10-K 1 hp-20170930x10k.htm 10-K hp_Current_Folio_10K

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

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

For the fiscal year ended September 30, 2017

 

OR

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

For the transition period from              to            

 

Commission file number 1‑4221

 

HELMERICH & PAYNE, INC.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)

73‑0679879
(I.R.S. Employer Identification No.)

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

74119‑3623
(Zip Code)

(918) 742‑5531
Registrant’s telephone number, including area code

 

 

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

 

 

 

 

Title of Each Class

    

Name of Each Exchange on Which Registered

Common Stock ($0.10 par value)

 

New York Stock Exchange

 

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

 

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

 

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 ☐  No ☒

 

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 ☒  No ☐

 

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 ☒  No ☐

 

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. ☒

 

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

 

Large accelerated filer ☒

Smaller reporting company ☐

Accelerated filer ☐

Emerging Growth Company ☐

 

Non‑accelerated filer ☐
(Do not check if a smaller reporting company)         

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

 

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

 

At March 31, 2017, the aggregate market value of the voting stock held by non‑affiliates was approximately $7.03 billion.

 

Number of shares of common stock outstanding at November 10, 2017:    108,605,547

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s 2018 Proxy Statement for the Annual Meeting of Stockholders to be held on March 7, 2018 are incorporated by reference into Part III of this Form 10‑K. The 2018 Proxy Statement will be filed with the U.S. Securities and Exchange Commission (“SEC”) within 120 days after the end of the fiscal year to which this Form 10‑K relates.

 

 


 

DISCLOSURE REGARDING FORWARD‑LOOKING STATEMENTS

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

 


 

HELMERICH & PAYNE, INC.

FORM 10‑K

YEAR ENDED SEPTEMBER 30, 2017

TABLE OF CONTENTS

 

    

 

    

Page

 

 

PART I

 

 

Item 1. 

 

Business

 

1

Item 1A. 

 

Risk Factors

 

6

Item 1B. 

 

Unresolved Staff Comments

 

17

Item 2. 

 

Properties

 

18

Item 3. 

 

Legal Proceedings

 

26

Item 4. 

 

Mine Safety Disclosures

 

26

 

 

Executive Officers of the Company

 

27

 

 

PART II

 

 

Item 5. 

 

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

 

28

Item 6. 

 

Selected Financial Data

 

30

Item 7. 

 

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

 

31

Item 7A. 

 

Quantitative and Qualitative Disclosures About Market Risk

 

45

Item 8. 

 

Financial Statements and Supplementary Data

 

46

Item 9. 

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

94

Item 9A. 

 

Controls and Procedures

 

94

Item 9B. 

 

Other Information

 

97

 

 

PART III

 

 

Item 10. 

 

Directors, Executive Officers and Corporate Governance

 

97

Item 11. 

 

Executive Compensation

 

97

Item 12. 

 

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

 

97

Item 13. 

 

Certain Relationships and Related Transactions, and Director Independence

 

97

Item 14. 

 

Principal Accountant Fees and Services

 

97

 

 

PART IV

 

 

Item 15. 

 

Exhibits and Financial Statement Schedules

 

98

Item 16. 

 

Form 10‑K Summary

 

102

SIGNATURES 

 

104

 

 

 

 

 


 

PART I

Item 1.  BUSINESS

Helmerich & Payne, Inc. (which together with its subsidiaries is identified as the “Company”, “we”, “us” or “our,” except where stated or the context requires otherwise), was incorporated under the laws of the State of Delaware on February 3, 1940, and is successor to a business originally organized in 1920. We are primarily engaged in contract drilling of oil and gas wells for oil and gas exploration and production companies 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 2017, our U.S. Land operations drilled primarily in Colorado, Louisiana, Ohio, Oklahoma, New Mexico, North Dakota, Pennsylvania, Texas, Utah, West Virginia and Wyoming. Offshore operations were conducted in the Gulf of Mexico. Our International Land segment conducted drilling operations in four international locations during fiscal 2017: Argentina, Bahrain, Colombia and United Arab Emirates (“UAE”).

