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

FORM 10-K

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

 

 

For the fiscal year ended September 30, 2014

 

 

OR

o

 

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

For the transition period from            to          

Commission file number 1-4221

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

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

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

 

74119-3623
(Zip Code)

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

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

Title of Each Class   Name of Each Exchange on Which Registered

Common Stock ($0.10 par value)

  New York Stock Exchange

Preferred Stock Purchase Rights

  New York Stock Exchange

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

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

         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, 2014, the aggregate market value of the voting stock held by non-affiliates was approximately $11.3 billion.

         Number of shares of common stock outstanding at November 14, 2014:    108,256,492.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the Registrant's 2015 Proxy Statement for the Annual Meeting of Stockholders to be held on March 4, 2015 are incorporated by reference into Part III of this Form 10-K. The 2015 Proxy Statement will be filed with the U.S. Securities and Exchange Commission ("SEC") within 120 days after the end of the fiscal year to which this Form 10-K relates.


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DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

        This Annual Report on Form 10-K ("Form 10-K") includes "forward-looking statements" within the meaning of the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-K, including, without limitation, statements regarding the Registrant's future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as "may", "will", "expect", "intend", "estimate", "anticipate", "believe", or "continue" or the negative thereof or similar terminology. Although the Registrant believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Important factors that could cause actual results to differ materially from the Registrant's expectations or results discussed in the forward-looking statements are disclosed in this Form 10-K under Item 1A—"Risk Factors", as well as in Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations." All subsequent written and oral forward-looking statements attributable to the Registrant, or persons acting on its behalf, are expressly qualified in their entirety by such cautionary statements. The Registrant assumes no duty to update or revise its forward-looking statements based on changes in internal estimates, expectations or otherwise, except as required by law.


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HELMERICH & PAYNE, INC.
FORM 10-K
YEAR ENDED SEPTEMBER 30, 2014

TABLE OF CONTENTS

 
   
  Page  

PART I

 

Item 1.

 

Business

   
1
 

Item 1A.

 

Risk Factors

    6  

Item 1B.

 

Unresolved Staff Comments

    15  

Item 2.

 

Properties

    16  

Item 3.

 

Legal Proceedings

    25  

Item 4.

 

Mine Safety Disclosures

    25  

 

Executive Officers of the Company

    26  

PART II

 

Item 5.

 

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

   
27
 

Item 6.

 

Selected Financial Data

    29  

Item 7.

 

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

    30  

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

    43  

Item 8.

 

Financial Statements and Supplementary Data

    44  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    85  

Item 9A.

 

Controls and Procedures

    85  

Item 9B.

 

Other Information

    88  

PART III

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

   
88
 

Item 11.

 

Executive Compensation

    88  

Item 12.

 

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

    88  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    88  

Item 14.

 

Principal Accountant Fees and Services

    88  

PART IV

 

Item 15.

 

Exhibits and Financial Statement Schedules

   
89
 

SIGNATURES

   
94
 

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PART I

Item 1.    BUSINESS

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

        Our contract drilling business is composed of three reportable business segments: U.S. Land, Offshore and International Land. During fiscal 2014, our U.S. Land operations drilled primarily in Oklahoma, California, Texas, Wyoming, Colorado, Louisiana, Mississippi, Pennsylvania, Ohio, Utah, New Mexico, Montana, North Dakota, West Virginia and Nevada. Offshore operations were conducted in the Gulf of Mexico and Equatorial Guinea. Our International Land segment operated in seven international locations during fiscal 2014: Ecuador, Colombia, Argentina, Tunisia, Bahrain, United Arab Emirates ("UAE") and Mozambique.

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

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

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

    CONTRACT DRILLING

    General

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

        In fiscal 2014, we received approximately 56 percent of our consolidated operating revenues from our ten largest contract drilling customers. Occidental Oil and Gas Corporation, Marathon and BHP Billiton (respectively, "Oxy", "Marathon" and "BHP"), including their affiliates, are our three largest contract drilling customers. We perform drilling services for Oxy on a world-wide basis and Marathon and BHP in U.S. land operations. Revenues from drilling services performed for Oxy, Marathon and BHP in fiscal 2014 accounted for approximately 11 percent, 8 percent and 7 percent, respectively, of our consolidated operating revenues for the same period.

    Rigs, Equipment and Facilities

        We provide drilling rigs, equipment, personnel and camps on a contract basis. These services are provided so that our customers may explore for and develop oil and gas from onshore areas and from

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

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

        During the mid-1990's, we undertook an initiative to use our land and offshore platform drilling experience to develop a new generation of drilling rigs that would be safer, faster-moving and more capable than mechanical rigs. In 1998, we put to work a new generation of highly mobile/depth flexible land drilling rigs (individually the "FlexRig®"). Since the introduction of our FlexRigs, we have focused on designing and building high-performance, high-efficiency rigs to be used exclusively in our contract drilling business. We believed that over time FlexRigs would displace older less capable rigs. With the advent of unconventional shale plays, our AC drive FlexRigs have proven to be particularly well suited for more complex horizontal drilling requirements. The FlexRig has been able to significantly reduce average rig move and drilling times compared to similar depth-rated traditional land rigs. In addition, the FlexRig allows greater depth flexibility and provides greater operating efficiency. The original rigs were designated as FlexRig1 and FlexRig2 rigs and were designed to drill wells with a depth of between 8,000 and 18,000 feet. In 2001, we announced that we would build the next generation of FlexRigs, known as "FlexRig3", which incorporated new drilling technology and new environmental and safety design. This new design included integrated top drive, AC electric drive, hydraulic BOP handling system, hydraulic tubular make-up and break-out system, split crown and traveling blocks and an enlarged drill floor that enables simultaneous crew activities. FlexRig3s were designed to target well depths of between 8,000 and 22,000 feet.

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

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of FlexRig3 combined with a bi-directional pad drilling system and equipment capacities suitable for wells in excess of 25,000 feet of measured depth.

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

        Since 1998, we have built and delivered 344 FlexRigs, including 207 FlexRig3s, 88 FlexRig4s, and 32 FlexRig5s. Of the total FlexRigs built through September 30, 2014, 161 have been built in the last five years. As of November 13, 2014, an additional 41 new FlexRigs remained under construction.

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

        We assemble new FlexRigs at our gulf coast facility near Houston, Texas. We also have a 123,000 square foot fabrication facility located on approximately 11 acres near Tulsa, Oklahoma. Additionally, we lease a 150,000 square foot industrial facility near Tulsa, Oklahoma, for the purpose of overhauling/repairing rig equipment and associated component parts.

    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 2014, all drilling services were performed on a "daywork" contract basis, under which we charge a fixed rate per day, with the price determined by the location, depth and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. We have previously performed contracts on a combination "footage" and "daywork" basis, under which we charged a fixed rate per foot of hole drilled to a stated depth, usually no deeper than 15,000 feet, and a fixed rate per day for the remainder of the hole. Contracts performed on a "footage" basis involve a greater element of risk to the contractor than do contracts performed on a "daywork" basis. Also, we have previously accepted "turnkey" contracts under which we charge a fixed sum to deliver a hole to a stated depth and agree to furnish services such as testing, coring and casing the hole which are not normally done on a "footage" basis. "Turnkey" contracts entail varying degrees of risk greater than the usual "footage" contract. We have not accepted any "footage" or "turnkey" contracts in over fifteen years. We believe that under current market conditions, "footage" and "turnkey" contract rates do not adequately compensate us for the added risks. The duration of our drilling contracts are "well-to-well" or for a fixed term. "Well-to-well" contracts are cancelable at the option of either party upon the completion of drilling at any one site. Fixed-term contracts generally have a minimum term of at least six months but customarily provide for termination at the election of the customer, with an "early termination payment" to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us.

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

        As of September 30, 2014, we had 193 existing rigs under fixed-term contracts. While the original duration for these current fixed-term contracts are for six-month to seven-year periods, some fixed-term

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and well-to-well contracts are expected to be extended for longer periods than the original terms. However, the contracting parties have no legal obligation to extend these contracts.

    Backlog

        Our contract drilling backlog, being the expected future revenue from executed contracts with original terms in excess of one year, as of September 30, 2014 and 2013 was $5.0 billion and $2.9 billion, respectively. The increase in backlog at September 30, 2014 from September 30, 2013, is primarily due to the execution of additional fixed-term contracts for the operation of new FlexRigs. Approximately 63.6 percent of the total September 30, 2014 backlog is not reasonably expected to be filled in fiscal 2015. A portion of the backlog represents term contracts for new rigs that will be constructed in the future.

