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TABLE OF CONTENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PART IV

Table of Contents

 

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

FORM 10-K

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

 

 

For the fiscal year ended September 30, 2016

 

 

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

         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, 2016, the aggregate market value of the voting stock held by non-affiliates was approximately $6.2 billion.

         Number of shares of common stock outstanding at November 11, 2016:    108,177,217.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the Registrant's 2017 Proxy Statement for the Annual Meeting of Stockholders to be held on March 1, 2017 are incorporated by reference into Part III of this Form 10-K. The 2017 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.



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, 2016
TABLE OF CONTENTS

 
   
  Page  

PART I

 

Item 1.

 

Business

   
1
 

Item 1A.

 

Risk Factors

    8  

Item 1B.

 

Unresolved Staff Comments

    19  

Item 2.

 

Properties

    20  

Item 3.

 

Legal Proceedings

    29  

Item 4.

 

Mine Safety Disclosures

    30  

 

Executive Officers of the Company

    31  

PART II

 

Item 5.

 

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

   
32
 

Item 6.

 

Selected Financial Data

    34  

Item 7.

 

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

    35  

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

    51  

Item 8.

 

Financial Statements and Supplementary Data

    52  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    106  

Item 9A.

 

Controls and Procedures

    106  

Item 9B.

 

Other Information

    109  

PART III

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

   
109
 

Item 11.

 

Executive Compensation

    109  

Item 12.

 

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

    109  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    109  

Item 14.

 

Principal Accountant Fees and Services

    109  

PART IV

 

Item 15.

 

Exhibits and Financial Statement Schedules

   
110
 

Item 16.

 

Form 10-K Summary

    114  

SIGNATURES

   
115
 

Table of Contents


PART I

Item 1.    BUSINESS

        Helmerich & Payne, Inc. (which together with its subsidiaries is identified as the "Company", "we", "us" or "our," except where stated or the context requires otherwise), 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 2016, our U.S. Land operations drilled primarily in Oklahoma, California, Texas, Wyoming, Colorado, Louisiana, Mississippi, Pennsylvania, Ohio, New Mexico and North Dakota. Offshore operations were conducted in the Gulf of Mexico and Equatorial Guinea. Our International Land segment conducted drilling operations in five international locations during fiscal 2016: Ecuador, Colombia, Argentina, Bahrain and United Arab Emirates ("UAE").

        We are also engaged in the ownership, development and operation of commercial real estate and the research and development of rotary steerable technology. 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. Since 2008, our subsidiary, TerraVici Drilling Solutions, Inc., has pursued the development of patented rotary steerable technology as a means to enhance our horizontal and directional drilling services. We expect to continue research and development of this and other technology in 2017. Each of the businesses operates independently of the others through wholly-owned subsidiaries. This operating decentralization is balanced by centralized finance and legal organizations.

    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 2016, we received approximately 68 percent of our consolidated operating revenues from our ten largest contract drilling customers. Occidental Oil and Gas Corporation, Continental Resources and Yacimientos Petroliferos Fiscales (respectively, "Oxy", "Continental" and "YPF"), including their affiliates, are our three largest contract drilling customers. We perform drilling services for Oxy on a world-wide basis, Continental in U.S. land operations and YPF in Argentina. Revenues from drilling services performed for Oxy, Continental and YPF in fiscal 2016 accounted for approximately 30 percent, 18 percent and 15 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 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

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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 are 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 designs. This design permits the installation of a pipe handling system which allows the rig to be more efficiently operated and eliminates the need for a casing stabber in the mast. While the FlexRig4 trailerized version provides for more efficient well site to well site rig moves, the skidding version allows for drilling of up to 22 wells from a single pad which results in reduced environmental impact. In 2011, we announced the introduction of the FlexRig5 design. The FlexRig5 is suited for long lateral drilling of multiple wells from a single location, which is well suited for unconventional shale reservoirs. The new design preserves the key performance features of FlexRig3 combined with a bi-directional pad drilling system and equipment capacities suitable for wells in excess of 25,000 feet of measured depth.

        Industry trends toward more complex drilling have accelerated the retirement of less capable mechanical rigs. Over time our mechanical rigs have been sold or decommissioned as we added new

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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. In fiscal 2016, we did not decommission any of our remaining 14 SCR rigs.

        Since 1998, we have built 232 FlexRig3s, 88 FlexRig4s, and 52 FlexRig5s with 367 of those delivered to the field. Of the total 372 AC drive FlexRigs built through September 30, 2016, 157 have been built in the last five fiscal years. As of November 17, 2016, there was one additional FlexRig under construction. Additionally, five previously completed FlexRigs are scheduled for delivery to the field at a later date per the request of certain customers.

        The effective use of technology is important to the maintenance of our competitive position within the drilling industry. We expect to continue to focus on new technology solutions and applications in the future. Our research and development expense totaled $10.3 million in fiscal 2016, $16.1 million in fiscal 2015, and $15.9 million in fiscal 2014.

        We currently have three facilities that provide vertically integrated solutions for drilling rig fabrication, upgrades, retrofits and modifications, as well as overhauling and repairing of drilling rigs, equipment and associated component parts. We have a gulf coast fabrication and assembly facility near Houston, Texas as well as 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.

        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 2017. 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 2014 when prices exceeded $100 per barrel. While oil prices have rebounded modestly from lows observed in early 2016, the decline in prices continued to negatively affect demand for services in fiscal 2016. Specifically, at the close of fiscal 2016 we had 118 contracted rigs, compared to 168 contracted rigs at the close of fiscal 2015 and 325 contracted rigs at the close of fiscal 2014. In addition, and in light of the price of oil and the status of the drilling industry and our rig fleet, in fiscal 2015 we 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. Similarly, during the third quarter of fiscal 2016 we recorded a $6.3 million impairment charge to reduce the carrying value of certain rig and rig related equipment classified as held for sale in our U.S. Land segment to their estimated fair values. While we continue to periodically perform impairment evaluations, no additional impairments were identified in fiscal 2016 for any 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

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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.

        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 many other competitors with regional operations. Internationally, we compete directly with various contractors at each location where we operate. In the Gulf of Mexico platform rig market, we primarily compete with Nabors Industries Ltd. and Blake International Rigs, LLC.

    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 2016, 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.

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        As of September 30, 2016, we had 88 existing rigs under fixed-term contracts. While the original duration for these current fixed-term contracts are for six-month to five-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 and some customers may elect to early terminate fixed-term contracts as discussed above.

    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, 2016 and 2015 was $1.8 billion and $3.1 billion, respectively. The decrease in backlog at September 30, 2016 from September 30, 2015, is primarily due to the revenue earned since September 30, 2015 and the expiration and termination of long-term contracts. Approximately 53.2 percent of the total September 30, 2016 backlog is not reasonably expected to be filled in fiscal 2017. A small portion of the backlog represents term contracts for new rigs that will begin operations in the future.

