAS

    643     22,000   AC (FlexRig3)     1,500  

TEXAS

    644     22,000   AC (FlexRig3)     1,500  

TEXAS

    645     22,000   AC (FlexRig3)     1,500  

TEXAS

    646     22,000   AC (FlexRig3)     1,500  

TEXAS

    648     22,000   AC (FlexRig3)     1,500  

TEXAS

    649     22,000   AC (FlexRig3)     1,500  

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

TEXAS

    650     22,000   AC (FlexRig3)     1,500  

TEXAS

    651     22,000   AC (FlexRig3)     1,500  

TEXAS

    652     22,000   AC (FlexRig3)     1,500  

TEXAS

    653     22,000   AC (FlexRig3)     1,500  

TEXAS

    659     22,000   AC (FlexRig3)     1,500  

CONVENTIONAL RIGS

   
 
   
 
 

 

   
 
 

TEXAS

   
139
   
30,000
 

SCR

   
3,000
 

LOUISIANA

    161     30,000   SCR     3,000  

OFFSHORE PLATFORM RIGS

   
 
   
 
 

 

   
 
 

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

    203     20,000   Self-Erecting     2,500  

GULF OF MEXICO

    204     30,000   Tension-leg     3,000  

GULF OF MEXICO

    205     20,000   Self-Erecting     2,000  

GULF OF MEXICO

    206     20,000   Self-Erecting     2,000  

        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,  
 
  2011   2012   2013   2014   2015  

U.S. Land Rigs

                               

Number of rigs at end of period

    248     282     302     329     343  

Average rig utilization rate during period (1)

    86 %   89 %   82 %   86 %   62 %

U.S. Offshore Platform Rigs

   
 
   
 
   
 
   
 
   
 
 

Number of rigs at end of period

    9     9     9     9     9  

Average rig utilization rate during period (1)

    77 %   79 %   89 %   89 %   93 %

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

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        The following table sets forth certain information concerning our international drilling rigs as of September 30, 2015:

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

Argentina

    123     26,000   SCR     2,100  

Argentina

    151     30,000+   SCR     3,000  

Argentina

    175     30,000   SCR     3,000  

Argentina

    177     30,000   SCR     3,000  

Argentina

    210     22,000   AC (FlexRig3)     1,500  

Argentina

    211     22,000   AC (FlexRig3)     1,500  

Argentina

    213     22,000   AC (FlexRig3)     1,500  

Argentina

    217     22,000   AC (FlexRig3)     1,500  

Argentina

    219     22,000   AC (FlexRig3)     1,500  

Argentina

    224     22,000   AC (FlexRig3)     1,500  

Argentina

    229     22,000   AC (FlexRig3)     1,500  

Argentina

    230     22,000   AC (FlexRig3)     1,500  

Argentina

    234     22,000   AC (FlexRig3)     1,500  

Argentina

    235     22,000   AC (FlexRig3)     1,500  

Argentina

    238     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  

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

    133     30,000   SCR     3,000  

Colombia

    152     30,000+   SCR     3,000  

Colombia

    237     18,000   AC (FlexRig3)     1,500  

Colombia

    243     22,000   AC (FlexRig3)     1,500  

Colombia

    291     8,000   AC (FlexRig4)     1,150  

Colombia

    333     8,000   AC (FlexRig4)     1,150  

Colombia

    334     8,000   AC (FlexRig4)     1,150  

Colombia

    900     30,000+   AC Drive     3,000  

Ecuador

    117     26,000   SCR     2,500  

Ecuador

    121     20,000   SCR     1,700  

Ecuador

    132     18,000   SCR     1,500  

Ecuador

    138     26,000   SCR     2,500  

Ecuador

    176     18,000   SCR     1,500  

Ecuador

    190     26,000   SCR     2,000  

UAE

    476     22,000   AC (FlexRig3)     1,500  

UAE

    484     22,000   AC (FlexRig3)     1,500  

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

 
  Years ended September 30,  
 
  2011   2012   2013   2014   2015  

Number of rigs at end of period

    24     29     29     36     38  

Average rig utilization rate during period (1)(2)

    70 %   77 %   82 %   76 %   53 %

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

(2)
Does not include rigs returned to the United States for major modifications and upgrades.

STOCK PORTFOLIO

        Information required by this item regarding our stock portfolio may be found on, and is incorporated by reference to, Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations—Stock Portfolio Held" included in this Form 10-K.

Item 3.    LEGAL PROCEEDINGS

    1.
    Investigation by the Department of the Interior.

        On November 8, 2013, the United States District Court for the Eastern District of Louisiana approved the previously disclosed October 30, 2013 plea agreement between our wholly owned subsidiary, Helmerich & Payne International Drilling Co., and the United States Department of Justice, United States Attorney's Office for the Eastern District of Louisiana ("DOJ"). The court's approval of the plea agreement resolved the DOJ's investigation into certain choke manifold testing irregularities that occurred in 2010 at one of Helmerich & Payne International Drilling Co.'s offshore platform rigs in the Gulf of Mexico. We have been engaged in discussions with the Inspector General's office of the Department of the Interior regarding the same events that were the subject of the DOJ's investigation. Although we presently believe that the outcome of our discussions will not have a material adverse effect on us, we can provide no assurances as to the timing or eventual outcome of these discussions.

    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. ("PDVSA") and PDVSA Petroleo, S.A. ("Petroleo"). We are seeking damages for the taking of our Venezuelan drilling business in violation of international law and for breach of contract. 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.