We are also engaged in the ownership, development and operation of commercial real estate and the research, development and lease for use in the oil and gas drilling industry of rotary steerable technology. Our real estate investments located exclusively within Tulsa, Oklahoma, include a shopping center containing approximately 441,000 leasable square feet, multi‑tenant industrial warehouse properties containing approximately one million leasable square feet and approximately 210 acres of undeveloped real estate. Since 2008, our subsidiary, TerraVici Drilling Solutions, Inc., has pursued the development of patented rotary steerable technology as a means to enhance our horizontal and directional drilling services. We expect to continue research and development of this and other technology in 2018. In addition, in June of 2017, we acquired MOTIVE Drilling Technologies, Inc. (“MOTIVE”).  MOTIVE has a proprietary Bit Guidance System that is an algorithm-driven system that considers the total economic consequences of directional drilling decisions and has proven to consistently lower drilling costs through more efficient drilling and increase hydrocarbon production through smoother wellbores and more accurate well placement.  We intend to utilize and continue to advance this technology to provide benefits for the drilling industry.  Each of the businesses operates independently of the others through wholly‑owned subsidiaries. This operating decentralization is balanced by centralized finance, legal, human resources and information technology organizations.

CONTRACT DRILLING

General

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

In fiscal 2017, we received approximately 55 percent of our consolidated operating revenues from our ten largest contract drilling customers. EOG Resources, Inc., Continental Resources and Occidental Oil and Gas Corporation (respectively, “EOG”, “Continental” and “Oxy”), including their affiliates, are our three largest contract drilling customers. We perform drilling services for EOG and Continental in U.S. land operations and Oxy on a world-wide basis. Revenues from drilling services performed for EOG, Continental and Oxy in fiscal 2017 accounted for approximately 9 percent, 9 percent and 7 percent, respectively, of our consolidated operating revenues for the same period.

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

We provide drilling rigs, equipment, personnel and related ancillary services on a contract basis. These services are provided so that our customers may explore for and develop oil and gas from onshore areas and from fixed platforms, tension‑leg platforms and spars in offshore areas. Each of the drilling rigs consists of engines, drawworks, a mast, pumps, blowout preventers, a drill string and related equipment. The intended well depth and the drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job. A land drilling rig may be moved from location to location without modification to the rig. A platform rig is specifically

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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 higher performing 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, building, and periodically upgrading, 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. In 2004, we deployed the first FlexRig3 skidding systems to enable efficient multi-well pad developments.  Over 135 of these systems have since been installed on FlexRig3’s operating in both the United States and international locations.  In 2017, we announced and began to deploy FlexRig3 walking system conversions as a second FlexRig3 solution for multi-well pad designs.  FlexRig3s are designed to target well depths of between 8,000 and 25,000 feet.

In 2006, we placed into service our first FlexRig4. While FlexRig4s are similar to our FlexRig3s, the FlexRig4s are designed to efficiently drill more shallow depth wells of between 4,000 and 18,000 feet. The FlexRig4 design includes a trailerized version and a skidding version, which incorporate additional environmental and safety designs. While the FlexRig4 trailerized version provides for more efficient well site to well site rig moves, the skidding version allows for drilling of up to 22 wells from a single pad which results in reduced environmental impact.

In 2011, we announced the introduction of the FlexRig5 design. The FlexRig5 is suited for long lateral drilling of multiple wells from a single location, which is well suited for unconventional shale reservoirs. The new design preserves the key performance features of FlexRig3 combined with a bi‑directional pad drilling system and equipment capacities suitable for wells in excess of 25,000 feet of measured depth.

Industry trends toward more complex drilling have accelerated the retirement of less capable mechanical rigs. Over time our mechanical rigs have been sold or decommissioned as we added new AC drive rigs to our fleet. The decommission of our remaining seven mechanical rigs in fiscal 2011 marked the end of a multi‑year evolution in the high‑grading of our fleet from mechanical rigs to high‑efficiency, high‑performance rigs. In fiscal 2015, we also decommissioned 23 of our 37 remaining SCR rigs including six of the eight 3,000 horsepower conventional rigs in our U.S. Land fleet, all six of our FlexRig1 SCR rigs and all 11 of our FlexRig2 SCR rigs. In fiscal 2016 and 2017, we did not decommission any of our remaining 14 SCR rigs.

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Since 1998, we have built 232 FlexRig3s, 88 FlexRig4s, and 53 FlexRig5s with all 373 of those delivered to the field. Of the total 373 AC drive FlexRigs built through September 30, 2017, 110 have been built in the last five fiscal years.