        The following table sets forth the total backlog by reportable segment as of September 30, 2016 and 2015, and the percentage of the September 30, 2016 backlog not reasonably expected to be filled in fiscal 2017:

 
  Total Backlog
Revenue
   
 
 
  Percentage Not Reasonably
Expected to be Filled in Fiscal 2017
 
Reportable Segment
  9/30/2016   9/30/2015  
 
  (in billions)
   
 

U.S. Land

  $ 1.2   $ 2.2     47.5 %

Offshore

    0.1     0.1     44.4 %

International

    0.5     0.8     68.8 %

  $ 1.8   $ 3.1        

        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 2016, 2015, and 2014, we had 348, 343 and 329, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2016 increased by a net of five rigs from the end of fiscal 2015. The net increase is due to five new FlexRigs completed in 2016. Our U.S. Land operations contributed approximately 77 percent ($1.2 billion) of our consolidated operating revenues during fiscal 2016, compared with approximately 80 percent ($2.5 billion) of consolidated operating revenues during fiscal 2015 and approximately 83 percent ($3.1 billion) of consolidated operating revenues during fiscal 2014. Rig utilization was approximately 30 percent in fiscal 2016, approximately 62 percent in fiscal 2015 and approximately 86 percent in fiscal 2014. A rig is considered to be utilized when it is operated or being mobilized or demobilized under contract. At the close of fiscal 2016, 95 out of an available 348 land rigs were generating revenue.

    Offshore Drilling

        Our Offshore operations contributed approximately 9 percent in fiscal year 2016 ($138.6 million) of our consolidated operating revenues compared to approximately 8 percent ($241.7 million) of consolidated operating revenues during fiscal 2015 and 7 percent ($251.3 million) of consolidated operating revenues during fiscal 2014. Rig utilization in fiscal 2016 was approximately 82 percent

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compared to approximately 93 percent in fiscal 2015 and 89 percent in fiscal 2014. At the end of fiscal 2016, we had seven of our nine offshore platform rigs under contract compared to eight at the end of fiscal 2015. We continued to work under management contracts for two customer-owned rigs at the close of fiscal 2016. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 61percent ($84.1 million) of offshore revenues during fiscal 2016.

    International Land Drilling

    General

        Prior to September 30, 2015, for financial reporting purposes, fiscal years of our foreign operations ended on August 31 to facilitate reporting of consolidated results, resulting in a one-month reporting lag when compared to the remainder of the Company. Starting October 1, 2015, the reporting year-end of these foreign operations was changed from August 31 to September 30 eliminating the previously existing one-month reporting lag. Accordingly, the results of operations below have been changed to reflect the period-specific effects of this change, unless otherwise noted. See Note 1—"Summary of Significant Accounting Policies" included in Item 8 "Financial Statements and Supplementary Data" of this Form 10-K for additional information regarding this change.

        At the end of September 2016 and 2015, we had 38 land rigs available for work in locations outside of the United States compared to 36 land rigs at the end of 2014. Our International Land operations contributed approximately 14 percent ($229.9 million) of our consolidated operating revenues during fiscal 2016, compared with approximately 12 percent ($382.3 million) of consolidated operating revenues during fiscal 2015 and 9 percent ($351.3 million) of consolidated operating revenues during fiscal 2014. Rig utilization in fiscal 2016 was 39 percent, 51 percent in fiscal 2015 and 74 percent in fiscal 2014. 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 2016, we had 19 rigs in Argentina. Our utilization rate was approximately 54 percent during fiscal 2016, approximately 57 percent during fiscal 2015 and approximately 77 percent during fiscal 2014. Revenues generated by Argentine drilling operations contributed approximately 10 percent in fiscal 2016 ($159.4 million) of our consolidated operating revenues compared to approximately 6 percent ($178.0 million) of our consolidated operating revenues during fiscal 2015 and approximately 3 percent ($107.2 million) of our consolidated operating revenues during fiscal 2014. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 9 percent of consolidated operating revenues and approximately 66 percent of international operating revenues during fiscal 2016. The Argentine drilling contracts are primarily with large international or national oil companies.

    Colombia

        At the end of fiscal 2016, we had eight rigs in Colombia. Our utilization rate was approximately 13 percent during fiscal 2016, approximately 48 percent during fiscal 2015 and approximately 62 percent during fiscal 2014. Revenues generated by Colombian drilling operations contributed approximately 1 percent in fiscal 2016 ($20.5 million) of our consolidated operating revenues compared to approximately 2 percent ($70.1 million) of our consolidated operating revenues during fiscal 2015 and approximately 2 percent ($81.2 million) of our consolidated operating revenues during fiscal 2014. Revenues from drilling services performed for our two customers in Colombia totaled approximately 1 percent of consolidated operating revenues and approximately 9 percent of international operating

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revenues during fiscal 2016. The Colombian drilling contracts are primarily with large international or national oil companies.

    Ecuador

        At the end of fiscal 2016, we had six rigs in Ecuador. The utilization rate in Ecuador was 4 percent in fiscal 2016, compared to 29 percent in fiscal 2015 and 83 percent in fiscal 2014. Revenues generated by Ecuadorian drilling operations contributed less than 1 percent ($4.9 million) during fiscal 2016 of our consolidated operating revenues compared to approximately 1 percent during fiscal 2015 ($31.0 million) of our consolidated operating revenues and 2 percent in fiscal 2014 ($68.0 million) of our consolidated operating revenues. At the end of fiscal 2016 all of our rigs in Ecuador were idle. The rigs in Ecuador, along with other rig related assets, were classified as held for sale at September 30, 2016.

    UAE—Abu Dhabi

        At the end of fiscal 2016, we had two rigs in the UAE. The utilization rate in the UAE was 100 percent in fiscal 2016, fiscal 2015 and in fiscal 2014. Revenues generated by drilling operations in the UAE contributed 2 percent ($34.6 million) during fiscal 2016 of our consolidated operating revenues compared to approximately 2 percent during fiscal 2015 ($47.7 million) of our consolidated operating revenues and 1 percent during fiscal 2014 ($48.5 million) of our consolidated operating revenues. The UAE drilling contracts are with a single national oil company that contributed approximately 15 percent of international operating revenues during fiscal 2016.

    Bahrain

        At the end of fiscal 2016, we had three rigs in Bahrain. The utilization rate in Bahrain was 33 percent in fiscal 2016, compared to 56 percent in fiscal 2015 and 100 percent in fiscal 2014. Revenues generated by drilling operations in Bahrain contributed 1 percent during fiscal 2016, fiscal 2015 and fiscal 2014 ($10.2 million, $41.9 million and $33.2 million, respectively) of our consolidated operating revenues. Bahrain drilling contracts are with a single national oil company that contributed approximately 4 percent of international operating revenues during fiscal 2016.

    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 4,116 employees within the United States (5 of which were part-time employees) and 724 employees in international operations as of September 30, 2016.