        The following table sets forth the total backlog by reportable segment as of September 30, 2014 and 2013, and the percentage of the September 30, 2014 backlog not reasonably expected to be filled in fiscal 2015:

 
  Total Backlog Revenue    
 
  Percentage Not Reasonably
Expected to be Filled in Fiscal 2015
Reportable Segment
  9/30/2014   9/30/2013
 
  (in billions)
   

U.S. Land

  $ 3.8   $ 2.4   59.4%

Offshore

    0.1     0.1   70.9%

International

    1.1     0.4   76.9%
             

  $ 5.0   $ 2.9    
             
             

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

    U.S. Land Drilling

        At the end of September 2014, 2013, and 2012, we had 329, 302 and 282, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2014 increased by a net of 27 rigs from the end of fiscal 2013. The increase is due to 42 new FlexRigs being placed into service, six FlexRigs being transferred to the International Land segment and nine older conventional rigs being removed from service. Our U.S. Land operations contributed approximately 83 percent ($3.1 billion) of our consolidated operating revenues during fiscal 2014, compared with approximately 82 percent ($2.8 billion) of consolidated operating revenues during fiscal 2013 and approximately 85 percent ($2.7 billion) of consolidated operating revenues during fiscal 2012. Rig utilization was approximately 86 percent in fiscal 2014, approximately 82 percent in fiscal 2013 and approximately 89 percent in fiscal 2012. Our fleet of FlexRigs had an average utilization of approximately 91 percent during fiscal 2014, while our conventional rigs had an average utilization of approximately 3 percent. A rig is considered to be utilized when it is operated or being mobilized or demobilized under contract. At the close of fiscal 2014, 294 out of an available 329 land rigs were working.

    Offshore Drilling

        Our Offshore operations contributed approximately 7 percent in fiscal year 2014 ($250.8 million) of our consolidated operating revenues compared to approximately 7 percent ($221.9 million) of consolidated operating revenues during fiscal 2013 and 6 percent ($189.1 million) of consolidated

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operating revenues during fiscal 2012. Rig utilization in fiscal 2014 and fiscal 2013 was approximately 89 percent compared to approximately 79 percent in fiscal 2012. At the end of fiscal 2014, we had eight of our nine offshore platform rigs under contract and continued to work under management contracts for three customer-owned rigs. The ninth rig commenced operations during the first fiscal quarter of 2015. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 52 percent of offshore revenues during fiscal 2014.

    International Land Drilling

    General

        Our International Land operations contributed approximately 10 percent ($355.5 million) of our consolidated operating revenues during fiscal 2014, compared with approximately 11 percent ($366.8 million) of consolidated operating revenues during fiscal 2013 and 9 percent ($270.0 million) of consolidated operating revenues during fiscal 2012. Rig utilization in fiscal 2014 was 76 percent, 82 percent in fiscal 2013 and 77 percent in fiscal 2012.

    Argentina

        At the end of fiscal 2014, we had 14 rigs in Argentina. Our utilization rate was approximately 80 percent during fiscal 2014, approximately 62 percent during fiscal 2013 and approximately 52 percent during fiscal 2012. Revenues generated by Argentine drilling operations contributed approximately 3 percent in fiscal 2014 ($107.9 million) of our consolidated operating revenues compared to approximately 2 percent ($73.2 million) of our consolidated operating revenues during fiscal 2013 and approximately 2 percent ($54.3 million) of our consolidated operating revenues during fiscal 2012. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 2 percent of consolidated operating revenues and approximately 21 percent of international operating revenues during fiscal 2014. The Argentine drilling contracts are primarily with large international or national oil companies.

    Colombia

        At the end of fiscal 2014, we had eight rigs in Colombia. Our utilization rate was approximately 63 percent during fiscal 2014, approximately 82 percent during fiscal 2013 and approximately 79 percent during fiscal 2012. Revenues generated by Colombian drilling operations contributed approximately 2 percent in fiscal 2014 ($85.2 million) of our consolidated operating revenues compared to approximately 3 percent ($100.1 million) of our consolidated operating revenues during fiscal 2013 and approximately 3 percent ($82.2 million) of our consolidated operating revenues during fiscal 2012. Revenues from drilling services performed for our two customers in Colombia totaled approximately 2 percent of consolidated operating revenues and approximately 24 percent of international operating revenues during fiscal 2014. The Colombian drilling contracts are primarily with large international or national oil companies.

    Ecuador

        At the end of fiscal 2014, we had six rigs in Ecuador. The utilization rate in Ecuador was 85 percent in fiscal 2014, compared to 95 percent in fiscal 2013 and 97 percent in fiscal 2012. Revenues generated by Ecuadorian drilling operations contributed approximately two percent in each of the three fiscal years 2014, 2013 and 2012 of our consolidated operating revenues ($69.2 million, $67.9 million and $56.4 million, respectively). Revenues from drilling services performed for the largest customer in Ecuador totaled approximately 1 percent of consolidated operating revenues and approximately 11 percent of international operating revenues during fiscal 2014. The Ecuadorian drilling contracts are primarily with large international or national oil companies.

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    Other Locations

        In addition to our operations discussed above, at the end of fiscal 2014 we had two rigs in Tunisia, three rigs in Bahrain, two rigs in the UAE and one rig in Mozambique.

    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 10,352 employees within the United States (13 of which were part-time employees) and 1,562 employees in international operations as of September 30, 2014.

    AVAILABLE INFORMATION

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

Item 1A.    RISK FACTORS

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

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

        Our business depends on the conditions of the land and offshore oil and natural gas industry. Demand for our services depends on oil and natural gas industry exploration and production activity and expenditure levels, which are directly affected by trends in oil and natural gas prices. Oil and natural gas prices, and market expectations regarding potential changes to these prices, significantly affect oil and natural gas industry activity. Higher oil and natural gas prices do not necessarily translate into increased activity because demand for our services is typically driven by our customers' expectations of future commodity prices. Commodity prices have historically been volatile. 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 prices;

    domestic and international tax policies;

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

    technological advances;

    the development and exploitation of alternative fuels;

    local and international political, economic and weather conditions;

    the 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; 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. A decline in the worldwide demand for oil and natural gas or prolonged low oil or natural gas prices in the future would likely result in reduced exploration and development of land and offshore areas and a decline in the demand for our services. Even during periods of high prices for oil and natural gas, companies exploring for oil and gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons. These factors could cause our revenues and margins to decline, reduce day rates and utilization of our rigs and limit our future growth prospects. In short, any prolonged reduction in demand for our services 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 new-build rig assembly facility located near the Houston, Texas ship channel, and our principal fabricator and other vendors are also located in the gulf coast region. Due to their location, these facilities are exposed to potentially greater hurricane damage.

        We have indemnification agreements with many of our customers and we also maintain liability and other forms of insurance. In general, our drilling contracts contain provisions requiring our

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customers to indemnify us for, among other things, pollution and reservoir damage. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts by us, our subcontractors and/or suppliers. Our customers may also dispute, or be unable to meet, their contractual indemnification obligations to us. Accordingly, we may be unable to transfer these risks to our drilling customers by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect 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 policy. However, we self-insure a large deductible as well as a significant portion of the estimated replacement cost of our offshore rigs and our land rigs and equipment. We also carry insurance with varying deductibles and coverage limits with respect to offshore platform rigs and "named wind storm" risk in the Gulf of Mexico.

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

        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 2015, 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 spending on exploration and development drilling or whether customers and/or vendors and suppliers will be able to access financing necessary to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations. In the event the global economic environment remains tepid or deteriorates, industry fundamentals may be impacted and result in stagnant or reduced demand for drilling rigs. Furthermore, these factors may result in certain of our customers experiencing an inability to pay vendors, including us. The global economic environment in the past has experienced significant deterioration in a relatively short period of time and there can be no assurance that the global economic environment will not quickly deteriorate again due to one or more factors. These conditions could have a material adverse effect on our business, financial condition and results of operations.

The contract drilling business is highly competitive.

        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

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region to another in response to changes in levels of activity, and an oversupply of rigs in any region may result, leading to increased price competition.

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

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 2014, we received approximately 56 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 26 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 will be necessary to keep pace with the bifurcation of the drilling industry, and growth through the building of new drilling 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 are increasingly demanding 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 build new, technologically advanced drilling rigs;

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

    successfully integrate additional drilling rigs;

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

    successfully deploy idle, stacked or additional drilling rigs;

    maintain crews necessary to operate additional drilling rigs; or

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

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

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

        It is a common practice in our industry for our customers to recover natural gas and oil from shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations using water, sand and other additives pumped under high pressure into the formation. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure, waste disposal and/or well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Members of the U.S. Congress and a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing and the possibility of more stringent regulation. For example, the U.S. Environmental Protection Agency has undertaken a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. Depending on the outcome of these or other studies, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing activities. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques, operational delays or increased operating and compliance costs in the production of oil and natural gas from shale plays, added difficulty in performing hydraulic fracturing, and potentially a decline in the completion of new oil and gas wells.