    3.
    Environmental Claim.

        On or about August 28, 2015, we received a Notice of Intent to File a Civil Administrative Complaint from the United States Environmental Protection Agency indicating that the EPA planned to file an Administrative Complaint against us in connection with an incident that occurred in May of 2014 at a customer's location in Ohio, where one of our domestic land rigs was working (the "NOI"). Specifically, the EPA alleges that we violated certain portions of the Clean Water Act and the oil pollution prevention regulations when oil was discharged from the well and migrated into an unnamed tributary. The EPA is proposing a penalty in the amount of $186,868. We have disputed the NOI and are currently awaiting a response from the EPA. In the event that the EPA finds against us and imposes a penalty, we will seek indemnification from our customer.

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Item 4.    MINE SAFETY DISCLOSURES

        Not applicable.


EXECUTIVE OFFICERS OF THE COMPANY

        The following table sets forth the names and ages of our executive officers, together with all positions and offices held by such executive officers with the Company or the Company's wholly-owned subsidiary, Helmerich & Payne International Drilling Co. Except as noted below, all positions and offices held are with the Company. 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.

John W. Lindsay, 54   President and Chief Executive Officer since March 2014; President and Chief Operating Officer from September 2012 to March 2014; 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

Juan Pablo Tardio, 50

 

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

Robert L. Stauder, 53

 

Senior Vice President and Chief Engineer, Helmerich & Payne International Drilling Co., since January 2012; Vice President and Chief Engineer of Helmerich & Payne International Drilling Co. from July 2010 to January 2012; Vice President, Engineering of Helmerich & Payne International Drilling Co. from 2006 to July 2010

Jeffrey L. Flaherty, 52

 

Senior Vice President of Operations, Helmerich & Payne International Drilling Co., since August 2014; Senior Vice President, U.S. Land Operations of Helmerich & Payne International Drilling Co. from January 2012 to August 2014; Vice President, U.S. Land Operations of Helmerich & Payne International Drilling Co. from March 2006 to January 2012

John R. Bell, 45

 

Vice President, Corporate Services since January 2015; Vice President of Human Resources from March 2012 to January 2015; Director of Human Resources from July 2002 to March 2012

Cara M. Hair, 39

 

Vice President, General Counsel and Chief Compliance Officer since March 2015; Deputy General Counsel from June 2014 to March 2015; Senior Attorney from December 2012 to June 2014; Attorney from 2006 to December 2012

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PART II

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

    Market Information

        The principal market on which our common stock is traded is the New York Stock Exchange under the symbol "HP". As of November 13, 2015, there were 611 record holders of our common stock as listed by our transfer agent's records. 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:

 
  2014   2015  
Quarter
  High   Low   High   Low  

First

  $ 84.87   $ 68.87   $ 98.47   $ 59.24  

Second

    108.43     81.34     71.55     54.00  

Third

    118.02     103.54     79.90     67.60  

Fourth

    118.95     96.79     70.34     46.16  

    Dividends

        We paid quarterly cash dividends during the past two fiscal years as shown in the table below. Payment of future dividends will depend on earnings and other factors.

 
  Paid per Share   Total Payment  
 
  Fiscal   Fiscal  
Quarter
  2014   2015   2014   2015  

First

  $ .5000   $ .6875   $ 53,859,536   $ 74,822,055  

Second

    .6250     .6875     67,685,672     74,525,525  

Third

    .6250     .6875     67,996,052     74,478,918  

Fourth

    .6875     .6875     74,844,562     74,540,202  

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    Performance Graph

        The following performance graph reflects the yearly percentage change in our cumulative total stockholder return on common stock as compared with the cumulative total return on the S&P 500 Index and the S&P 500 Oil & Gas Drilling Index. All cumulative returns assume an initial investment of $100, the reinvestment of dividends and are calculated on a fiscal year basis ending on September 30 of each year.

GRAPHIC

 
   
  INDEXED RETURNS
Years Ending
 
 
  Base
Period
Sep10
 
Company / Index
  Sep11   Sep12   Sep13   Sep14   Sep15  

Helmerich & Payne, Inc. 

    100     100.79     118.84     174.52     253.98     127.78  

S&P 500 Index

    100     101.15     131.69     157.17     188.18     187.02  

S&P 500 Oil & Gas Drilling Index

    100     88.93     106.70     118.16     103.77     46.80  

        The above performance graph and related information shall not be deemed to be "soliciting material" or to be "filed" with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.

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Item 6.    SELECTED FINANCIAL DATA

        The following table summarizes selected financial information and should be read in conjunction with Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item 8—"Financial Statements and Supplementary Data" included in this Form 10-K.


Five-year Summary of Selected Financial Data

 
  2015   2014   2013   2012   2011  
 
  (in thousands except per share amounts)
 

Operating revenues

  $ 3,165,441   $ 3,719,707   $ 3,387,614   $ 3,151,802   $ 2,543,894  

Income from continuing operations

    422,272     708,766     721,453     573,609     434,668  

Income (loss) from discontinued operations

    (47 )   (47 )   15,186     7,436     (482 )

Net income

    422,225     708,719     736,639     581,045     434,186  

Basic earnings per share from continuing operations

    3.90     6.54     6.75     5.35     4.06  

Basic earnings per share from discontinued operations

            0.14     0.07      

Basic earnings per share

    3.90     6.54     6.89     5.42     4.06  

Diluted earnings per share from continuing operations

    3.87     6.46     6.65     5.27     3.99  

Diluted earnings per share from discontinued operations

            0.14     0.07      

Diluted earnings per share

    3.87     6.46     6.79     5.34     3.99  

Total assets*^

    7,152,012     6,720,998     6,263,564     5,719,413     5,003,001  

Long-term debt^

    492,443     39,502     79,137     193,737     234,279  

Cash dividends declared per common share

    2.750     2.625     1.300     0.280     0.260  

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

^
Total assets and Long-term debt for 2014 and prior periods restated to reflect the retrospective adoption of Accounting Standards Update No. 2015-03 "Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" issued by the Financial Accounting Standards Board in April 2015.