    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

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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. Volatility and the overall decline in prices continued through 2015 and into early 2016. For example, in July of 2014 oil prices exceeded $100 per barrel. Oil prices dropped below $30 per barrel in early 2016. In recent months oil prices have generally remained below $50 per barrel. In response to the downward trend in prices, many of our customers reduced their capital spending budgets for 2015 and 2016. As such, demand for our drilling services declined further in the first half of fiscal 2016. We have, however, experienced an increase in demand and activity since May of 2016. 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, 2016, 95 out of an available 348 land rigs were contracted in the U.S. Land segment. As of November 17, 2016, 105 rigs were contracted in the U.S. Land segment. In the event oil prices remain depressed for a sustained period, or decline again, our U.S. Land, International Land and Offshore segments may again experience 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;

    the continued development of shale plays which may influence worldwide supply and prices;

    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;

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    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.

        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 facility located near the Houston, Texas ship channel where we upgrade and repair rigs and perform fabrication work, 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 or by reason of state anti-indemnity laws. 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

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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, and most cyber risks. 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 2017, 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 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 bankruptcy or otherwise becoming unable 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

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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 has experienced downturns in demand during the last decade, including a significant downturn that started in 2014. Today, as was the case in past downturns, there are 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 be unable to replace fixed-term contracts that were terminated early, extend expiring contracts or obtain new contracts in the spot market, and the day rates (and other material terms) under any new contracts may be on substantially less favorable rates and terms. As such, we may have difficulty sustaining rig utilization and profit margins in the future, 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 2016, we received approximately 68 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 30 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 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 improve existing rigs or build new, technologically advanced drilling rigs;

    avoid cost overruns inherent in large fabrication projects resulting from numerous factors such as shortages of equipment, materials and skilled labor, unscheduled delays in delivery of ordered

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      equipment and materials, unanticipated increases in costs of equipment, materials and labor, design and engineering problems, and financial or other difficulties;

    successfully deploy idle, stacked or new drilling rigs;

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

    maintain crews necessary to operate existing or additional drilling rigs; or

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

        If we are not successful in upgrading existing rigs and equipment or building new rigs in a timely and cost-effective manner suitable to customer needs, 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 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.

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We may be required to record impairment charges with respect to our drilling rigs.

        We evaluate our drilling rigs and other property whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss may exist when the estimated future cash flows are less than the carrying amount of the asset. Lower utilization and day rates adversely affect our revenues and profitability. Prolonged periods of low utilization and day rates may result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable. For example, in fiscal 2015, we performed an impairment evaluation of all our long-lived drilling assets. 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. Similarly, during the third quarter of fiscal 2016 we recorded a $6.3 million impairment charge to reduce the carrying value of certain rig and rig related equipment classified as held for sale in our U.S. Land segment to their estimated fair values. Although we are actively marketing idle drilling rigs in our fleet, there can be no assurance that we will be able to obtain future contracts for all of our rigs. As of September 30, 2016, we assessed our idle drilling rigs and determined no additional impairment charges were necessary. However, drilling rigs in our fleet may become impaired in the future if current depressed market conditions are prolonged or if oil and gas prices remain low or decline further.

Department of Interior investigation could 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. 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 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

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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 2016, approximately 14 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2016, approximately 80 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 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.

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        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, 2016, our contract drilling backlog was approximately $1.8 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, financial strength, and possibly financial results.

        At September 30, 2016, we had a portfolio of securities with a total fair value of approximately $71.5 million, consisting of Atwood Oceanics, Inc. and Schlumberger, Ltd. The total fair value of the portfolio of securities was $91.5 million at September 30, 2015. These securities are subject to a wide variety of market-related risks that could substantially reduce or increase the fair value of the 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 unless a decline in fair value below our cost basis is considered to be other than temporary in which case the change is recorded through earnings. Our position in Atwood Oceanics, Inc. (an offshore drilling company severely impacted by the downturn in the energy sector) was in an unrealized loss position for under 30 days at September 30, 2015, and then dropped below cost again in December 2015 and continued to be in a loss position through fiscal 2016. During the fourth quarter of fiscal 2016, we determined the loss was other-than-temporary. As a result, we recognized a $26.0 million other-than-temporary impairment charge. At November 17, 2016, the fair value of the portfolio had decreased to approximately $68.8 million.

We may reduce or suspend our dividend in the future.

        We have paid a quarterly dividend for many years. Our most recent, quarterly dividend was $0.70 per share. In the future, our Board of Directors may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position the Company for long-term success. The declaration and amount of future dividends is at the discretion of our Board of Directors and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board of Directors deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements

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governing our indebtedness now or in the future. There can be no assurance that we will continue to pay a dividend in the future.

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. In addition, during periods of depressed market conditions, such as the one we are currently experiencing, we may be subject to an increased risk of our customers, vendors, former employees and others initiating legal proceedings against us. 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.

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, parts and equipment 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, increased demands in the industry or other reasons beyond our control. Similarly, certain key rig components, parts and equipment 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. If we are unable to procure certain of such rig components, parts or equipment, our ability to maintain, improve, upgrade or construct drilling rigs could be impaired, which 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. In December 2015, the Argentine peso experienced a sharp devaluation resulting in an aggregate foreign currency loss of $8.5 million for the three months ended December 31, 2015. Subsequent to the sharp devaluation, the Argentine peso has significantly stabilized and the Argentine Foreign Exchange Market controls place fewer restrictions on repatriating U.S. dollars. However, in the future we may incur currency devaluations, foreign exchange restrictions or other difficulties repatriating U.S. dollars in Argentina or elsewhere 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

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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 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.

Our ability to access capital markets could be limited.

        From time to time, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by, among other things, oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health of the drilling and overall oil and gas industry, and the liquidity of the capital markets. Many of the factors that affect our ability to access capital markets are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations.

We may not be able to generate cash to service all of our indebtedness, and may be forced to take other actions to satisfy our obligations.

        Our ability to make future, scheduled payments on or to refinance our debt obligations depends on our financial position, results of operations and cash flows. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal and interest on our indebtedness. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investment decisions and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness. Furthermore, these alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial position at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would be a default (if not waived) and would likely result in a reduction of our credit rating, which could harm our ability to seek additional capital or restructure or refinance our indebtedness.

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

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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 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.

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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, sell or otherwise dispose of assets, enter into new lines of business, and merge or consolidate. In addition, our credit facility requires us to maintain a funded leverage ratio (as defined) of less than 50 percent and certain priority debt (as defined) may not exceed 17.5% of our net worth (as defined). 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 2016 fiscal year and that remain unresolved.