        We do not engage in any hydraulic fracturing activities. However, any new laws, regulations or permitting requirements regarding hydraulic fracturing could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the drilling services we provide. Widespread regulation significantly restricting or prohibiting hydraulic fracturing by our customers could have a material adverse impact on our business, financial condition and results of operation.

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

        On November 8, 2013, the United States District Court for the Eastern District of Louisiana approved the previously disclosed October 30, 2013 plea agreement between our wholly owned subsidiary, Helmerich & Payne International Drilling Co. ("H&PIDC"), and the United States Department of Justice, United States Attorney's Office for the Eastern District of Louisiana ("DOJ"). The court's approval of the plea agreement resolved the DOJ's investigation into certain choke manifold testing irregularities that occurred in 2010 at one of H&PIDC's offshore platform rigs in the Gulf of Mexico. As part of the plea agreement, H&PIDC agreed, during a three-year probationary period, to not commit any further criminal violations and to fulfill the terms of an environmental compliance plan ("ECP") whose purpose is to develop and implement additional training and safety

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programs. Our ability to comply with the terms of the plea agreement is dependent, in part, on our successful implementation of the additional training and safety programs set forth in the ECP. While not anticipated, a failure to comply with the terms of the plea agreement, including the ECP, could result in prosecution and other regulatory sanctions, and could otherwise adversely affect our business. We have been engaged in discussions with the Inspector General's office of the Department of Interior regarding the same events that were the subject of the DOJ's investigation. Although we presently believe that the outcome of our discussions will not have a material adverse effect on us, we can provide no assurances as to the timing or eventual outcome of these discussions. In addition, we could be exposed to civil litigation arising from the events that were the subject of the DOJ's investigation. Any such litigation may result in financial liability. 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 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 2014, approximately 10 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2014, approximately 74 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.

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

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

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

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

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

        At September 30, 2014, we had a portfolio of securities with a total fair value of approximately $222 million, consisting of Atwood Oceanics, Inc. and Schlumberger, Ltd. These securities are subject to a wide variety of market-related risks that could substantially reduce or increase the fair value of our holdings. The portfolio is recorded at fair value on our balance sheet with changes in unrealized after-tax value reflected in the equity section of our balance sheet. At November 13, 2014, the fair value of the portfolio had decreased to approximately $185 million.

Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti-bribery legislation, other governmental regulations and environmental laws 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.

        Additionally, 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

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and regulations in the United States impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of drilling rigs, we may be deemed to be a responsible party under these laws and regulations.

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

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

        Scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs") and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. The United States Congress may consider legislation to reduce GHG emissions. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding GHG emissions could have a material adverse impact on our business, financial condition and results of operations.

Legal proceedings could have a negative impact on our business.

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

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. Based upon current information, we believe that our exposure to potential losses from currency restrictions and devaluation in foreign countries is immaterial. However, 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 the event of future payments in foreign currencies and an inability to timely exchange foreign currencies for U.S. dollars, we may incur currency devaluation losses which could have a material adverse impact on our business, financial condition and results of operations.

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Our current backlog of contract drilling revenue 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 poor global economic environment may affect the customer's ability 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, including those described above. As of September 30, 2014, our contract drilling backlog was approximately $5.0 billion for future revenues under firm commitments. 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.

We may have additional tax liabilities.

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

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.

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.

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, loss of our intellectual property, theft of our FlexRig and other technology, loss or

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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.

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

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

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

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

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

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

Item 1B.    UNRESOLVED STAFF COMMENTS

        We have received no written comments regarding our periodic or current reports from the staff of the SEC that were issued 180 days or more preceding the end of our 2014 fiscal year and that remain unresolved.

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Item 2.    PROPERTIES

    CONTRACT DRILLING

        The following table sets forth certain information concerning our U.S. land and offshore drilling rigs as of September 30, 2014:

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

FLEXRIGS

                       

TEXAS

   
164
   
18,000
 

SCR (FlexRig1)

   
1,500
 

TEXAS

    165     18,000   SCR (FlexRig1)     1,500  

TEXAS

    166     18,000   SCR (FlexRig1)     1,500  

TEXAS

    167     18,000   SCR (FlexRig1)     1,500  

TEXAS

    168     18,000   SCR (FlexRig1)     1,500  

TEXAS

    169     18,000   SCR (FlexRig1)     1,500  

NORTH DAKOTA

    179     18,000   SCR (FlexRig2)     1,500  

NORTH DAKOTA

    180     18,000   SCR (FlexRig2)     1,500  

TEXAS

    181     18,000   SCR (FlexRig2)     1,500  

TEXAS

    182     18,000   SCR (FlexRig2)     1,500  

TEXAS

    183     18,000   SCR (FlexRig2)     1,500  

TEXAS

    184     18,000   SCR (FlexRig2)     1,500  

TEXAS

    185     18,000   SCR (FlexRig2)     1,500  

TEXAS

    186     18,000   SCR (FlexRig2)     1,500  

TEXAS

    187     18,000   SCR (FlexRig2)     1,500  

TEXAS

    188     18,000   SCR (FlexRig2)     1,500  

OKLAHOMA

    189     18,000   SCR (FlexRig2)     1,500  

TEXAS

    210     22,000   AC (FlexRig3)     1,500  

TEXAS*

    211     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    212     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    214     22,000   AC (FlexRig3)     1,500  

WYOMING

    215     22,000   AC (FlexRig3)     1,500  

TEXAS

    216     22,000   AC (FlexRig3)     1,500  

TEXAS

    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  

NEW MEXICO

    223     22,000   AC (FlexRig3)     1,500  

TEXAS

    224     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

    231     22,000   AC (FlexRig3)     1,500  

TEXAS

    232     22,000   AC (FlexRig3)     1,500  

TEXAS

    233     22,000   AC (FlexRig3)     1,500  

TEXAS

    235     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    236     22,000   AC (FlexRig3)     1,500  

TEXAS*

    238     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    239     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    240     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    241     22,000   AC (FlexRig3)     1,500  

TEXAS

    244     22,000   AC (FlexRig3)     1,500  

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

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  

MISSISSIPPI

    249     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    250     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    251     22,000   AC (FlexRig3)     1,500  

TEXAS

    252     22,000   AC (FlexRig3)     1,500  

TEXAS

    253     22,000   AC (FlexRig3)     1,500  

TEXAS

    254     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    255     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    256     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    257     22,000   AC (FlexRig3)     1,500  

MONTANA

    258     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    259     22,000   AC (FlexRig3)     1,500  

TEXAS

    260     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    261     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    262     22,000   AC (FlexRig3)     1,500  

TEXAS

    263     22,000   AC (FlexRig3)     1,500  

TEXAS

    264     22,000   AC (FlexRig3)     1,500  

TEXAS

    265     22,000   AC (FlexRig3)     1,500  

TEXAS

    266     22,000   AC (FlexRig3)     1,500  

TEXAS

    267     22,000   AC (FlexRig3)     1,500  

TEXAS

    268     22,000   AC (FlexRig3)     1,500  

TEXAS

    269     22,000   AC (FlexRig3)     1,500  

WYOMING

    271     18,000   AC (FlexRig4)     1,500  

MONTANA

    272     18,000   AC (FlexRig4)     1,500  

COLORADO

    273     18,000   AC (FlexRig4)     1,500  

TEXAS

    274     18,000   AC (FlexRig4)     1,500  

WYOMING

    275     18,000   AC (FlexRig4)     1,500  

UTAH

    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  

OHIO

    284     18,000   AC (FlexRig4)     1,500  

WEST VIRGINIA

    285     18,000   AC (FlexRig4)     1,500  

NORTH DAKOTA

    286     18,000   AC (FlexRig4)     1,500  

OHIO

    287     18,000   AC (FlexRig4)     1,500  

TEXAS

    288     18,000   AC (FlexRig4)     1,500  

LOUISIANA

    289     18,000   AC (FlexRig4)     1,500  

OHIO

    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  

17


Table of Contents

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

OKLAHOMA

    297     18,000   AC (FlexRig4)     1,500  

WYOMING

    298     18,000   AC (FlexRig4)     1,500  

TEXAS

    299     18,000   AC (FlexRig4)     1,500  

NEW MEXICO

    300     18,000   AC (FlexRig4)     1,500  

TEXAS

    302     8,000   AC (FlexRig4)     1,150  

TEXAS

    303     8,000   AC (FlexRig4)     1,150  

TEXAS

    304     8,000   AC (FlexRig4)     1,150  

TEXAS

    305     8,000   AC (FlexRig4)     1,150  

TEXAS

    306     8,000   AC (FlexRig4)     1,150  

COLORADO

    307     18,000   AC (FlexRig4)     1,500  

COLORADO

    308     18,000   AC (FlexRig4)     1,500  

NORTH DAKOTA

    309     18,000   AC (FlexRig4)     1,500  

WYOMING

    310     18,000   AC (FlexRig4)     1,500  

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  

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  

OKLAHOMA

    328     18,000   AC (FlexRig4)     1,500  

COLORADO

    329     18,000   AC (FlexRig4)     1,500  

COLORADO

    330     18,000   AC (FlexRig4)     1,500  

LOUISIANA

    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  

18


Table of Contents

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

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  

CALIFORNIA

    380     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    381     22,000   AC (FlexRig3)     1,500  