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

Risk Factors and Forward-Looking Statements

        The following discussion should be read in conjunction with Part I of this Form 10-K as well as the Consolidated Financial Statements and related notes thereto included in Item 8—"Financial Statements and Supplementary Data" of this Form 10-K. 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 and Analysis of Financial Condition and Results of Operations include forward-looking statements. These forward-looking statements are based on various assumptions. We caution that, while we believe such assumptions to be reasonable and make them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. We are including this cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by us or persons acting on our behalf. The factors identified in this cautionary statement and those factors discussed under Item 1A—"Risk Factors" of this 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 390 drilling rigs at September 30, 2015. Our contract drilling segments consist of the U.S. Land segment with 343 rigs, the Offshore segment with nine offshore platform rigs and the International Land segment with 38 rigs at September 30, 2015. During fiscal 2015, we placed into service 30 new FlexRigs and completed another nine new FlexRigs. At the close of fiscal 2015, we had 170 contracted rigs, compared to 325 contracted rigs at the same time during the prior year. Faced with a global oversupply of oil, the short-term outlook for the industry is unfavorable. However, our long-term strategy remains focused on innovation, technology, safety and customer satisfaction. We believe that our advanced rig fleet, financial strength, long-term contract backlog, strong customer base, and best-in-class reputation position us very well to manage the current slowdown and take advantage of opportunities that lie ahead.

        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 pertain only to our continuing operations. Unless otherwise indicated, references to 2015, 2014 and 2013 in the following discussion are referring to fiscal years 2015, 2014 and 2013.

Results of Operations

        All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net income for 2015 was $422.2 million ($3.87 per share), compared with $708.7 million

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($6.46 per share) for 2014 and $736.6 million ($6.79 per share) for 2013. Included in our net income is after-tax gains from the sale of investment securities of $27.8 million ($0.25 per share) in 2014 and $97.9 million ($0.91 per share) in 2013. Net income also includes after-tax gains from the sale of assets of $7.4 million ($0.07 per share) in 2015, $12.7 million ($0.12 per share) in 2014 and $12.2 million ($0.11 per share) in 2013.

        Consolidated operating revenues were $3.2 billion in 2015, $3.7 billion in 2014 and $3.4 billion in 2013. As oil prices steeply declined during 2015, customers aggressively reduced drilling budgets. As a result, we experienced a significant decline in rig activity. The number of revenue days in our U.S. Land segment totaled 75,866 in 2015, compared to 100,638 in 2014 and 88,620 in 2013. Our U.S. land rig utilization was 62 percent in 2015, 86 percent in 2014 and 82 percent in 2013. The average number of U.S. land rigs available was 336 rigs in 2015, 319 rigs in 2014 and 295 rigs in 2013. Revenue in the Offshore segment steadily decreased in 2015 after increasing in 2014 from 2013 while rig utilization for offshore rigs was 93 percent in 2015, compared to 89 percent in 2014 and 2013. The International Land segment has also been affected by the decline in oil prices causing revenue days to decline to 7,474 in 2015 from 8,303 in 2014 and 8,707 in 2013. Rig utilization in our International Land segment was 53 percent in 2015, 76 percent in 2014 and 82 percent in 2013.

        In 2014 and 2013, we had $45.2 million and $162.1 million in gains from the sale of investment securities, respectively. Interest and dividend income was $5.8 million, $1.6 million and $1.7 million in 2015, 2014 and 2013, respectively. The increase was primarily the result of Atwood Oceanics, Inc. declaring dividends during 2015.

        Direct operating costs in 2015 were $1.7 billion or 54 percent of operating revenues, compared with $2.0 billion or 54 percent of operating revenues in 2014 and $1.9 billion or 55 percent of operating revenues in 2013.

        Depreciation expense was $607.0 million in 2015, $523.5 million in 2014 and $455.6 million in 2013. Included in depreciation are abandonments of equipment of $43.6 million in 2015, $23.0 million in 2014 and $9.1 million in 2013. Depreciation expense, exclusive of the abandonments, increased over the three-year period as we placed into service 30 new rigs in 2015, 45 in 2014 and 20 in 2013. Depreciation expense in 2016 is expected to increase from 2015 from new rigs placed into service during 2015 and additional rigs placed into service during 2016. (See Liquidity and Capital Resources.) Abandonments increased over the three-year period primarily due to decommissioning 23 rigs in 2015, nine rigs in 2014 and two rigs in 2013.

        As conditions warrant, management performs an analysis of the industry market conditions impacting its long-lived assets in each drilling segment. The overall down turn in our industry, primarily caused by low oil and gas prices, served as an impairment indicator and an impairment analysis was performed. Based on this analysis, management determines if any impairment is required. In 2015, we recorded $39.2 million of impairment charges to reduce the carrying values of seven SCR rigs in our International Land segment to their estimated fair value. The impairment charge is not expected to have an impact on our liquidity or debt covenants. In 2014 and 2013, no impairment was recorded.

        General and administrative expenses totaled $134.9 million in 2015, $135.1 million in 2014 and $126.3 million in 2013. The $8.8 million increase in 2014 from 2013 is primarily due to continued growth in the number of employees in the comparative periods and increases in salaries, bonuses, and stock-based compensation.

        Interest expense net of amounts capitalized totaled $15.0 million in 2015, $4.7 million in 2014 and $6.1 million in 2013. Interest expense is primarily attributable to fixed-rate debt outstanding. Interest expense increased in 2015 from 2014 primarily due to the issuance of $500 million unsecured senior notes in March 2015. Interest expense decreased in 2014 from 2013 primarily due to a reduction in outstanding debt balances during the two years. Capitalized interest was $7.0 million, $7.7 million and $8.8 million in 2015, 2014 and 2013, respectively. All of the capitalized interest is attributable to our rig construction program.