19


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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, 2016:

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  

COLORADO

    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  

TEXAS

    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  

TEXAS

    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  

20


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  

TEXAS

    267     22,000   AC (FlexRig3)     1,500  

TEXAS

    268     22,000   AC (FlexRig3)     1,500  

TEXAS

    269     22,000   AC (FlexRig3)     1,500  

COLORADO

    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  

COLORADO

    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  

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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  

TEXAS

    340     8,000   AC (FlexRig4)     1,150  

TEXAS

    341     18,000   AC (FlexRig4)     1,500  

TEXAS

    342     18,000   AC (FlexRig4)     1,500  

COLORADO

    343     18,000   AC (FlexRig4)     1,500  

TEXAS

    344     8,000   AC (FlexRig4)     1,150  

TEXAS

    345     8,000   AC (FlexRig4)     1,150  

TEXAS

    346     8,000   AC (FlexRig4)     1,150  

TEXAS

    347     8,000   AC (FlexRig4)     1,150  

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  

LOUISIANA

    383     22,000   AC (FlexRig3)     1,500  

TEXAS

    384     22,000   AC (FlexRig3)     1,500  

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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  

TEXAS

    415     22,000   AC (FlexRig3)     1,500  

TEXAS

    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  

WYOMING

    448     22,000   AC (FlexRig3)     1,500  

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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  

TEXAS

    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  

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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  

COLORADO

    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  

OHIO

    521     25,000   AC (FlexRig5)     1,500  

COLORADO

    522     25,000   AC (FlexRig5)     1,500  

TEXAS

    523     25,000   AC (FlexRig5)     1,500  

COLORADO

    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  

LOUISIANA

    533     25,000   AC (FlexRig5)     1,500  

LOUISIANA

    534     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    535     25,000   AC (FlexRig5)     1,500  

TEXAS

    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

    551     25,000   AC (FlexRig5)     1,500  

TEXAS

    552     25,000   AC (FlexRig5)     1,500  

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

TEXAS

    553     25,000   AC (FlexRig5)     1,500  

TEXAS

    556     25,000   AC (FlexRig5)     1,500  

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  

NEW MEXICO

    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  

NEW MEXICO

    636     22,000   AC (FlexRig3)     1,500  

TEXAS

    637     22,000   AC (FlexRig3)     1,500  

TEXAS

    638     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    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  

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

TEXAS

    647     22,000   AC (FlexRig3)     1,500  

TEXAS

    648     22,000   AC (FlexRig3)     1,500  

TEXAS

    649     22,000   AC (FlexRig3)     1,500  

TEXAS

    650     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    651     22,000   AC (FlexRig3)     1,500  

TEXAS

    652     22,000   AC (FlexRig3)     1,500  

TEXAS

    653     22,000   AC (FlexRig3)     1,500  

TEXAS

    656     22,000   AC (FlexRig3)     1,500  

TEXAS

    657     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    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
 

LOUISIANA

    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  

LOUISIANA

    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,  
 
  2012   2013   2014   2015   2016  

U.S. Land Rigs

                               

Number of rigs at end of period

    282     302     329     343     348  

Average rig utilization rate during period (1)

    89 %   82 %   86 %   62 %   30 %

U.S. Offshore Platform Rigs

   
 
   
 
   
 
   
 
   
 
 

Number of rigs at end of period

    9     9     9     9     9  

Average rig utilization rate during period (1)

    79 %   89 %   89 %   93 %   82 %

(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, 2016:

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,  
 
  2012   2013   2014   2015   2016  

Number of rigs at end of period

    29     29     36     38     38  

Average rig utilization rate during period (1)(2)(3)

    78 %   82 %   74 %   51 %   39 %

(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.

(3)
Utilization for years prior to 2016 have been changed due to the change in reporting year-end from August 31 to September 30 effective October 1, 2015

STOCK PORTFOLIO

        Information required by this item regarding our stock portfolio may be found in, 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 ("DOI") regarding the same events that were the subject of the DOJ's investigation. We can provide no assurances as to the timing or eventual outcome of these discussions and are unable to determine the amount of penalty, if any, that may be assessed or the effect of any terms that may be required by an administrative agreement with the DOI. However, we presently believe that the outcome of our discussions will not have a material adverse effect on us.

    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

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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.

    4.
    Keel Litigation.

        As previously disclosed, on or about April 28, 2015, Joshua Keel ("Keel"), an employee of Helmerich & Payne International Drilling Co. ("HPIDC"), filed a petition in the 152nd Judicial Court for Harris County, Texas (Cause No. 2015-24531) against us, our customer and several subcontractors of our customer. The suit arose from injuries Keel sustained in an accident that occurred while he was working on HPIDC Rig 223 in New Mexico in July of 2014. Keel alleged that the defendants were negligent and negligent per se, acted recklessly, intentionally, and/or with an utterly wanton disregard for the rights and safety of the plaintiff and was seeking damages well in excess of $100 million.

        On September 14, 2016, the parties in the Keel litigation entered into a global settlement agreement, which was approved by the court on October 14, 2016. The total settlement amount of $72 million will be paid by the Company and its insurers on behalf of all defendants pursuant to industry standard contractual indemnification obligations. After taking into account amounts to be paid by the Company's various insurers, $18.8 million was recorded as an operating cost in our U.S. Land segment. At September 30, 2016, we have recorded in our Consolidated Balance Sheet a $72.0 million accrued liability and a $50.2 million accounts receivable from insurance. The settlement payment is due on or before December 24, 2016.

Item 4.    MINE SAFETY DISCLOSURES

        Not applicable.

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Table of Contents


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, 55   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, 51

 

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, 54

 

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

John R. Bell, 46

 

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, 40

 

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 11, 2016, there were 592 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:

 
  2015   2016  
Quarter
  High   Low   High   Low  

First

  $ 98.47   $ 59.24   $ 61.70   $ 46.32  

Second

    71.55     54.00     64.06     40.02  

Third

    79.90     67.60     69.20     55.75  

Fourth

    70.34     46.16     70.28     56.19  

    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
  2015   2016   2015   2016  

First

  $ .6875   $ .6875   $ 74,822,055   $ 74,560,506  

Second

    .6875     .6875     74,525,525     74,739,803  

Third

    .6875     .6875     74,478,918     74,740,993  

Fourth

    .6875     .7000     74,540,202     76,111,240  

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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
Sep11
 
Company / Index
  Sep12   Sep13   Sep14   Sep15   Sep16  

Helmerich & Payne, Inc

    100     117.91     173.15     251.99     126.77     189.28  

S&P 500 Index

    100     130.20     155.39     186.05     184.91     213.44  

S&P 500 Oil & Gas Drilling Index

    100     119.98     132.87     116.68     52.63     57.26  

        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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Table of Contents

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+

 
  2016   2015   2014   2013   2012  
 
  (in thousands except per share amounts)
 

Operating revenues

  $ 1,624,232   $ 3,161,702   $ 3,715,968   $ 3,392,932   $ 3,158,543  

Income (loss) from continuing operations

    (52,990 )   420,474     706,610     720,653     571,305  

Income (loss) from discontinued operations

    (3,838 )   (47 )   (47 )   15,186     7,436  

Net income (loss)

    (56,828 )   420,427     706,563     735,839     578,741  

Basic earnings (loss) per share from continuing operations

    (0.50 )   3.88     6.52     6.74     5.33  

Basic earnings (loss) per share from discontinued operations

    (0.04 )           0.14     0.07  

Basic (loss) earnings per share

    (0.54 )   3.88     6.52     6.88     5.40  

Diluted earnings (loss) per share from continuing operations

    (0.50 )   3.85     6.44     6.65     5.25  

Diluted earnings (loss) per share from discontinued operations

    (0.04 )           0.14     0.07  

Diluted earnings (loss) per share

    (0.54 )   3.85     6.44     6.79     5.32  

Total assets*^

    6,832,019     7,147,242     6,725,316     6,265,923     5,724,313  

Long-term debt^

    491,847     492,443     39,502     79,137     193,737  

Cash dividends declared per common share

    2.775     2.750     2.625     1.300     0.280  

+
Results for 2015 and prior periods have been changed due to the change in reporting year-end for our international subsidiaries from August 31 to September 30 effective October 1, 2015.