TEXAS

    382     22,000   AC (FlexRig3)     1,500  

TEXAS

    383     22,000   AC (FlexRig3)     1,500  

TEXAS

    384     22,000   AC (FlexRig3)     1,500  

OHIO

    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  

NEW MEXICO

    391     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    392     22,000   AC (FlexRig3)     1,500  

TEXAS

    393     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    394     22,000   AC (FlexRig3)     1,500  

TEXAS

    395     22,000   AC (FlexRig3)     1,500  

TEXAS

    396     22,000   AC (FlexRig3)     1,500  

TEXAS

    397     22,000   AC (FlexRig3)     1,500  

TEXAS

    398     22,000   AC (FlexRig3)     1,500  

TEXAS

    399     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    415     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    416     22,000   AC (FlexRig3)     1,500  

LOUISIANA

    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  

19


Table of Contents

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

TEXAS

    429     22,000   AC (FlexRig3)     1,500  

TEXAS

    430     22,000   AC (FlexRig3)     1,500  

TEXAS

    431     22,000   AC (FlexRig3)     1,500  

TEXAS

    432     22,000   AC (FlexRig3)     1,500  

TEXAS

    433     22,000   AC (FlexRig3)     1,500  

TEXAS

    434     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    435     22,000   AC (FlexRig3)     1,500  

TEXAS

    436     22,000   AC (FlexRig3)     1,500  

TEXAS

    437     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    438     22,000   AC (FlexRig3)     1,500  

TEXAS

    439     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    440     22,000   AC (FlexRig3)     1,500  

TEXAS

    441     22,000   AC (FlexRig3)     1,500  

TEXAS

    442     22,000   AC (FlexRig3)     1,500  

TEXAS

    443     22,000   AC (FlexRig3)     1,500  

CALIFORNIA

    444     22,000   AC (FlexRig3)     1,500  

TEXAS

    445     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    446     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    447     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    448     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    449     22,000   AC (FlexRig3)     1,500  

OKLAHOMA

    450     22,000   AC (FlexRig3)     1,500  

TEXAS

    451     22,000   AC (FlexRig3)     1,500  

TEXAS

    452     22,000   AC (FlexRig3)     1,500  

TEXAS

    453     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    454     22,000   AC (FlexRig3)     1,500  

TEXAS

    455     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    456     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    457     22,000   AC (FlexRig3)     1,500  

TEXAS

    458     22,000   AC (FlexRig3)     1,500  

TEXAS

    459     22,000   AC (FlexRig3)     1,500  

TEXAS

    460     22,000   AC (FlexRig3)     1,500  

TEXAS

    461     22,000   AC (FlexRig3)     1,500  

TEXAS

    462     22,000   AC (FlexRig3)     1,500  

TEXAS

    463     22,000   AC (FlexRig3)     1,500  

TEXAS

    464     22,000   AC (FlexRig3)     1,500  

TEXAS

    465     22,000   AC (FlexRig3)     1,500  

TEXAS

    466     22,000   AC (FlexRig3)     1,500  

TEXAS

    467     22,000   AC (FlexRig3)     1,500  

TEXAS

    468     22,000   AC (FlexRig3)     1,500  

TEXAS

    469     22,000   AC (FlexRig3)     1,500  

TEXAS

    470     22,000   AC (FlexRig3)     1,500  

NORTH DAKOTA

    471     22,000   AC (FlexRig3)     1,500  

TEXAS

    472     22,000   AC (FlexRig3)     1,500  

TEXAS

    473     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    474     22,000   AC (FlexRig3)     1,500  

TEXAS

    475     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    477     22,000   AC (FlexRig3)     1,500  

TEXAS

    478     22,000   AC (FlexRig3)     1,500  

20


Table of Contents

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

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  

NEW MEXICO

    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  

TEXAS

    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  

PENNSYLVANIA

    500     25,000   AC (FlexRig5)     1,500  

TEXAS

    501     25,000   AC (FlexRig5)     1,500  

TEXAS

    502     25,000   AC (FlexRig5)     1,500  

TEXAS

    503     25,000   AC (FlexRig5)     1,500  

TEXAS

    504     25,000   AC (FlexRig5)     1,500  

TEXAS

    505     25,000   AC (FlexRig5)     1,500  

TEXAS

    506     25,000   AC (FlexRig5)     1,500  

TEXAS

    507     25,000   AC (FlexRig5)     1,500  

TEXAS

    508     25,000   AC (FlexRig5)     1,500  

TEXAS

    509     25,000   AC (FlexRig5)     1,500  

TEXAS

    510     25,000   AC (FlexRig5)     1,500  

TEXAS

    511     25,000   AC (FlexRig5)     1,500  

TEXAS

    512     25,000   AC (FlexRig5)     1,500  

TEXAS

    513     25,000   AC (FlexRig5)     1,500  

TEXAS

    514     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    515     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    516     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    517     25,000   AC (FlexRig5)     1,500  

TEXAS

    518     25,000   AC (FlexRig5)     1,500  

TEXAS

    519     25,000   AC (FlexRig5)     1,500  

WYOMING

    520     25,000   AC (FlexRig5)     1,500  

PENNSYLVANIA

    521     25,000   AC (FlexRig5)     1,500  

COLORADO

    522     25,000   AC (FlexRig5)     1,500  

LOUISIANA

    523     25,000   AC (FlexRig5)     1,500  

NORTH DAKOTA

    524     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    525     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    526     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    527     25,000   AC (FlexRig5)     1,500  

OKLAHOMA

    528     25,000   AC (FlexRig5)     1,500  

21


Table of Contents

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

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

    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  

NEW MEXICO

    615     22,000   AC (FlexRig3)     1,500  

TEXAS

    616     22,000   AC (FlexRig3)     1,500  

TEXAS

    617     22,000   AC (FlexRig3)     1,500  

TEXAS

    618     22,000   AC (FlexRig3)     1,500  

TEXAS

    619     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    620     22,000   AC (FlexRig3)     1,500  

NEW MEXICO

    621     22,000   AC (FlexRig3)     1,500  

TEXAS

    622     22,000   AC (FlexRig3)     1,500  

MISSISSIPPI

    623     22,000   AC (FlexRig3)     1,500  

TEXAS

    624     22,000   AC (FlexRig3)     1,500  

COLORADO

    625     22,000   AC (FlexRig3)     1,500  

TEXAS

    626     22,000   AC (FlexRig3)     1,500  

TEXAS

    627     22,000   AC (FlexRig3)     1,500  

PENNSYLVANIA

    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  

CONVENTIONAL RIGS

   
 
   
 
 

 

   
 
 

LOUISIANA

   
72
   
30,000
 

SCR

   
3,000
 

OKLAHOMA

    73     30,000   SCR     3,000  

LOUISIANA

    134     30,000   SCR     3,000  

TEXAS

    136     30,000   SCR     3,000  

TEXAS

    157     30,000   SCR     3,000  

LOUISIANA

    161     30,000   SCR     3,000  

LOUISIANA

    163     30,000   SCR     3,000  

OFFSHORE PLATFORM RIGS

   
 
   
 
 

 

   
 
 

GULF OF MEXICO

   
203
   
20,000
 

Self-Erecting

   
2,500
 

GULF OF MEXICO

    205     20,000   Self-Erecting     2,000  

GULF OF MEXICO

    206     20,000   Self-Erecting     2,000  

22


Table of Contents

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

GULF OF MEXICO

    100     30,000   Conventional     3,000  

GULF OF MEXICO

    105     30,000   Conventional     3,000  

GULF OF MEXICO

    107     30,000   Conventional     3,000  

GULF OF MEXICO

    201     30,000   Tension-leg     3,000  

GULF OF MEXICO

    202     30,000   Tension-leg     3,000  

GULF OF MEXICO

    204     30,000   Tension-leg     3,000  

*
Rig moved to Argentina in the first quarter of fiscal 2015

        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,  
 
  2010   2011   2012   2013   2014  

U.S. Land Rigs

                               

Number of rigs at end of period

    220     248     282     302     329  

Average rig utilization rate during period (1)