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        The provision for income taxes totaled $243.4 million in 2015, $387.5 million in 2014 and $392.8 million in 2013. The effective income tax rate was 36.6 percent in 2015 compared to 35.4 percent in 2014 and 35.3 percent in 2013. 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 2015, 2014 and 2013, we incurred $16.1 million, $15.9 million and $15.2 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 2016.

        Expenses incurred within the country of Venezuela are reported as discontinued operations. Included in 2013 are proceeds from arbitration disputes with third parties not affiliated with the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. ("PDVSA") or PDVSA Petroleo, S.A. ("Petroleo") related to the seizure of our property in Venezuela on June 30, 2010. Proceeds of $15.0 million were received and recorded as discontinued operations in 2013.

        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 Venezuelan government, PDVSA and Petroleo. Our subsidiaries seek damages for the taking of their Venezuelan drilling business in violation of international law and for breach of contract. 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.

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        The following tables summarize operations by reportable operating segment.

Comparison of the years ended September 30, 2015 and 2014

 
  2015   2014   % Change  
 
  (in thousands, except operating statistics)
 

U.S. LAND OPERATIONS

                   

Operating revenues

  $ 2,523,518   $ 3,099,954     (18.6 )%

Direct operating expenses

    1,254,424     1,576,702     (20.4 )

General and administrative expense

    50,769     41,573     22.1  

Depreciation

    519,950     455,934     14.0  

Segment operating income

  $ 698,375   $ 1,025,745     (31.9 )

Operating Statistics:

                   

Revenue days

    75,866     100,638     (24.6 )%

Average rig revenue per day

  $ 30,211   $ 28,194     7.2  

Average rig expense per day

  $ 13,483   $ 13,058     3.3  

Average rig margin per day

  $ 16,728   $ 15,136     10.5  

Number of rigs at end of period

    343     329     4.3  

Rig utilization

    62 %   86 %   (27.9 )

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $231,528 and $262,532 for 2015 and 2014, respectively.

Rig utilization in 2015 excludes nine FlexRigs completed and ready for delivery at September 30, 2015.

        Operating income in the U.S. Land segment decreased to $698.4 million in 2015 from $1.0 billion in 2014 primarily due to a decrease in revenue days and the decommissioning of 23 rigs. Included in U.S. land revenues for 2015 and 2014 is approximately $203.6 million and $11.7 million, respectively, from early termination of fixed-term contracts. Excluding early termination related revenue, the average revenue per day for 2015 decreased by $550 to $27,528 from $28,078 in 2014 which was also a factor in the decrease of operating income during the comparative periods. Direct operating expenses as a percentage of revenue were 50 percent in 2015 and 51 percent in 2014.

        Rig utilization decreased to 62 percent in 2015 from 86 percent in 2014. The total number of rigs at September 30, 2015 was 343 compared to 329 rigs at September 30, 2014. The net increase is due to 30 new FlexRigs completed and placed into service, nine new FlexRigs completed and ready for delivery, five FlexRigs transferred to the International Land segment, two FlexRigs transferred from the International Land segment, one conventional rig transferred from the International Land segment and 23 older rigs removed from service. As of November 12, 2015, six announced FlexRigs remained to be delivered.

        Depreciation includes charges for abandoned equipment of $42.6 million and $21.5 million in 2015 and 2014, respectively. Included in abandonments in 2015 is the decommissioning of 23 SCR rigs, including six conventional rigs, six FlexRig1s and 11 FlexRig2s, and spare equipment for drilling rigs. Included in abandonments in 2014 is the decommissioning of nine conventional rigs and spare equipment for drilling rigs. Excluding the abandonment amounts, depreciation in 2015 increased 10 percent from 2014 due to the increase in available rigs. As a result of the new FlexRigs added in fiscal 2015 and additional rigs scheduled for completion in fiscal 2016, we anticipate depreciation expense to continue to increase in fiscal 2016.

        At September 30, 2015, 145 out of 343 existing rigs in the U.S. Land segment were generating revenue. Of the 145 rigs generating revenue, 120 were under fixed-term contracts, and 25 were working in the spot market. At November 12, 2015, the number of existing rigs under fixed-term contracts in the segment was 108 and the number of rigs working in the spot market was 24.

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Comparison of the years ended September 30, 2015 and 2014

 
  2015   2014   % Change  
 
  (in thousands, except operating statistics)
 

OFFSHORE OPERATIONS

                   

Operating revenues

  $ 241,043   $ 250,811     (3.9 )%

Direct operating expenses

    158,138     158,834     (0.4 )

General and administrative expense

    3,517     9,858     (64.3 )

Depreciation

    11,659     12,300     (5.2 )

Segment operating income

  $ 67,729   $ 69,819     (3.0 )

Operating Statistics:

                   

Revenue days

    3,067     2,920     5 %

Average rig revenue per day

  $ 44,125   $ 63,094     (30.1 )

Average rig expense per day

  $ 27,246   $ 37,653     (27.6 )

Average rig margin per day

  $ 16,879   $ 25,441     (33.7 )

Number of rigs at end of period

    9     9      

Rig utilization

    93 %   89 %   4.5  

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $32,868 and $19,007 for 2015 and 2014, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.

        Total revenue and segment operating income in our Offshore segment decreased in 2015 from 2014 primarily due to one rig being idle over half of the year, a contractual decrease in a dayrate for one rig and several other rigs moving to lower pricing while on standby or other standby-type dayrate. At September 30, 2015 and 2014, eight of our nine rigs were contracted.