The effective use of technology is important to the maintenance of our competitive position within the drilling industry. We expect to continue to focus on new technology solutions and applications in the future. Our research and development expense totaled $12.0 million in fiscal 2017, $10.3 million in fiscal 2016, and $16.1 million in fiscal 2015.

We currently have three facilities that provide vertically integrated solutions for drilling rig fabrication, upgrades, retrofits and modifications, as well as overhauling and repairing of drilling rigs, equipment and associated component parts. We have a gulf coast fabrication and assembly facility near Houston, Texas as well as a 123,000 square foot fabrication facility located on approximately 11 acres near Tulsa, Oklahoma. Additionally, we lease a 150,000 square foot industrial facility near Tulsa, Oklahoma.

Our business is subject to various federal, state and local laws enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. We do not anticipate that compliance with currently applicable environmental regulations and controls will significantly change our competitive position, capital spending or earnings during fiscal 2018. For further information on environmental laws and regulations applicable to our operations, see Item 1A—“Risk Factors.”

Industry / Competitive Conditions

Our business largely depends on the level of capital spending by oil and gas companies for exploration, development and production activities. Sustained increases or decreases in the price of oil and natural gas generally have a material impact on the exploration, development and production activities of our customers. As such, significant declines in the price of oil and natural gas may have a material adverse effect on our business, financial condition and results of operations. Oil prices have declined significantly since 2014 when prices exceeded $100 per barrel. Oil prices have rebounded modestly from lows below $30 per barrel in early 2016 to ranges between approximately $43 and $54 per barrel in fiscal 2017. The decline in prices continued to negatively affect demand for services in fiscal 2016 before showing some recovery in 2017. At the close of fiscal 2017 we had 218 contracted rigs, compared to 118 contracted rigs at the close of fiscal 2016 and 168 contracted rigs at the close of fiscal 2015. In addition, and in light of the price of oil and the status of the drilling industry and our rig fleet, in fiscal 2015 we performed an impairment evaluation of all our long‑lived drilling assets in accordance with ASC 360, Property, Plant, and Equipment. Our evaluation resulted in $39.2 million of impairment charges to reduce the carrying value of seven SCR land rigs within our International Land segment to their estimated fair value. Similarly, during fiscal 2016 we recorded a $6.3 million impairment charge to reduce the carrying value of certain rig and rig related equipment on previously decommissioned rigs to their estimated fair values. While we continue to periodically perform impairment evaluations, no additional impairments were identified in fiscal 2017 for any rigs in our domestic, international or offshore fleets. For further information concerning risks associated with our business, including volatility surrounding oil and natural gas prices and the impact of low oil prices on our business, see Item 1A—“Risk Factors” and Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this Form 10‑K.

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

We compete against many drilling companies and certain competitors are present in more than one of our operating regions. In the United States, we compete with Nabors Industries Ltd., Patterson‑UTI Energy, Inc. and many other competitors with regional operations. Internationally, we compete directly with various contractors at each location

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where we operate. In the Gulf of Mexico platform rig market, we primarily compete with Nabors Industries Ltd. and Blake International Rigs, LLC.

Drilling Contracts

Our drilling contracts are obtained through competitive bidding or as a result of negotiations with customers, and often cover multi‑well and multi‑year projects. Each drilling rig operates under a separate drilling contract. During fiscal 2017, all drilling services were performed on a “daywork” contract basis, under which we charged 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 twenty 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, 2017, we had 112 existing rigs under fixed‑term contracts. While the original duration for these current fixed‑term contracts are for six‑month to five‑year periods, some fixed‑term and well‑to‑well contracts are expected to be extended for longer periods than the original terms. However, the contracting parties have no legal obligation to extend these contracts and some customers may elect to early terminate fixed‑term contracts as discussed above.

Backlog

Our contract drilling backlog, being the expected future revenue from executed contracts with original terms in excess of one year, as of September 30, 2017 and 2016 was $1.3 billion and $1.8 billion, respectively. The decrease in backlog at September 30, 2017 from September 30, 2016, is primarily due to the revenue earned since September 30, 2016. Approximately 41.7 percent of the total September 30, 2017 backlog is not reasonably expected to be filled in fiscal 2018.  Included in backlog is early termination revenue expected to be recognized after the periods presented in which early termination notice was received prior to the end of the period.