    73 %   86 %   89 %   82 %   86 %

U.S. Offshore Platform Rigs

   
 
   
 
   
 
   
 
   
 
 

Number of rigs at end of period

    9     9     9     9     9  

Average rig utilization rate during period (1)

    80 %   77 %   79 %   89 %   89 %

(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, 2014:

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

Argentina

    230     22,000   AC (FlexRig3)     1,500  

Argentina

    234     22,000   AC (FlexRig3)     1,500  

Argentina

    335     8,000   AC (FlexRig4)     1,150  

Argentina

    336     8,000   AC (FlexRig4)     1,150  

Argentina

    337     8,000   AC (FlexRig4)     1,150  

Argentina

    338     8,000   AC (FlexRig4)     1,150  

Argentina

    123     26,000   SCR     2,100  

Argentina

    175     30,000   SCR     3,000  

Argentina

    177     30,000   SCR     3,000  

Argentina

    151     30,000+   SCR     3,000  

Argentina

    213     22,000   AC (FlexRig3)     1,500  

Argentina

    217     22,000   AC (FlexRig3)     1,500  

Argentina

    219     22,000   AC (FlexRig3)     1,500  

Argentina

    229     22,000   AC (FlexRig3)     1,500  

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

    237     18,000   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

    133     30,000   SCR     3,000  

Colombia#

    139     30,000+   SCR     3,000  

Colombia

    152     30,000+   SCR     3,000  

Colombia

    900     30,000+   AC Drive     3,000  

Ecuador

    132     18,000   SCR     1,500  

Ecuador

    176     18,000   SCR     1,500  

Ecuador

    121     20,000   SCR     1,700  

Ecuador

    190     26,000   SCR     2,000  

Ecuador

    117     26,000   SCR     2,500  

Ecuador

    138     26,000   SCR     2,500  

Mozambique

    243     22,000   AC (FlexRig3)     1,500  

Tunisia

    228     22,000   AC (FlexRig3)     1,500  

Tunisia

    242     22,000   AC (FlexRig3)     1,500  

UAE

    476     22,000   AC (FlexRig3)     1,500  

UAE

    484     22,000   AC (FlexRig3)     1,500  

#
Rig moved to U.S. Land in the first quarter of fiscal 2015.

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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,  
 
  2010   2011   2012   2013   2014  

Number of rigs at end of period

    28     24     29     29     36  

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

    71 %   70 %   77 %   82 %   76 %

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

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

STOCK PORTFOLIO

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

Item 3.    LEGAL PROCEEDINGS

    1.
    Investigation by the Department of the Interior.

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

    2.
    Venezuela Expropriation.

        Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A. filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. ("PDVSA") and PDVSA Petroleo, S.A. ("Petroleo"). We are seeking damages for the taking of our Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery.

Item 4.    MINE SAFETY DISCLOSURES

        Not applicable.

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OUR EXECUTIVE OFFICERS

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

John W. Lindsay, 53   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

Steven R. Mackey, 63

 

Executive Vice President, General Counsel and Chief Administrative Officer since June 2014; Executive Vice President, Secretary, General Counsel and Chief Administrative Officer from March 2010 to June 2014; Executive Vice President, Secretary and General Counsel from June 2008 to March 2010; Secretary from 1990 to June 2014; Vice President from 1988 to 2010; General Counsel since 1988

Juan Pablo Tardio, 49

 

Vice President and Chief Financial Officer since April 2010; Director of Investor Relations from January 2008 to April 2010; Manager of Investor Relations from August 2005 to January 2008

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PART II

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

    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 14, 2014, there were 617 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:

 
  2013   2014  
Quarter
  High   Low   High   Low  

First

  $ 57.19   $ 44.95   $ 84.87   $ 68.87  

Second

    69.38     55.79     108.43     81.34  

Third

    66.02     55.78     118.02     103.54  

Fourth

    71.36     62.35     118.95     96.79  

    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
  2013   2014   2013   2014  

First

  $ .0700   $ .5000   $ 7,430,942   $ 53,859,536  

Second

    .1500     .6250     16,038,413     67,685,672  

Third

    .1500     .6250     16,049,768     67,996,052  

Fourth

    .5000     .6875     53,534,259     74,844,562  

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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
Sep09
 
Company / Index
  Sep10   Sep11   Sep12   Sep13   Sep14  

Helmerich & Payne, Inc. 

    100     102.92     103.73     122.31     179.61     261.40  

S&P 500 Index

    100     110.16     111.42     145.08     173.14     207.30  

S&P 500 Oil & Gas Drilling Index

    100     91.14     81.05     97.25     107.69     94.57  

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

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Item 6.    SELECTED FINANCIAL DATA

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


Five-year Summary of Selected Financial Data

 
  2014   2013   2012   2011   2010  
 
  (in thousands except per share amounts)
 

Operating revenues

  $ 3,719,707   $ 3,387,614   $ 3,151,802   $ 2,543,894   $ 1,875,162  

Income from continuing operations

    708,766     721,453     573,609     434,668     286,081  

Income (loss) from discontinued operations

    (47 )   15,186     7,436     (482 )   (129,769 )

Net Income

    708,719     736,639     581,045     434,186     156,312  

Basic earnings per share from continuing operations

    6.54     6.75     5.35     4.06     2.70  

Basic earnings (loss) per share from discontinued operations

        0.14     0.07         (1.23 )

Basic earnings per share

    6.54     6.89     5.42     4.06     1.47  

Diluted earnings per share from continuing operations

    6.46     6.65     5.27     3.99     2.66  

Diluted earnings (loss) per share from discontinued operations

        0.14     0.07         (1.21 )

Diluted earnings per share

    6.46     6.79     5.34     3.99     1.45  

Total assets*

    6,721,861     6,264,827     5,721,085     5,003,891     4,265,370  

Long-term debt

    40,000     80,000     195,000     235,000     360,000  

Cash dividends declared per common share

    2.625     1.300     0.280     0.260     0.220  

*
Total assets for all years include amounts related to discontinued operations. As further discussed in Note 2—"Discontinued Operations" included in Item 8—"Financial Statements and Supplementary Data" of this Form 10-K, 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.

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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 374 drilling rigs at September 30, 2014. Our contract drilling segments consist of the U.S. Land segment with 329 rigs, the Offshore segment with 9 offshore platform rigs and the International Land segment with 36 rigs at September 30, 2014. We continued to expand our rig fleet in 2014 and our flexibility in managing our own rate of production has allowed us to quickly respond to changing levels of FlexRig demand. Our position in the market is strengthened by our high quality fleet, our long-term contracts and our customer base. The market demand for AC drive rigs continued to increase during the year. During 2014, we placed into service 44 new FlexRigs and one new AC drive rig, all with fixed-term contracts. At September 30, 2014, we had 325 active rigs, compared to 276 active rigs at the same time during the prior year.

        In addition, our customers continue to focus on efficiency, technology and safety. We believe that our superior field performance and safety record will allow us to continue to gain market share over the coming years.

        As further discussed in Note 2 of the Consolidated Financial Statements, our Venezuelan subsidiary was classified as discontinued operations on June 30, 2010, after the seizure of our drilling assets in that country by the Venezuelan government. Except as specifically discussed, the following results of operations pertain only to our continuing operations. Unless otherwise indicated, references to 2014, 2013 and 2012 in the following discussion are referring to our fiscal 2014, 2013 and 2012.

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Results of Operations

        All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net income for 2014 was $708.7 million ($6.46 per share), compared with $736.6 million ($6.79 per share) for 2013 and $581.0 million ($5.34 per share) for 2012. Included in our net income is after-tax gains from the sale of investment securities of $27.8 million ($0.25 per share) in 2014 and $97.9 million ($0.91 per share) in 2013. Net income also includes after-tax gains from the sale of assets of $12.7 million ($0.12 per share) in 2014, $12.2 million ($0.11 per share) in 2013 and $12.3 million ($0.11 per share) in 2012.

        Consolidated operating revenues were $3.7 billion in 2014, $3.4 billion in 2013 and $3.2 billion in 2012. Our total number of revenue days (drilling activity) also increased to record levels during 2014. The number of revenue days in our U.S. Land segment totaled 100,638 in 2014, compared to 88,620 in 2013 and 86,340 in 2012. Our U.S. land rig utilization was 86 percent in 2014, 82 percent in 2013 and 89 percent in 2012. The average number of U.S. land rigs available was 319 rigs in 2014, 295 rigs in 2013 and 266 rigs in 2012. Revenue in the Offshore segment steadily increased in 2014 and 2013 from 2012, while rig utilization for offshore rigs was 89 percent in 2014 and 2013, compared to 79 percent in 2012. Revenue and rig utilization in the International Land segment decreased in 2014 from 2013 after increasing in 2013 from 2012. Rig utilization in our International Land segment was 76 percent in 2014, 82 percent in 2013 and 77 percent in 2012.