Comparison of the years ended September 30, 2015 and 2014

 
  2015   2014   % Change  
 
  (in thousands, except operating statistics)
 

INTERNATIONAL LAND OPERATIONS

                   

Operating revenues

  $ 386,693   $ 355,532     8.8 %

Direct operating expenses

    290,752     274,894     5.8  

General and administrative expense

    3,342     4,289     (22.1 )

Depreciation

    56,287     39,932     41.0  

Asset Impairment charge

    39,242         100.0  

Segment operating income (loss)

  $ (2,930 ) $ 36,417     (108.0 )

Operating Statistics:

                   

Revenue days

    7,474     8,303     (10.0 )%

Average rig revenue per day

  $ 46,684   $ 37,117     25.8  

Average rig expense per day

  $ 34,211   $ 27,278     25.4  

Average rig margin per day

  $ 12,473   $ 9,839     26.8  

Number of rigs at end of period

    38     36     5.6  

Rig utilization

    53 %   76 %   (30.3 )

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $37,776 and $47,350 for 2015 and 2014, respectively. Also excluded are the effects of currency revaluation expense.

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        The International Land segment had an operating loss of $2.9 million for 2015 compared to operating income of $36.4 million for 2014. Included in International land revenues in 2015 is approximately $18.7 million related to early termination of fixed-term contracts.

        Excluding early termination revenue in 2015, the average rig revenue per day increased by $7,065 as compared to 2014. Rigs transferred into the segment during 2015 and 2014 favorably impacted revenue and revenue per day. The average number of active rigs was 20.5 during 2015 compared to 22.7 during 2014.

        The average rig expense increase was attributable to expenses incurred on rigs that have become idle and other costs associated with rigs transitioning between locations. The average rig expense was also impacted by approximately $673 per day related to a charge for allowance for doubtful accounts.

        During 2015, the total number of available rigs increased by two due to five FlexRigs transferred from the U.S. Land segment, two FlexRigs transferred to the U.S. Land segment and one conventional rig transferred to the U.S. Land segment. At the close of 2015 and 2014, we had 17 and 23 rigs working, respectively.

        During the fourth fiscal quarter of 2015, we recorded a $39.2 million impairment charge to reduce the carrying values of seven SCR rigs located in our International Land segment to their estimated fair value. The impairment charge is not expected to have an impact on our liquidity or debt covenants.

Comparison of the years ended September 30, 2014 and 2013

 
  2014   2013   % Change  
 
  (in thousands, except operating statistics)
 

U.S. LAND OPERATIONS

                   

Operating revenues

  $ 3,099,954   $ 2,785,449     11.3 %

Direct operating expenses

    1,576,702     1,424,716     10.7  

General and administrative expense

    41,573     37,070     12.1  

Depreciation

    455,934     391,072     16.6  

Segment operating income

  $ 1,025,745   $ 932,591     10.0  

Operating Statistics:

                   

Revenue days

    100,638     88,620     13.6 %

Average rig revenue per day

  $ 28,194   $ 28,382     (0.7 )

Average rig expense per day

  $ 13,058   $ 13,029     0.2  

Average rig margin per day

  $ 15,136   $ 15,353     (1.4 )

Number of rigs at end of period

    329     302     8.9  

Rig utilization

    86 %   82 %   4.9  

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $262,532 and $270,223 for 2014 and 2013, respectively.

Rig utilization in 2013 excludes two FlexRigs completed and ready for delivery at September 30, 2013.

        Operating income in the U.S. Land segment increased to $1.0 billion in 2014 from $932.6 million in 2013 primarily due to an increase in revenue days. Included in U.S. land revenues for 2014 and 2013 is approximately $11.7 million and $19.0 million, respectively, from early termination of fixed-term contracts. Excluding early termination related revenue, the average rig revenue per day for 2014 only slightly decreased by $90 to $28,078 from $28,168 in 2013. Direct operating expenses as a percentage of revenue were 51 percent in 2014 and 51 percent in 2013.

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        Rig utilization increased to 86 percent in 2014 from 82 percent in 2013. The total number of available rigs at September 30, 2014 was 329 compared to 302 rigs at September 30, 2013. The net increase is due to 42 new FlexRigs completed and placed into service, six FlexRigs transferred to the International Land segment and nine older conventional rigs removed from service.

        Depreciation includes charges for abandoned equipment of $21.5 million and $8.2 million in 2014 and 2013, respectively. Included in abandonments in 2014 is the decommissioning of nine conventional rigs and spare equipment for drilling rigs. Included in abandonments in 2013 is the decommissioning of two conventional rigs. Excluding the abandonment amounts, depreciation in 2014 increased 13 percent from 2013 due to the increase in available rigs.

Comparison of the years ended September 30, 2014 and 2013

 
  2014   2013   % Change  
 
  (in thousands, except operating statistics)
 

OFFSHORE OPERATIONS

                   

Operating revenues

  $ 250,811   $ 221,863     13.0 %

Direct operating expenses

    158,834     146,184     8.7  

General and administrative expense

    9,858     8,849     11.4  

Depreciation

    12,300     13,766     (10.6 )

Segment operating income

  $ 69,819   $ 53,064     31.6  

Operating Statistics:

                   

Revenue days

    2,920     2,920     %

Average rig revenue per day

  $ 63,094   $ 61,069     3.3  

Average rig expense per day

  $ 37,653   $ 37,654      

Average rig margin per day

  $ 25,441   $ 23,415     8.7  

Number of rigs at end of period

    9     9      

Rig utilization

    89 %   89 %    

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $19,007 and $19,701 for 2014 and 2013, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.

        Total revenue and segment operating income in our Offshore segment increased in 2014 from 2013 primarily due to our offshore management contracts. Included in 2013 direct operating expenses is a one-time charge of $6.4 million related to an incident in the Gulf of Mexico. At September 30, 2014 and 2013, eight of our nine rigs were working.