*
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 395 drilling rigs at September 30, 2016. Our contract drilling segments consist of the U.S. Land segment with 348 rigs, the Offshore segment with nine offshore platform rigs and the International Land segment with 38 rigs at September 30, 2016. During fiscal 2016, we placed into service ten new FlexRigs and completed another five new FlexRigs. At the close of fiscal 2016, we had 118 contracted rigs, compared to 168 contracted rigs at the same time during the prior year. During fiscal years 2015 and 2016, the drilling industry experienced significant declines in activity as over 1,400 drilling rigs were idled in the U.S. This decline caused dramatic reductions in personnel and investment in the industry and significantly impacted financial results across oilfield services and other companies. Nevertheless, late in fiscal 2016 we began to see the U.S. land active rig count increase and customers increasing their drilling budgets. Throughout the downturn, our long-term strategy remained 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 effectively manage the Company during these challenging times and take advantage of opportunities that lie ahead.

        Prior to October 1, 2015, for financial reporting purposes, fiscal years of our foreign operations ended on August 31 to facilitate reporting of consolidated results, resulting in a one-month reporting lag when compared to the remainder of the Company. Starting October 1, 2015, the reporting year-end of these foreign operations was changed from August 31 to September 30 eliminating the previously existing one-month reporting lag. Accordingly, the results of operations that follow have been changed

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to reflect the period-specific effects of this change. (See Note 1 of the Consolidated Financial Statements for additional information regarding this change.)

        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 2016, 2015 and 2014 in the following discussion are referring to fiscal years 2016, 2015 and 2014.

Results of Operations

        All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net loss for 2016 was $56.8 million ($0.54 loss per share), compared with net income of $420.4 million ($3.85 per share) for 2015 and $706.6 million ($6.44 per share) for 2014. Included in our 2016 net loss is an after-tax loss of $15.9 million ($0.15 loss per share) from an other-than-temporary impairment of our marketable equity security position in Atwood Oceanics, Inc. ("Atwood"). Net loss in 2016 also includes an after-tax loss of $12.0 million ($0.11 loss per share) from the settlement of litigation. Our 2014 net income includes after-tax gains from the sale of investment securities of $27.8 million ($0.25 per share). Net loss in 2016 includes after-tax gains from the sale of assets of $6.1 million ($0.06 per share) while net income in 2015 and 2014 include after-tax gains from the sale of assets of $7.4 million ($0.07 per share) and $12.1 million ($0.11 per share), respectively. Net loss in 2016 includes a $3.8 million loss ($0.04 loss per share) from discontinued operations.

        Consolidated operating revenues were $1.6 billion in 2016, $3.2 billion in 2015 and $3.7 billion in 2014. As oil prices steeply declined during 2015 and remained low during 2016, 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 36,984 in 2016, compared to 75,866 in 2015 and 100,638 in 2014. Our U.S. land rig utilization was 30 percent in 2016, 62 percent in 2015 and 86 percent in 2014. The average number of U.S. land rigs available was 339 rigs in 2016, 336 rigs in 2015 and 319 rigs in 2014. Revenue in the Offshore segment decreased in 2016 from 2015 as several rigs moved to lower pricing while on standby and one less average rig operated in 2016 compared to 2015. Rig utilization for offshore rigs was 82 percent in 2016, compared to 93 percent in 2015 and 89 percent in 2014. The International Land segment has also been affected by the decline in oil prices causing revenue days to decline to 5,364 in 2016 from 7,284 in 2015 and 8,262 in 2014. Rig utilization in our International Land segment was 39 percent in 2016, 51 percent in 2015 and 74 percent in 2014.

        In 2016, we recorded a $26.0 million other-than-temporary impairment charge as our marketable equity security position in Atwood remained in a loss position during most of the fiscal year. Atwood is in the offshore drilling industry which has been severely impacted by the downturn in the energy sector. In 2014, we had $45.2 million in gains from the sale of investment securities. Interest and dividend income was $3.2 million, $5.8 million and $1.5 million in 2016, 2015 and 2014, respectively. The higher income in 2015 was primarily the result of Atwood declaring dividends during 2015. Those dividends ceased in early 2016.

        Direct operating costs in 2016 were $898.8 million or 55 percent of operating revenues, compared with $1.7 billion or 54 percent of operating revenues in 2015 and $2.0 billion or 54 percent of operating revenues in 2014.

        Depreciation expense was $598.6 million in 2016, $608.0 million in 2015 and $524.0 million in 2014. Included in depreciation are abandonments of equipment of $39.3 million in 2016, $43.6 million in 2015 and $23.0 million in 2014. Additionally, we recorded impairment charges on rig and rig related equipment of $6.3 million in 2016 and $39.2 million in 2015. Depreciation expense, exclusive of the abandonments, decreased in 2016 from 2015 by one percent after increasing in both 2015 and 2014 from the previous comparative year due to lower levels of capital expenditures in 2016. Depreciation

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expense in 2017 is expected to decline from 2016 as capital expenditures are expected to continue to decrease. (See Liquidity and Capital Resources.) Abandonments in the three-year period were primarily due to the abandonment of used drilling equipment in all years and the decommissioning of 23 rigs in 2015 and 9 rigs in 2014.

        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 2016, we recorded a $6.3 million impairment charge to reduce the carrying value in rig and rig related equipment classified as held for sale to their estimated fair values, based on expected sales prices. The used drilling equipment is from rigs that were decommissioned from service in prior fiscal periods and written down to their estimated recoverable value at the time of decommissioning. The impairment charge is not expected to have an impact on our liquidity or debt covenants. 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. In 2014, no impairment was recorded. Six of the seven international rigs impaired in 2015 along with other rig related assets were classified as held for sale at September 30, 2016. We plan to sell these assets in their current condition.