        In 2014 and 2013, we had $45.2 million and $162.1 million in gains from the sale of investment securities, respectively. We did not sell any investment securities in 2012. Interest and dividend income was $1.6 million, $1.7 million and $1.4 million in 2014, 2013 and 2012, respectively.

        Direct operating costs in 2014 were $2.0 billion or 54 percent of operating revenues, compared with $1.9 billion or 55 percent of operating revenues in 2013 and $1.8 billion or 56 percent of operating revenues in 2012.

        Depreciation expense was $523.5 million in 2014, $455.6 million in 2013 and $387.5 million in 2012. Included in depreciation are abandonments of equipment of $23.0 million in 2014, $9.1 million in 2013 and $16.4 million in 2012. Depreciation expense, exclusive of the abandonments, increased over the three-year period as we placed into service 45 new rigs in 2014, 20 in 2013 and 48 in 2012. Depreciation expense in 2015 is expected to increase from 2014 from new rigs placed into service during 2014 and additional rigs placed into service during 2015. (See Liquidity and Capital Resources.)

        As conditions warrant, management performs an analysis of the industry market conditions impacting its long-lived assets in each drilling segment. Based on this analysis, management determines if any impairment is required. In 2014, 2013 and 2012, no impairment was recorded.

        General and administrative expenses totaled $135.1 million in 2014, $126.3 million in 2013 and $107.3 million in 2012. The $8.8 million increase in 2014 from 2013 is primarily due to continued growth in the number of employees in the comparative periods and increases in salaries, bonuses, and stock-based compensation. The $19.0 million increase in 2013 from 2012 was due to increases in stock-based compensation of approximately $17.3 million associated with growth in the number of employees and increases in wages in the comparative periods.

        Interest expense net of amounts capitalized totaled $4.7 million in 2014, $6.1 million in 2013 and $8.7 million in 2012. Interest expense is primarily attributable to the fixed-rate debt outstanding. Interest expense decreased in 2014 from 2013 and in 2013 from 2012 primarily due to a reduction in outstanding debt balances during the three years. Capitalized interest was $7.7 million, $8.8 million and $12.9 million in 2014, 2013 and 2012, respectively. All of the capitalized interest is attributable to our rig construction program.

        The provision for income taxes totaled $387.5 million in 2014, $392.8 million in 2013 and $329.0 million in 2012. The effective income tax rate was 35.4 percent in 2014 compared to

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35.3 percent in 2013 and 36.4 percent in 2012. 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 2014, 2013 and 2012, we incurred $15.9 million, $15.2 million and $16.1 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 2015.

        Expenses incurred within the country of Venezuela are reported as discontinued operations. Included in 2013 and 2012 are proceeds from arbitration disputes with third parties not affiliated with the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. ("PDVSA") or PDVSA Petroleo, S.A. ("Petroleo") related to the seizure of our property in Venezuela on June 30, 2010. Proceeds of $15.0 million and $7.5 million were received and recorded as discontinued operations in 2013 and 2012, respectively.

        Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Venezuelan government, PDVSA and Petroleo. Our subsidiaries seek damages for the taking of their Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No gain contingencies are recognized in our Consolidated Financial Statements.

        The following tables summarize operations by reportable operating segment.

Comparison of the years ended September 30, 2014 and 2013

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

U.S. LAND OPERATIONS

                   

Operating revenues

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

Direct operating expenses

    1,576,702     1,424,716     10.7  

General and administrative expense

    41,573     37,070     12.1  

Depreciation

    455,934     391,072     16.6  
                 

Segment operating income

  $ 1,025,745   $ 932,591     10.0  
                 
                 

Operating Statistics:

                   

Revenue days

    100,638     88,620     13.6 %

Average rig revenue per day

  $ 28,194   $ 28,382     (0.7 )

Average rig expense per day

  $ 13,058   $ 13,029     0.2  

Average rig margin per day

  $ 15,136   $ 15,353     (1.4 )

Number of rigs at end of period

    329     302     8.9  

Rig utilization

    86 %   82 %   4.9  

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

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

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        Operating income in the U.S. Land segment increased to $1.0 billion in 2014 from $932.6 million in 2013 primarily due to an increase in revenue days. Included in U.S. land revenues for 2014 and 2013 is approximately $11.7 million and $19.0 million, respectively, from early termination and revenue from customers that requested delivery delays for new FlexRigs. Excluding early termination related revenue and customer requested delivery delay revenue for new FlexRigs, the average revenue per day for 2014 only slightly decreased by $90 to $28,080 from $28,168 in 2013. Direct operating expenses as a percentage of revenue were 51 percent in 2014 and 51 percent in 2013.

        Rig utilization increased to 86 percent in 2014 from 82 percent in 2013. The total number of rigs at September 30, 2014 was 329 compared to 302 rigs at September 30, 2013. The net increase is due to 42 new FlexRigs completed and placed into service, 6 FlexRigs transferred to the International Land segment and 9 older conventional rigs removed from service. Subsequent to September 30, 2014 two FlexRigs were transferred to the International Land segment and three additional FlexRigs are expected to be transferred during 2015.

        Subsequent to September 30, 2014, we announced we had entered into agreements with two customers to build and operate six new FlexRigs. As of November 13, 2014, 41 announced FlexRigs remained to be delivered.

        Depreciation includes charges for abandoned equipment of $21.5 million and $8.2 million in 2014 and 2013, respectively. Included in abandonments in 2014 is the decommission of nine conventional rigs and spare equipment for drilling rigs. Included in abandonments in 2013 is the decommission of two conventional rigs. Excluding the abandonment amounts, depreciation in 2014 increased 13 percent from 2013 due to the increase in available rigs. As a result of the new FlexRigs added in fiscal 2014 and additional rigs scheduled for completion in fiscal 2015, we anticipate depreciation expense to continue to increase in fiscal 2015.

        At September 30, 2014, 294 out of 329 existing rigs in the U.S. Land segment were generating revenue. Of the 294 rigs generating revenue, 176 were under fixed-term contracts, and 118 were working in the spot market. At November 13, 2014, the number of existing rigs under fixed-term contracts in the segment was 179 and the number of rigs working in the spot market increased to 119.

Comparison of the years ended September 30, 2014 and 2013

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

OFFSHORE OPERATIONS

                   

Operating revenues

  $ 250,811   $ 221,863     13.0 %

Direct operating expenses

    158,834     146,184     8.7  

General and administrative expense

    9,858     8,849     11.4  

Depreciation

    12,300     13,766     (10.6 )
                 

Segment operating income

  $ 69,819   $ 53,064     31.6  
                 
                 

Operating Statistics:

                   

Revenue days

    2,920     2,920     %

Average rig revenue per day

  $ 63,094   $ 61,069     3.3  

Average rig expense per day

  $ 37,653   $ 37,654      

Average rig margin per day

  $ 25,441   $ 23,415     8.7  

Number of rigs at end of period

    9     9      

Rig utilization

    89 %   89 %    

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

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        Total revenue and segment operating income in our Offshore segment increased in 2014 from 2013 primarily due to our offshore management contracts. Included in 2013 direct operating expenses is a one-time charge of $6.4 million related to an incident in the Gulf of Mexico more fully discussed in Note 13 to the Consolidated Financial Statements. At September 30, 2014 and 2013, eight of our nine rigs were working. The ninth rig commenced operations during the first fiscal quarter of 2015.

Comparison of the years ended September 30, 2014 and 2013

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

INTERNATIONAL LAND OPERATIONS

                   

Operating revenues

  $ 355,532   $ 366,841     (3.1 )%

Direct operating expenses

    274,894     282,335     (2.6 )

General and administrative expense

    4,289     3,911     9.7  

Depreciation

    39,932     36,000     10.9  
                 

Segment operating income

  $ 36,417   $ 44,595     (18.3 )
                 
                 

Operating Statistics:

                   

Revenue days

    8,303     8,707     (4.6 )%

Average rig revenue per day

  $ 37,117   $ 37,246     (0.3 )

Average rig expense per day

  $ 27,278   $ 27,589     (1.1 )

Average rig margin per day

  $ 9,839   $ 9,657     1.9  

Number of rigs at end of period

    36     29     24.1  

Rig utilization

    76 %   82 %   (7.3 )

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

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

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

        During 2014, the total number of rigs increased by seven due to one new 3,000 horsepower AC drive rig added to the fleet and six FlexRigs transferred from the U.S. Land segment. As of November 13, 2014, an additional two rigs were transferred from the U.S. Land segment with another three expected to transfer during 2015. All of the additional rigs added to the segment in 2014 through November 13, 2014 and those expected to be added in 2015 are under fixed-term contracts.