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Comparison of the years ended September 30, 2014 and 2013

 
  2014   2013   % Change  
 
  (in thousands, except operating statistics)
 

INTERNATIONAL LAND OPERATIONS

                   

Operating revenues

  $ 355,532   $ 366,841     (3.1 )%

Direct operating expenses

    274,894     282,335     (2.6 )

General and administrative expense

    4,289     3,911     9.7  

Depreciation

    39,932     36,000     10.9  

Segment operating income

  $ 36,417   $ 44,595     (18.3 )

Operating Statistics:

                   

Revenue days

    8,303     8,707     (4.6 )%

Average rig revenue per day

  $ 37,117   $ 37,246     (0.3 )

Average rig expense per day

  $ 27,278   $ 27,589     (1.1 )

Average rig margin per day

  $ 9,839   $ 9,657     1.9  

Number of rigs at end of period

    36     29     24.1  

Rig utilization

    76 %   82 %   (7.3 )

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $47,350 and $42,542 for 2014 and 2013, respectively. Also excluded are the effects of currency revaluation expense.

        The International Land segment had operating income of $36.4 million for 2014 compared to $44.6 million for 2013. Included in International land revenues in 2013 is approximately $5.3 million related to early termination fees.

        Excluding the $5.3 million early termination revenues in 2013, segment operating income in 2014 decreased from 2013 with revenue days decreasing 4.6 percent and rig utilization decreasing to 76 percent in 2014 from 82 percent in 2013. The total number of available rigs increased to 36 at September 30, 2014 from 29 at September 30, 2013.

        During 2014, the total number of available rigs increased by seven due to one new 3,000 horsepower AC drive rig added to the fleet and six FlexRigs transferred from the U.S. Land segment. At the close of 2014 and 2013, we had 23 and 22 rigs working, respectively.

LIQUIDITY AND CAPITAL RESOURCES

        Our capital spending was $1.1 billion in 2015, $952.9 million in 2014 and $809.1 million in 2013. Net cash provided from operating activities was $1.4 billion in 2015, $1.1 billion in 2014 and $997.2 million in 2013. Our 2016 capital spending is currently estimated to be between $300 million and $400 million, depending primarily on drilling market conditions. This estimate includes contracted new builds, capital maintenance requirements, tubulars and other special projects.

        Historically, we have financed operations primarily through internally generated cash flows. In periods when internally generated cash flows are not sufficient to meet liquidity needs, we will either borrow from available credit sources or we may sell portfolio securities. Likewise, if we are generating excess cash flows, we may invest in short-term money market securities or short-term marketable securities. In 2015, we purchased $45.6 million of short-term investments classified as trading securities. The investments include U.S. Treasury securities, U.S. Agency issued debt securities, corporate bonds, certificate of deposit and money market funds. The securities are recorded at fair value.

        We manage a portfolio of marketable securities that, at the close of fiscal 2015, had a fair value of $91.5 million consisting of common shares of Atwood Oceanics, Inc. and Schlumberger, Ltd. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. The portfolio is recorded at fair value on our balance sheet.

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        During 2015, we did not sell any marketable available-for-sale securities. During 2014, we had cash proceeds from the sale of available-for-sale securities of $49.2 million. During 2013, we had cash proceeds from the sale of investment securities of $232.2 million including $214.1 from the sale of marketable equity available-for-sale securities and $18.1 million from the sale of three limited partnerships.

        Our proceeds from asset sales totaled $22.5 million in 2015, $30.8 million in 2014 and $28.0 million in 2013. Income from asset sales in 2015 totaled $11.7 million, $19.6 million in 2014 and $18.9 million in 2013. In each year we had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business.

        The Company has authorization from the Board of Directors for the repurchase of up to four million common shares in any calendar year. The repurchases may be made using our cash and cash equivalents or other available sources. During 2015, we purchased 810,097 common shares at an aggregate cost of $59.7 million, which will be held as treasury shares. We had no purchases of common shares in fiscal 2014 and 2013.

        During 2015, we paid dividends of $2.75 per share, or a total of $298.4 million. We paid $2.438 per share or $264.4 million in 2014 and $0.87 per share or $93.1 million in 2013. Adjusting for stock splits accordingly, we have increased the effective annual dividend per share every year for over 40 years.

        We have $40 million of senior unsecured fixed-rate notes outstanding at September 30, 2015 that mature July 2016. Interest on the notes is paid semi-annually based on an annual rate of 6.10 percent. A final annual principal repayment of $40 million is due July 2016. We have complied with our financial covenants which require us to maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00.

        On March 19, 2015, we issued $500 million of 4.65 percent 10-year unsecured senior notes. The net proceeds, after discount and issuance cost, were or will be used for general corporate purposes, including capital expenditures associated with our rig construction program. Interest is payable semi-annually on March 15 and September 15 each year, commencing on September 15, 2015. The debt discount is being amortized to interest expense using the effective interest method. The debt issuance costs are amortized straight-line over the stated life of the obligation, which approximates the effective yield method.

        We have a $300 million unsecured revolving credit facility that will mature May 25, 2017. The credit facility has $100 million available to use for letters of credit. The majority of borrowings under the facility would accrue interest at a spread over the London Interbank Offered Rate (LIBOR). We also pay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined according to a scale based on a ratio of our total debt to total capitalization. The spread over LIBOR ranges from 1.125 percent to 1.75 percent per annum and commitment fees range from .15 percent to .35 percent per annum. Based on our debt to total capitalization on September 30, 2015, the spread over LIBOR and commitment fees would be 1.125 percent and .15 percent, respectively. Financial covenants in the facility require us to maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The credit facility contains additional terms, conditions, restrictions, and covenants that we believe are usual and customary in unsecured debt arrangements for companies of similar size and credit quality. As of September 30, 2015, there were no borrowings, but there were three letters of credit outstanding in the amount of $48.2 million. At September 30, 2015, we had $251.8 million available to borrow under our $300 million unsecured credit facility. Subsequent to September 30, 2015, we reduced our outstanding letters of credit by $7.9 million, which increased available borrowing capacity to $259.7 million.