        General and administrative expenses totaled $146.2 million in 2016, $134.7 million in 2015 and $135.3 million in 2014. Contributing to the increase in 2016 from 2015 were expenses related to employee work force reductions including employee severance expenses, additional pension expense and additional employer match to our 401(k)/Employee Thrift Plan due to a partial plan termination status whereby affected participants were fully vested in their 401(k) accounts.

        Interest expense net of amounts capitalized totaled $22.9 million in 2016, $15.0 million in 2015 and $4.7 million in 2014. Interest expense is primarily attributable to fixed-rate debt outstanding. Interest expense increased in 2016 from 2015 and in 2015 from 2014 primarily due to the issuance of $500 million unsecured senior notes in March 2015. Capitalized interest was $2.8 million, $7.0 million and $7.7 million in 2016, 2015 and 2014, respectively. All of the capitalized interest is attributable to our rig construction program.

        We had an income tax benefit of $19.7 million in 2016 compared to income tax expense of $241.4 million in 2015 and $388.0 million in 2014. The effective income tax rate was 27.1 percent in 2016 compared to 36.5 percent in 2015 and 35.4 percent in 2014. 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 2016, 2015 and 2014, we incurred $10.3 million, $16.1 million and $15.9 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 2017.

        Expenses incurred within the country of Venezuela are reported as discontinued operations. In March 2016, the Venezuelan government implemented the previously announced plans for a new foreign currency exchange system. The implementation of this system resulted in a reported loss from discontinued operations of $3.8 million in fiscal 2016, all of which corresponds to the Company's former operations in Venezuela.

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        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, Petroleos de Venezuela, S.A. and PDVSA Petroleo, S.A. 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.

        The following tables summarize operations by reportable operating segment.

Comparison of the years ended September 30, 2016 and 2015

 
  2016   2015
(as adjusted)
  % Change  
 
  (in thousands, except operating statistics)
 

U.S. LAND OPERATIONS

                   

Operating revenues

  $ 1,242,462   $ 2,523,518     (50.8 )%

Direct operating expenses

    603,800     1,254,424     (51.9 )

General and administrative expense

    50,057     50,769     (1.4 )

Depreciation

    508,237     519,950     (2.3 )

Asset impairment charge

    6,250         100.0  

Segment operating income

  $ 74,118   $ 698,375     (89.4 )

Operating Statistics:

                   

Revenue days

    36,984     75,866     (51.3 )%

Average rig revenue per day

  $ 31,369   $ 30,211     3.8  

Average rig expense per day

  $ 14,117   $ 13,483     4.7  

Average rig margin per day

  $ 17,252   $ 16,728     3.1  

Number of rigs at end of period

    348     343     1.5  

Rig utilization

    30 %   62 %   (51.6 )

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $82,337 and $231,528 for 2016 and 2015, respectively.

Rig utilization in 2016 excludes four FlexRigs completed and ready for delivery at September 30, 2016.

        Operating income in the U.S. Land segment decreased to $74.1 million in 2016 from $698.4 million in 2015. Included in U.S. land revenues for 2016 and 2015 is approximately $219.0 million and $203.6 million, respectively, from early termination of fixed-term contracts.

        Excluding early termination related revenue, the average revenue per day for 2016 decreased by $2,080 to $25,448 from $27,528 in 2015. Low oil prices have continued to have a negative effect on customer spending. Some customers did not renew expiring contracts while others elected to terminate fixed-term contracts early. As a result, we experienced a 51 percent decrease in revenue days when comparing 2016 to 2015. Fixed-term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term (except in limited circumstances including sustained unacceptable performance by us).

        Direct operating expenses as a percentage of revenue were 49 percent in 2016 and 50 percent in 2015. In September 2016, we entered into a settlement agreement, subsequently approved by the court, regarding a lawsuit filed by an employee who was injured while working on a U.S. land rig. After

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taking into account amounts to be paid by our various insurers, we recorded an $18.8 million expense which reduced operating income and negatively impacted the average rig expense per day by $508. (See Note 13 of the Consolidated Financial Statements for additional disclosure regarding this lawsuit.)

        Depreciation includes charges for abandoned equipment of $38.8 million and $42.6 million in 2016 and 2015, respectively. Included in abandonments in 2016 is the retirement of used drilling equipment. 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. We recorded in fiscal 2016 a $6.3 million impairment charge to reduce the carrying value in rig and rig related equipment classified as held for sale to their estimated fair values, based on expected sales prices. The used drilling equipment is from rigs that were decommissioned from service in prior fiscal periods and written down to their estimated recoverable value at the time of decommissioning. Excluding the abandonment, depreciation in 2016 decreased from 2015, primarily due to low levels of capital expenditures in 2016 and the decommissioning of rigs in 2015. We anticipate depreciation expense to decline in fiscal 2017 as capital expenditures are expected to continue to decrease in fiscal 2017.

        Rig utilization decreased to 30 percent in 2016 from 62 percent in 2015. The total number of rigs at September 30, 2016 was 348 compared to 343 rigs at September 30, 2015. The net increase is due to five new FlexRigs completed in 2016 and included in our operating statistics. We have two FlexRigs expected to be delivered to the field in the first quarter of 2017.

        At September 30, 2016, 95 out of 348 existing rigs in the U.S. Land segment were generating revenue. Of the 95 rigs generating revenue, 72 were under fixed-term contracts, and 23 were working in the spot market. At November 17, 2016, the number of existing rigs under fixed-term contracts in the segment was 72 and the number of rigs working in the spot market was 33.

Comparison of the years ended September 30, 2016 and 2015

 
  2016   2015
(as adjusted)
  % Change  
 
  (in thousands, except operating statistics)
 

OFFSHORE OPERATIONS

                   

Operating revenues

  $ 138,601   $ 241,666     (42.6 )%

Direct operating expenses

    106,983     158,488     (32.5 )

General and administrative expense

    3,464     3,517     (1.5 )

Depreciation

    12,495     11,659     7.2  

Segment operating income

  $ 15,659   $ 68,002     (77.0 )

Operating Statistics:

                   

Revenue days

    2,708     3,067     (11.7 )%

Average rig revenue per day

  $ 26,973   $ 44,125     (38.9 )

Average rig expense per day

  $ 19,381   $ 27,246     (28.9 )

Average rig margin per day

  $ 7,592   $ 16,879     (55.0 )

Number of rigs at end of period

    9     9      

Rig utilization

    82 %   93 %   (11.8 )

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $23,138 and $33,254 for 2016 and 2015, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.

        Average rig revenue per day, average rig expense per day and average rig margin per day decreased in 2016 compared to 2015 primarily due to several rigs moving to lower pricing while on standby or other special dayrates.

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        At September 30, 2016 seven of our nine platform rigs were contracted compared to eight at September 30, 2015.