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Comparison of the years ended September 30, 2013 and 2012

 
  2013   2012   % Change  
 
  (in thousands, except operating statistics)
 

U.S. LAND OPERATIONS

                   

Operating revenues

  $ 2,785,449   $ 2,678,475     4.0 %

Direct operating expenses

    1,424,716     1,407,986     1.2  

General and administrative expense

    37,070     30,798     20.4  

Depreciation

    391,072     332,723     17.5  
                 

Segment operating income

  $ 932,591   $ 906,968     2.8  
                 
                 

Operating Statistics:

                   

Revenue days

    88,620     86,340     2.6 %

Average rig revenue per day

  $ 28,382   $ 27,737     2.3  

Average rig expense per day

  $ 13,029   $ 13,022     0.1  

Average rig margin per day

  $ 15,353   $ 14,715     4.3  

Number of rigs at end of period

    302     282     7.1  

Rig utilization

    82 %   89 %   (7.9 )

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $270,223 and $283,640 for 2013 and 2012, respectively.

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

        Operating income in the U.S. Land segment increased to $932.6 million in 2013 from $907.0 million in 2012. Included in U.S. land revenues for 2013 is approximately $19.0 million from early termination and revenue from customers that requested delivery delays for new FlexRigs. Included in U.S. land revenues for 2012 is approximately $10.1 million from early termination revenue. Excluding early termination related revenue and customer requested delivery delay revenue for new FlexRigs, the average revenue per day for 2013 increased by $548 to $28,168 from $27,620 in 2012, primarily attributable to increases in dayrates early in 2012, which then stabilized and only slightly declined in 2013.

        Direct operating expenses as a percentage of revenue were 51 percent in 2013 and 53 percent in 2012.

        Rig utilization decreased to 82 percent in 2013 from 89 percent in 2012. The total number of rigs at September 30, 2013 was 302 compared to 282 rigs at September 30, 2012. The net increase is due to 20 new FlexRigs completed and placed into service, two new FlexRigs completed and ready for delivery and two older conventional rigs removed from service.

        Depreciation includes charges for abandoned equipment of $8.2 million and $15.9 million in 2013 and 2012, respectively. Included in abandonments is the removal of two conventional rigs in 2013 and seven mechanical highly mobile rigs in 2012. Excluding the abandonment amounts, depreciation in 2013 increased 21 percent from 2012 due to the increase in available rigs.

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Comparison of the years ended September 30, 2013 and 2012

 
  2013   2012   % Change  
 
  (in thousands, except operating statistics)
 

OFFSHORE OPERATIONS

                   

Operating revenues

  $ 221,863   $ 189,086     17.3 %

Direct operating expenses

    146,184     126,470     15.6  

General and administrative expense

    8,849     7,386     19.8  

Depreciation

    13,766     13,455     2.3  
                 

Segment operating income

  $ 53,064   $ 41,775     27.0  
                 
                 

Operating Statistics:

                   

Revenue days

    2,920     2,625     11.2 %

Average rig revenue per day

  $ 61,069   $ 53,927     13.2  

Average rig expense per day

  $ 37,654   $ 33,051     13.9  

Average rig margin per day

  $ 23,415   $ 20,876     12.2  

Number of rigs at end of period

    9     9      

Rig utilization

    89 %   79 %   12.7  

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $19,701 and $18,346 for 2013 and 2012, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.

        Segment operating income in our Offshore segment increased by 27.0 percent in 2013 from 2012 primarily due to an increase in revenue days and an increase in dayrates reduced by a one-time charge of $6.4 million related to an incident in the Gulf of Mexico more fully discussed in Note 13 to the Consolidated Financial Statements. The increase in revenue days is primarily due to two rigs working all of 2013 compared to working only a portion of 2012, offset partially by a third rig completing its contract in 2012 and being idle during 2013.

Comparison of the years ended September 30, 2013 and 2012

 
  2013   2012   % Change  
 
  (in thousands, except operating statistics)
 

INTERNATIONAL LAND OPERATIONS

                   

Operating revenues

  $ 366,841   $ 270,027     35.9 %

Direct operating expenses

    282,335     215,642     30.9  

General and administrative expense

    3,911     3,318     17.9  

Depreciation

    36,000     30,701     17.3  
                 

Segment operating income

  $ 44,595   $ 20,366     119.0  
                 
                 

Operating Statistics:

                   

Revenue days

    8,707     7,343     18.6 %

Average rig revenue per day

  $ 37,246   $ 32,998     12.9  

Average rig expense per day

  $ 27,589   $ 25,524     8.1  

Average rig margin per day

  $ 9,657   $ 7,474     29.2  

Number of rigs at end of period

    29     29      

Rig utilization

    82 %   77 %   6.5  

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $42,542 and $27,720 for 2013 and 2012, respectively. Also excluded are the effects of currency revaluation expense.

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        The International Land segment had operating income of $44.6 million for 2013 compared to $20.4 million for 2012. Included in International land revenues in 2013 is approximately $5.3 million related to early termination fees.

        Revenues increased by $96.8 million in 2013 from 2012 in international land operations and rig utilization increased to 82 percent in 2013 compared to 77 percent in 2012. The total number of rigs remained constant at 29. The average revenue per day for 2013 compared to 2012 increased $4,248 of which $609 is attributable to early termination related revenue. The remaining increase is primarily due to higher dayrates.

LIQUIDITY AND CAPITAL RESOURCES

        Our capital spending was $952.9 million in 2014, $809.1 million in 2013 and $1.1 billion in 2012. Net cash provided from operating activities was $1.1 billion in 2014, $997.2 million in 2013 and $1.0 billion in 2012. Our 2015 capital spending is currently estimated to be between $1.4 billion and $1.7 billion, depending primarily on drilling market conditions and incremental demand for additional new FlexRigs during the fiscal year. This estimate includes contracted new builds, capital maintenance requirements, tubulars and other special projects.

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

        We manage a portfolio of marketable securities that, at the close of fiscal 2014, had a fair value of $222.3 million consisting 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 2014, we had cash proceeds from the sale of available-for-sale securities of $49.2 million. During 2013, we had cash proceeds from the sale of investment securities of $232.2 million including $214.1 from the sale of marketable equity available-for-sale securities and $18.1 million from the sale of three limited partnerships. We did not sell any portfolio securities in 2012.

        Our proceeds from asset sales totaled $30.8 million in 2014, $28.0 million in 2013 and $39.9 million in 2012. Income from asset sales in 2014 totaled $19.6 million, $18.9 million in 2013 and $19.2 million in 2012. 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 fiscal 2012, we purchased 1,747,819 common shares at an aggregate cost of $77.6 million, which are held as treasury shares. We had no purchases of common shares in fiscal 2014 and 2013. Subsequent to September 30, 2014, we purchased 414,992 common shares at an aggregate cost of $32.3 million, which will be held as treasury shares.

        During 2014, we increased our dividends paid in both the second fiscal quarter and the fourth fiscal quarter, representing the 42nd consecutive year of dividend increases. We paid dividends of $2.438 per share, or a total of $264.4 million during 2014 compared to $0.87 per share or $93.1 million paid in 2013 and $0.28 per share or $30.0 million paid in 2012.

        We have $80 million of senior unsecured fixed-rate notes outstanding at September 30, 2014 that mature over a period from July 2015 to July 2016. Interest on the notes is paid semi-annually based on an annual rate of 6.10 percent. Annual principal repayments of $40 million are due July 2015 and July 2016. We have complied with our financial covenants which require us to maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00.

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        We have a $300 million unsecured revolving credit facility that will mature May 25, 2017. The credit facility has $100 million available to use for letters of credit. The majority of borrowings under the facility would accrue interest at a spread over the London Interbank Offered Rate (LIBOR). We also pay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined according to a scale based on a ratio of our total debt to total capitalization. The spread over LIBOR ranges from 1.125 percent to 1.75 percent per annum and commitment fees range from .15 percent to .35 percent per annum. Based on our debt to total capitalization on September 30, 2014, the spread over LIBOR and commitment fees would be 1.125 percent and .15 percent, respectively. Financial covenants in the facility require us to maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. The credit facility contains additional terms, conditions, restrictions, and covenants that we believe are usual and customary in unsecured debt arrangements for companies of similar size and credit quality. As of September 30, 2014, there were no borrowings, but there were three letters of credit outstanding in the amount of $34.2 million. At September 30, 2014, we had $265.8 million available to borrow under our $300 million unsecured credit facility.

        At September 30, 2014, we had two letters of credit outstanding, totaling $12 million that were issued to support international operations. These letters of credit were issued separately from the $300 million credit facility so they do not reduce the available borrowing capacity discussed in the previous paragraph.