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        At September 30, 2015, we had two letters of credit outstanding, totaling $12 million that were issued to support international operations. These letters of credit were issued separately from the $300 million credit facility so they do not reduce the available borrowing capacity discussed in the previous paragraph.

        The applicable agreements for all unsecured debt described in Note 3 to the Consolidated Financial Statements contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2015, we were in compliance with all debt covenants.

        At September 30, 2015, we had 137 existing rigs with fixed term contracts with original term durations ranging from six months to seven years, with some expiring in fiscal 2016. The contracts provide for termination at the election of the customer, with an early termination payment to be paid if a contract is terminated prior to the expiration of the fixed term. While most of our customers are primarily major oil companies and large independent oil companies, a risk exists that a customer, especially a smaller independent oil company, may become unable to meet its obligations and may exercise its early termination election in the future and not be able to pay the early termination fee. Although not expected at this time, our future revenue and operating results could be negatively impacted if this were to happen.

        Our operating cash requirements, scheduled debt repayments, interest payments, any stock repurchases and estimated capital expenditures, including our rig construction program, for fiscal 2016 are expected to be funded through current cash and cash to be provided from operating activities. However, there can be no assurance that we will continue to generate cash flows at current levels.

        The current ratio was 4.1 at September 30, 2015 and 2.5 at September 30, 2014. The long-term debt to total capitalization ratio, including the current portion of long-term debt, was ten percent at September 30, 2015 compared to two percent at September 30, 2014.

STOCK PORTFOLIO HELD

September 30, 2015
  Number of Shares   Cost Basis   Market Value  
 
  (in thousands, except share amounts)
 

Atwood Oceanics, Inc. 

    4,000,000   $ 60,749   $ 59,240  

Schlumberger, Ltd. 

    467,500     3,713     32,243  

Total

        $ 64,462   $ 91,483  

Material Commitments

        We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations as of September 30, 2015, are summarized in the table below in thousands:

 
  Payments due by year  
Contractual Obligations
  Total   2016   2017   2018   2019   2020   After
2020
 

Long-term debt and estimated interest (a)

  $ 762,346   $ 65,690   $ 23,250   $ 23,250   $ 23,250   $ 23,250   $ 603,656  

Operating leases (b)

    38,635     7,803     6,246     4,304     4,236     3,711     12,335  

Purchase obligations (b)

    81,090     81,090                      

Total contractual obligations

  $ 882,071   $ 154,583   $ 29,496   $ 27,554   $ 27,486   $ 26,961   $ 615,991  

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

(b)
See Note 13 "Commitments and Contingencies" to our Consolidated Financial Statements.

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

        In 2015, we contributed $2.2 million to the pension plan. Contributions may be made in fiscal 2016 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond fiscal 2016 are difficult to estimate due to multiple variables involved.

        At September 30, 2015, we had $22.3 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in Note 4 to the Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

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

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of rigs, appraisals and other factors. The use of different assumptions could increase or decrease the estimated fair value of assets and could therefore affect any impairment measurement.

        During the fourth fiscal quarter of 2015, we recorded a $39.2 million impairment charge to reduce the carrying values of seven SCR rigs located in our International Land segment to their estimated fair value. The rigs fair value was estimated using discounted future cash flows.

        Self-Insurance Accruals    We self-insure a significant portion of expected losses relating to worker's compensation, general liability, employer's liability and automobile liability. Generally, deductibles range from $1 million to $3 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events but there can be no assurance that such coverage will respond or be adequate in all circumstances. Estimates are recorded for incurred outstanding liabilities for worker's compensation and other casualty claims. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred. Estimates for liabilities and retained losses are based on adjusters' estimates, our historical loss experience and statistical methods that we believe are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

        Our wholly-owned captive insurance company finances a significant portion of the physical damage risk on company-owned drilling rigs as well as international casualty deductibles. With the exception of "named wind storm" risk in the Gulf of Mexico, we insure rig and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self-insure a number of other risks including loss of earnings and business interruption.

        Pension Costs and Obligations    Our pension benefit costs and obligations are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan assets. Our discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was lowered to 4.27 percent from 4.32 percent as of September 30, 2015 to reflect changes in the market conditions for high-quality fixed-income investments. The expected return on plan assets is determined based on historical portfolio results and future expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated from future periods. We anticipate pension expense to decrease approximately $1.4 million in 2016 from 2015.

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

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        The fair value of restricted stock awards is determined based on the closing price of our common stock on the date of grant. We amortize the fair value of restricted stock awards to compensation expense on a straight-line basis over the vesting period. At September 30, 2015, unrecognized compensation cost related to unvested restricted stock was $21.2 million. The cost is expected to be recognized over a weighted-average period of 2.2 years.

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

NEW ACCOUNTING STANDARDS

        In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2015-03 "Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs". ASU No. 2015-03 amends the FASB Accounting Standards Codifications ("ASC") to require that debt issuance cost be presented in the balance sheet as a direct deduction from the carrying amount of the related liability. Prior to the amendment, debt issuance costs were reported in the balance sheet as an asset. The amended guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015, however, we elected to early adopt effective January 1, 2015. The election requires retrospective application and represents a change in accounting principle. The ASU provides that debt issuance costs are similar to debt discounts and in effect reduce the proceeds of borrowing, thereby increasing the effective interest rate. As a result of the adoption, the September 30, 2014 Consolidated Balance Sheet has been restated as shown in Note 1 of the Consolidated Financial Statements.