Comparison of the years ended September 30, 2016 and 2015

 
  2016   2015
(as adjusted)
  % Change  
 
  (in thousands, except operating statistics)
 

INTERNATIONAL LAND OPERATIONS

                   

Operating revenues

  $ 229,894   $ 382,331     (39.9 )%

Direct operating expenses

    183,969     289,700     (36.5 )

General and administrative expense

    2,909     3,148     (7.6 )

Depreciation

    57,102     57,334     (0.4 )

Asset impairment charge

        39,242     (100.0 )

Segment operating loss

  $ (14,086 ) $ (7,093 )   (98.6 )

Operating Statistics:

                   

Revenue days

    5,364     7,284     (26.4 )%

Average rig revenue per day

  $ 39,044   $ 47,352     (17.5 )

Average rig expense per day

  $ 28,638   $ 34,848     (17.8 )

Average rig margin per day

  $ 10,406   $ 12,504     (16.8 )

Number of rigs at end of period

    38     38      

Rig utilization

    39 %   51 %   (23.5 )

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $20,458 and $37,420 for 2016 and 2015, respectively. Also excluded are the effects of currency revaluation income and expense.

        The International Land segment had an operating loss of $14.1 million for 2016 compared to $7.1 million for 2015. Included in International land revenues in 2015 is approximately $18.7 million related to early termination of fixed-term contracts.

        Excluding early termination per day revenue of $2,566 in 2015, the average rig margin per day for 2016 compared to 2015 increased by $468 to $10,406. Low oil prices have continued to have a negative effect on customer spending. As a result, we experienced a 26 percent decrease in revenue days when comparing 2016 to 2015. The average number of active rigs was 14.7 during 2016 compared to 20.0 during 2015.

        The average rig expense per day decreased $6,210 or 18 percent as compared to the 2015 average rig expense that was impacted by expenses on rigs that had become idle and other costs associated with rigs transitioning between locations.

        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. Six of these rigs along with other rig related assets were classified as held for sale at September 30, 2016. We plan to sell these assets in their current condition.

        Included in direct operating expenses for 2016 is $9.8 million of foreign currency transaction losses, primarily due to a devaluation of the Argentine peso in December 2015.

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Comparison of the years ended September 30, 2015 and 2014

 
  2015
(as adjusted)
  2014
(as adjusted)
  % 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.

        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.

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Comparison of the years ended September 30, 2015 and 2014

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

OFFSHORE OPERATIONS

                   

Operating revenues

  $ 241,666   $ 251,341     (3.8 )%

Direct operating expenses

    158,488     159,214     (0.5 )

General and administrative expense

    3,517     9,858     (64.3 )

Depreciation

    11,659     12,300     (5.2 )

Segment operating income

  $ 68,002   $ 69,969     (2.8 )

Operating Statistics:

                   

Revenue days

    3,067     2,920     5.0 %

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 $33,254 and $18,889 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.

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Comparison of the years ended September 30, 2015 and 2014

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

INTERNATIONAL LAND OPERATIONS

                   

Operating revenues

  $ 382,331   $ 351,263     8.8 %

Direct operating expenses

    289,700     271,328     6.8  

General and administrative expense

    3,148     4,423     (28.8 )

Depreciation

    57,334     40,367     42.0  

Asset Impairment charge

    39,242         100.0  

Segment operating income (loss)

  $ (7,093 ) $ 35,145     (120.2 )

Operating Statistics:

                   

Revenue days

    7,284     8,262     (11.8 )%

Average rig revenue per day

  $ 47,352   $ 37,038     27.8  

Average rig expense per day

  $ 34,848   $ 27,297     27.7  

Average rig margin per day

  $ 12,504   $ 9,741     28.4  

Number of rigs at end of period

    38     36     5.6  

Rig utilization

    51 %   74 %   (31.1 )

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $37,420 and $45,258 for 2015 and 2014, respectively. Also excluded are the effects of currency revaluation income and expense.

        The International Land segment had an operating loss of $7.1 million for 2015 compared to operating income of $35.1 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 per day revenue of $2,566 in 2015, the average rig margin per day for 2015 compared to 2014 increased by $197 to $9,938. Rigs transferred into the segment during 2015 and 2014 favorably impacted average rig revenue and revenue per day. The average number of active rigs was 20.0 during 2015 compared to 22.6 during 2014.

        The average rig expense per day increase was attributable to expenses incurred on rigs that had become idle and other costs associated with rigs transitioning between locations. The average rig expense in 2015 was also impacted by approximately $690 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 15 and 22 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 did not have an impact on our liquidity or debt covenants.

LIQUIDITY AND CAPITAL RESOURCES

        Our capital spending was $257.2 million in 2016, $1.1 billion in 2015 and $951.5 million in 2014. Net cash provided from operating activities was $0.8 billion in 2016, $1.4 billion in 2015 and $1.1 billion in 2014. Our 2017 capital spending is currently estimated to be approximately $200 million, depending primarily on drilling market conditions. This estimate includes capital maintenance requirements, tubulars and other special projects primarily related to further upgrading our existing rig fleet.

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        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 invested $45.6 million in short-term investments classified as trading securities. We have reinvested maturities and earnings during 2016 resulting in short-term investments totaling $44.1 million at September 30, 2016. 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 2016, had a fair value of $71.5 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. During the fourth quarter of 2016, we determined that the decline in fair value below our cost basis in Atwood was other than temporary. As a result, we recorded a non-cash charge totaling $26.0 million.

        During 2016 and 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.

        Our proceeds from asset sales totaled $21.8 million in 2016, $22.6 million in 2015 and $30.2 million in 2014. Income from asset sales in 2016 totaled $9.9 million, $11.8 million in 2015 and $19.1 million in 2014. 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 are held as treasury shares. During 2016 we did not repurchase any shares of common stock.

        During 2016, we paid dividends of $2.763 per share, or a total of $300.2 million. We paid $2.75 per share or $298.4 million in 2015 and $2.438 per share or $264.4 million in 2014. Adjusting for stock splits accordingly, we have increased the effective annual dividend per share every year for well over 40 years.

        We had $40 million of senior unsecured fixed-rate notes outstanding that matured in July 2016. The final annual principal repayment of $40 million along with interest was paid with cash on hand in July 2016.

        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, have been or will be used for general corporate purposes, including capital expenditures associated with our rig construction program, capital maintenance requirements and other projects. Interest is payable semi-annually on March 15 and September 15. 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.

        On July 13, 2016, we terminated our previous $300 million unsecured revolving credit facility with no borrowings, and its $40.3 million of letters of credit were transferred to a new $300 million unsecured revolving credit facility which will mature on July 13, 2021. The new facility has $75 million available to use as letters of credit. The majority of any 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

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over LIBOR ranges from 1.125 percent to 1.75 percent per annum and commitment fees range from .15 percent to .30 percent per annum. Based on our debt to total capitalization on September 30, 2016, the spread over LIBOR and commitment fees would be 1.125 percent and .15 percent, respectively. There is one financial covenant in the facility which requires us to maintain a funded leverage ratio (as defined) of less than 50 percent. 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 including a limitation that priority debt (as defined in the agreement) may not exceed 17.5% of the net worth of the Company. As of September 30, 2016, there were no borrowings, but there were three letters of credit outstanding in the amount of $38.8 million. At September 30, 2016, we had $261.2 available to borrow under our $300 million unsecured credit facility. Subsequent to September 30, 2016, another letter of credit was issued for $1.5 million lowering the amount available to borrow to $259.7 million.