        The applicable agreements for all of the unsecured debt described above contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2014, we were in compliance with all debt covenants.

        At September 30, 2014, we had 193 existing rigs with fixed term contracts with original term durations ranging from six months to seven years, with some expiring in fiscal 2015. The contracts provide for termination at the election of the customer, with an early termination payment to be paid if a contract is terminated prior to the expiration of the fixed term. While most of our customers are primarily major oil companies and large independent oil companies, a risk exists that a customer, especially a smaller independent oil company, may become unable to meet its obligations and may exercise its early termination election in the future and not be able to pay the early termination fee. Although not expected at this time, our future revenue and operating results could be negatively impacted if this were to happen.

        Our operating cash requirements, scheduled debt repayments, any stock repurchases and estimated capital expenditures, including our rig construction program, for fiscal 2015 are expected to be funded through current cash, cash to be provided from operating activities and, possibly, from additional borrowings and sales of available-for-sale securities.

        The current ratio was 2.5 at September 30, 2014 and 2.8 at September 30, 2013. The long-term debt to total capitalization ratio, including the current portion of long-term debt, was two percent at September 30, 2014 compared to four percent at September 30, 2013.

STOCK PORTFOLIO HELD

September 30, 2014
  Number of Shares   Cost Basis   Market Value  
 
  (in thousands, except share amounts)
 

Atwood Oceanics, Inc. 

    4,000,000   $ 60,749   $ 174,760  

Schlumberger, Ltd. 

    467,500     3,713     47,540  
                 

Total

        $ 64,462   $ 222,300  
                 
                 

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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, 2014, are summarized in the table below in thousands:

 
  Payments due by year  
Contractual Obligations
  Total   2015   2016   2017   2018   2019   After
2019
 

Long-term debt and estimated interest (a)

  $ 86,371   $ 44,406   $ 41,965   $   $   $   $  

Operating leases (b)

    38,476     7,658     5,165     4,489     3,220     3,213     14,731  

Purchase obligations (b)

    412,949     412,949                      
                               

Total contractual obligations

  $ 537,796   $ 465,013   $ 47,130   $ 4,489   $ 3,220   $ 3,213   $ 14,731  
                               
                               

(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 2014, we contributed $7.3 million to the pension plan. Based on current information available from plan actuaries, we estimate contributing at least $0.1 million in 2015 to meet the minimum contribution required by law. Additional contributions may be made in 2015 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond 2015 are difficult to estimate due to multiple variables involved.

        At September 30, 2014, we had $17.2 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. 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

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retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.

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

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

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

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        Pension Costs and Obligations    Our pension benefit costs and obligations are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan assets. Our discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was lowered to 4.32 percent from 4.80 percent as of September 30, 2014 to reflect changes in the market conditions for high-quality fixed-income investments. The expected return on plan assets is determined based on historical portfolio results and future expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated from future periods. We anticipate pension expense to decrease approximately $1.3 million in 2015 from 2014.

        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, 2014, unrecognized compensation cost related to unvested restricted stock was $20.0 million. The cost is expected to be recognized over a weighted-average period of 2.3 years.

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

NEW ACCOUNTING STANDARDS

        On October 1, 2013, we adopted Accounting Standards Update ("ASU") 2013-02, Other Comprehensive Income. ASU No. 2013-02 amended Accounting standards Codifications ("ASC") 220, Comprehensive Income, and superseded and replaced ASU 2011-05, Presentation of Comprehensive Income, and ASU 2011-12, Comprehensive Income. The standard did not change the current requirements for reporting net income or other comprehensive income in financial statements. However, the guidance does require an entity to provide enhanced disclosures to present separately by component reclassifications out of accumulated other comprehensive income. The adoption had no impact on the amount of other comprehensive income reported in the Consolidated Financial Statements.

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        In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes virtually all existing revenue recognition guidance. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. This update also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. The provisions of ASU 2014-09 are effective for interim and annual periods beginning after December 15, 2016, and we have the option of using either a full retrospective or a modified retrospective approach when adopting this new standard. We are currently evaluating the alternative transition methods and the potential effects of the adoption of this update on our financial statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Foreign Currency Exchange Rate Risk    Our contracts for work in foreign countries generally provide for payment in U.S. dollars. However, in Argentina we are paid in Argentine pesos. The Argentine branch of one of our second-tier subsidiaries 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. Based upon current information, we believe that our exposure to potential losses from currency restrictions and devaluation in foreign countries is immaterial. However, 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 the event of future payments in foreign currencies and an inability to timely exchange foreign currencies for U.S. dollars, we may incur currency devaluation losses which could have a material adverse impact on our business, financial condition and results of operations.

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

        Commodity Price Risk    The demand for contract drilling services is 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 supply and demand, worldwide economic conditions and geopolitical factors. Crude oil and natural gas prices have historically been volatile and very difficult to predict. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining future spending levels. This volatility can lead many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices.

        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

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for drilling services which could have a material adverse effect on our business, financial condition and results of operations.

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

        Interest Rate Risk    Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our commercial banks. Because all of our debt at September 30, 2014 has fixed-rate interest obligations, there is no current risk due to interest rate fluctuation.

        The following tables provide information as of September 30, 2014 and 2013 about our interest rate risk sensitive instruments:

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

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

Fixed-Rate Debt

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

Average Interest Rate

    6.1 %   6.1 %   %   %   %   %   6.1 %      

Variable Rate Debt

  $   $   $   $   $   $   $   $  

Average Interest Rate

                                                 

INTEREST RATE RISK AS OF SEPTEMBER 30, 2013 (dollars in thousands)

 
  2014   2015   2016   2017   2018   After
2018
  Total   Fair Value
9/30/13
 

Fixed-Rate Debt

  $ 115,000   $ 40,000   $ 40,000   $   $   $   $ 195,000   $ 205,386  

Average Interest Rate

    6.5 %   6.1 %   6.1 %   %   %   %   6.3 %      

Variable Rate Debt

  $   $   $   $   $   $   $   $  

Average Interest Rate

                                                 

        Equity Price Risk    On September 30, 2014, we had a portfolio of securities with a total fair value of $222.3 million. The total fair value of the portfolio of securities was $305.6 million at September 30, 2013. We make no specific plans to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the fair value of our holdings. The portfolio is recorded at fair value on the balance sheet with changes in unrealized after-tax value reflected in the equity section of the balance sheet. At November 13, 2014, the total fair value of the remaining securities had decreased to approximately $184.8 million. Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements.

Item 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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Item 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

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

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

        We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2014 and 2013, and the related consolidated statements of income, comprehensive income, shareholders' equity and cash flows for each of the three years in the period ended September 30, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helmerich & Payne, Inc. at September 30, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2014, in conformity with U.S. generally accepted accounting principles.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helmerich & Payne, Inc.'s internal control over financial reporting as of September 30, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated November 26, 2014 expressed an unqualified opinion thereon.

    /s/Ernst & Young LLP

Tulsa, Oklahoma
November 26, 2014

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Consolidated Statements of Income

HELMERICH & PAYNE, INC.

 
  Years Ended September 30,  
 
  2014   2013   2012  
 
  (in thousands, except per share amounts)
 

Operating revenues

                   

Drilling—U.S. Land

  $ 3,099,954   $ 2,785,449   $ 2,678,475  

Drilling—Offshore

    250,811     221,863     189,086  

Drilling—International Land

    355,532     366,841     270,027  

Other

    13,410     13,461     14,214  
               

    3,719,707     3,387,614     3,151,802  
               

Operating costs and expenses

                   

Operating costs, excluding depreciation

    2,009,912     1,852,768     1,750,510  

Depreciation

    523,549     455,623     387,549  

Research and development

    15,905     15,235     16,060  

General and administrative

    135,139     126,250     107,307  

Income from asset sales

    (19,585 )   (18,923 )   (19,223 )
               

    2,664,920     2,430,953     2,242,203  
               

Operating income from continuing operations

    1,054,787     956,661     909,599  

Other income (expense)

                   

Interest and dividend income

    1,583     1,653     1,380  

Interest expense

    (4,654 )   (6,129 )   (8,653 )

Gain on sale of investment securities

    45,234     162,121      

Other

    (636 )   (9 )   254  
               

    41,527     157,636     (7,019 )
               

Income from continuing operations before income taxes

    1,096,314     1,114,297     902,580  

Income tax provision

    387,548     392,844     328,971  
               

Income from continuing operations

    708,766     721,453     573,609  

Income from discontinued operations before income taxes

    2,758     14,701     7,355  

Income tax provision (benefit)

    2,805     (485 )   (81 )
               

Income (loss) from discontinued operations

    (47 )   15,186     7,436  
               

NET INCOME

  $ 708,719   $ 736,639   $ 581,045