        In April 2014, FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendments in ASU 2014-08 change the criteria for reporting discontinued operations while enhancing disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization's operations and financial results. In addition, the new guidance requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income, and expenses of discontinued operations. The pronouncement is effective for fiscal years beginning on or after December 15, 2014 and interim periods within those years. The adoption of this pronouncement is not expected to have a material impact on our financial statements.

        In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes virtually all existing revenue recognition guidance. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. This update also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. The provisions of ASU 2014-09 are effective for interim and annual periods beginning after December 15, 2017, and we have the option of using either a full retrospective or a modified retrospective approach when adopting this new standard.

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We are currently evaluating the alternative transition methods and the potential effects of the adoption of this update on our financial statements.

        In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. This update simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with the lower of cost or net realizable value test. Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard should be applied prospectively and is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. We do not expect the adoption of this standard to have a material impact on our financial statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Foreign Currency Exchange Rate Risk    Our contracts for work in foreign countries generally provide for payment in U.S. dollars. However, in Argentina we are paid in Argentine pesos. The Argentine branch of one of our second-tier subsidiaries then remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars. In the future, other contracts or applicable law may require payments to be made in foreign currencies. As such, there can be no assurance that we will not experience in Argentina or elsewhere a devaluation of foreign currency, foreign exchange restrictions or other difficulties repatriating U.S. dollars even if we are able to negotiate the contract provisions designed to mitigate such risks. In the event of future payments in foreign currencies and an inability to timely exchange foreign 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. A hypothetical 10% decrease in the value of our Argentine pesos relative to the U.S. dollar as of September 30, 2015 would result in a $2.5 million decrease in the fair value of our monetary assets and liabilities denominated in Argentine pesos.

        We are not operating in any country that is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period based on inflation data published by the respective governments. Estimates from other published sources may indicate that Argentina is a highly inflationary country. Regardless, all of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations.

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

        Credit and Capital Market Risk    In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets, as experienced in the past, can make it difficult for customers to

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obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in customer credit defaults or reduced demand for drilling services which could have a material adverse effect on our business, financial condition and results of operations.

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

        Interest Rate Risk    Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our commercial banks. Because all of our debt at September 30, 2015 has fixed-rate interest obligations, there is no current risk due to interest rate fluctuation.

        The following tables provide information as of September 30, 2015 and 2014 about our interest rate risk sensitive instruments:

INTEREST RATE RISK AS OF SEPTEMBER 30, 2015 (dollars in thousands)

 
  2016   2017   2018   2019   2020   After
2020
  Total   Fair Value
9/30/15
 

Fixed-Rate Debt

  $ 40,000   $   $   $   $   $ 500,000   $ 540,000   $ 553,546  

Average Interest Rate

    6.1 %   %   %   %   %   4.65 %   4.78 %      

Variable Rate Debt

  $   $   $   $   $   $   $   $  

Average Interest Rate

                                                 

INTEREST RATE RISK AS OF SEPTEMBER 30, 2014 (dollars in thousands)

 
  2015   2016   2017   2018   2019   After
2019
  Total   Fair Value
9/30/14
 

Fixed-Rate Debt

  $ 40,000   $ 40,000   $   $   $   $   $ 80,000   $ 84,328  

Average Interest Rate

    6.1 %   6.1 %   %   %   %   %   6.1 %      

Variable Rate Debt

  $   $   $   $   $   $   $   $  

Average Interest Rate

                                                 

        Equity Price Risk    On September 30, 2015, we had a portfolio of securities with a total fair value of $91.5 million. The total fair value of the portfolio of securities was $222.3 million at September 30, 2014. A hypothetical 10% decrease in the market prices for all securities in our portfolio as of September 30, 2015 would decrease the fair value of our available-for-sale securities by $9.2 million. We make no specific plans to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the fair value of our holdings. The portfolio is recorded at fair value on the balance sheet with changes in unrealized after-tax value reflected in the equity section of the balance sheet. At November 12, 2015, the total fair value of the remaining securities had increased to approximately $98.7 million. Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements.

Item 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Information required by this item may be found in Item 1A—"Risk Factors" and in Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk" included in this Form 10-K.

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Item 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

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Report of Independent Registered Public Accounting Firm
HELMERICH & PAYNE, INC.

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

        We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2015 and 2014, and the related consolidated statements of income, comprehensive income, shareholders' equity and cash flows for each of the three years in the period ended September 30, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helmerich & Payne, Inc. at September 30, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2015, in conformity with U.S. generally accepted accounting principles.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helmerich & Payne, Inc.'s internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 25, 2015 expressed an unqualified opinion thereon.

    /s/Ernst & Young LLP

Tulsa, Oklahoma
November 25, 2015

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Consolidated Statements of Income

HELMERICH & PAYNE, INC.

 
  Years Ended September 30,  
 
  2015   2014   2013  
 
  (in thousands, except per share amounts)
 

Operating revenues

                   

Drilling—U.S. Land

  $ 2,523,518   $ 3,099,954   $ 2,785,449  

Drilling—Offshore

    241,043     250,811     221,863  

Drilling—International Land

    386,693     355,532     366,841  

Other

    14,187     13,410     13,461  

    3,165,441     3,719,707     3,387,614  

Operating costs and expenses

                   

Operating costs, excluding depreciation

    1,704,163     2,009,912     1,852,768  

Depreciation

    606,992     523,549     455,623  

Asset impairment charge

    39,242          

Research and development

    16,104