        In addition to the letters of credit mentioned in the preceding paragraph, at September 30, 2016, we had two letters of credit outstanding, totaling $12 million that were issued to support international operations. These additional letters of credit were issued separately from the $300 million credit facility discussed in the preceding paragraph and do not reduce the available borrowing capacity of that facility.

        The applicable agreements for all unsecured debt 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, 2016, we were in compliance with all debt covenants.

        At September 30, 2016, we had 88 existing rigs with fixed term contracts with original term durations ranging from six months to five years, with some expiring in fiscal 2017. 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 upgrade construction program, for fiscal 2017 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 4.8 at September 30, 2016 and 4.2 at September 30, 2015. The long-term debt to total capitalization ratio was 9.7 percent at September 30, 2016 compared to 9.8 percent at September 30, 2015.

Stock Portfolio Held

September 30, 2016
  Number
of Shares
  Cost Basis   Market Value  
 
  (in thousands, except share amounts)
 

Atwood Oceanics, Inc. 

    4,000,000   $ 34,760   $ 34,760  

Schlumberger, Ltd. 

    467,500     3,713     36,764  

Total

        $ 38,473   $ 71,524  

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Material Commitments

        We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations as of September 30, 2016, are summarized in the table below in thousands:

 
  Payments due by year  
Contractual Obligations
  Total   2017   2018   2019   2020   2021   After
2021
 

Long-term debt and estimated interest (a)

  $ 696,656   $ 23,250   $ 23,250   $ 23,250   $ 23,250   $ 23,250   $ 580,406  

Operating leases (b)

    36,573     8,550     5,680     5,214     4,401     3,049     9,679  

Purchase obligations (b)

    44,022     44,022                      

Total contractual obligations

  $ 777,251   $ 75,822   $ 28,930   $ 28,464   $ 27,651   $ 26,299   $ 590,085  

(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.

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

        In 2016, we did not make any contributions to the pension plan. Contributions may be made in fiscal 2017 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond fiscal 2017 are difficult to estimate due to multiple variables involved.

        At September 30, 2016, we had $16.3 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.

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        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 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 third fiscal quarter of 2016, we recorded a $6.3 million impairment charge to reduce the carrying values in used drilling equipment classified as held for sale in our U.S. Land segment to their estimated fair value. The rig and rig related equipment fair value was estimated based on expected sales prices.

        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, and most cyber risks.

        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 3.64 percent from 4.27 percent as of September 30, 2016 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,

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the rate of compensation increase assumption has been eliminated from future periods. We anticipate pension expense to decrease by approximately $4.7 million in 2017 from 2016.

        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.

        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, 2016, unrecognized compensation cost related to unvested restricted stock was $19.2 million. The cost is expected to be recognized over a weighted-average period of 2.1 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 May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers, which supersedes virtually all existing revenue recognition guidance. In May 2016, accounting guidance was issued to clarify the not yet effective revenue recognition guidance issued in May 2014. This additional guidance does not change the core principle of the revenue recognition guidance issued by the FASB in May 2014. Rather, it provides clarification of accounting for collections of sales taxes as well as recognition of revenue (i) associated with contract modifications, (ii) for noncash consideration, and (iii) based on the collectability of the consideration from the customer. The ASU provides for full retrospective, modified retrospective, or use of the cumulative effect method during the period of adoption. We have not yet determined which adoption method we will employ. In July 2015, the FASB extended the effective date of this standard to interim and annual periods beginning on or after December 15, 2017. We are currently evaluating 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

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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.

        In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The standard requires entities to measure equity investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any changes in fair value in net income. The provisions of ASU 2016-01 are effective for interim and annual periods starting after December 15, 2017. At adoption, a cumulative-effect adjustment to beginning retained earnings will be recorded. We will adopt this standard on October 1, 2018. Subsequent to adoption, changes in the fair value of our available-for-sale investments will be recognized in net income and the effect will be subject to stock market fluctuations.

        In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 will require organizations that lease assets—referred to as "lessees"—to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. Under ASU 2016-02, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Lessor accounting remains substantially similar to current GAAP. In addition, disclosures of leasing activities are to be expanded to include qualitative along with specific quantitative information. For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-02 mandates a modified retrospective transition method. We are currently evaluating the potential impact of adopting this guidance on our consolidated financial statements.

        In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the potential impact of adopting this guidance on our consolidated financial statements. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses. The ASU sets forth a "current expected credit loss" (CECL) model which requires companies to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable supportable forecasts. This replaces the existing incurred loss model and is applicable to the measurement of credit losses on financial assets measured at amortized cost and applies to some off-balance sheet credit exposures. This standard is effective for interim and annual periods beginning after December 15, 2019. We are currently assessing the impact this standard will have on our consolidated financial statements and disclosures.

        In August 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). The ASU is intended to reduce diversity in practice in presentation and classification of certain cash receipts and cash payments by providing guidance on eight specific cash flow issues. The ASU is effective for interim and annual periods beginning after December 15, 2017 and early adoption is permitted, including adoption during an interim period. We are currently assessing the impact this standard will have on our consolidated statement of cash flows.

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

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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 December 2015, the Argentine peso experienced a sharp devaluation resulting in an aggregate foreign currency loss of $8.5 million for the three months ended December 31, 2015. Subsequent to the devaluation, the Argentine peso stabilized and the Argentine Foreign Exchange Market controls now place fewer restrictions on repatriating U.S. dollars. These changes have limited our current foreign currency exchange rate risk in Argentina. However, in the future we may incur currency devaluations, foreign exchange restrictions or other difficulties repatriating U.S. dollars in Argentina or elsewhere which could have a material adverse impact on our business, financial condition and results of operations. For example, assuming we encounter future foreign exchange restrictions or other difficulties repatriating U.S. dollars in Argentina resulting in a substantial accumulation of Argentine pesos, a hypothetical 10% decrease in the value of our Argentine pesos relative to the U.S. dollar could result in a $1.8 million decrease in the fair value of our monetary assets and liabilities denominated in Argentine pesos.

        Estimates from published sources indicate that Argentina is a highly inflationary country, 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. 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 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. Similarly, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by, among other things, oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health of the drilling and overall oil and gas industry, and the liquidity of the capital markets. Many of the factors that affect our ability to access capital markets are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations.

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        Further, 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, 2016 has fixed-rate interest obligations, there is no current risk due to interest rate fluctuation.

        The following tables provide information as of September 30, 2016 and 2015 about our interest rate risk sensitive instruments:

INTEREST RATE RISK AS OF SEPTEMBER 30, 2016 (dollars in thousands)