The following table sets forth the total backlog by reportable segment as of September 30, 2017 and 2016, and the percentage of the September 30, 2017 backlog not reasonably expected to be filled in fiscal 2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

Total Backlog

    

 

  

 

 

Revenue

 

Percentage Not Reasonably

 

Reportable Segment

    

9/30/2017

    

9/30/2016

    

Expected to be Filled in Fiscal 2018

 

 

 

(in billions)

 

 

 

U.S. Land

 

$

0.9

 

$

1.2

 

36.4

%

Offshore

 

 

 —

 

 

0.1

 

 —

%

International

 

 

0.4

 

 

0.5

 

58.0

%

 

 

$

1.3

 

$

1.8

 

  

 

 

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

U.S. Land Drilling

At the end of September 2017, 2016, and 2015, we had 350, 348 and 343, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2017 increased by a net of two rigs from the end of fiscal 2016. The net increase is due to two new FlexRigs completed in 2017. Our U.S. Land operations contributed approximately 80 percent ($1.4 billion) of our consolidated operating revenues during fiscal 2017, compared with approximately 77 percent ($1.2 billion) of consolidated operating revenues during fiscal 2016 and approximately 80 percent ($2.5 billion) of consolidated operating revenues during fiscal 2015. Rig utilization was approximately 45 percent in fiscal 2017, approximately 30 percent in fiscal 2016 and approximately 62 percent in fiscal 2015. A rig is considered to be utilized when it is operated (or otherwise deployed for a customer) or being moved, assembled or dismantled under contract. At the close of fiscal 2017, 197 out of an available 350 land rigs were generating revenue.

Offshore Drilling

Our Offshore operations contributed approximately 8 percent in fiscal year 2017 ($136.3 million) of our consolidated operating revenues compared to approximately 9 percent ($138.6 million) of consolidated operating revenues during fiscal 2016 and 8 percent ($241.7 million) of consolidated operating revenues during fiscal 2015. Rig utilization in fiscal 2017 was approximately 74 percent compared to approximately 82 percent in fiscal 2016 and 93 percent in fiscal 2015. At the end of fiscal 2017, we had five of our eight offshore platform rigs under contract compared to seven of an available nine at the end of fiscal 2016. We continued to work under management contracts for two customer‑owned rigs at the close of fiscal 2017. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 60 percent ($81.1 million) of offshore revenues during fiscal 2017.

International Land Drilling

General

At the end of September 2017, 2016 and 2015, we had 38 land rigs available for work in locations outside of the United States. Our International Land operations contributed approximately 12 percent ($213.0 million) of our consolidated operating revenues during fiscal 2017, compared with approximately 14 percent ($229.9 million) of consolidated operating revenues during fiscal 2016 and 12 percent ($382.3 million) of consolidated operating revenues during fiscal 2015. Rig utilization was 36 percent in fiscal 2017, 39 percent in fiscal 2016 and 51 percent in fiscal 2015. Our international operations are subject to various political, economic and other uncertainties not typically encountered in U.S. operations. For further information on various risks associated with doing business in foreign countries, see Item 1A—“Risk Factors.”

Argentina

At the end of fiscal 2017, we had 19 rigs in Argentina. Our utilization rate was approximately 55 percent during fiscal 2017, approximately 54 percent during fiscal 2016 and approximately 57 percent during fiscal 2015. Revenues generated by Argentine drilling operations contributed approximately 9 percent in fiscal 2017 ($157.3 million) of our consolidated operating revenues compared to approximately 10 percent ($159.4 million) of our consolidated operating revenues during fiscal 2016 and approximately 6 percent ($178.0 million) of our consolidated operating revenues during fiscal 2015. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 8 percent of consolidated operating revenues and approximately 70 percent of international operating revenues during fiscal 2017. The Argentine drilling contracts are primarily with large international or national oil companies.

Colombia

At the end of fiscal 2017, we had eight rigs in Colombia. Our utilization rate was approximately 25 percent during fiscal 2017, approximately 13 percent during fiscal 2016 and approximately 48 percent during fiscal 2015. Revenues generated by Colombian drilling operations contributed approximately 2 percent in fiscal 2017 ($37.6 million)

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of our consolidated operating revenues compared to approximately 1 percent ($20.5 million) of our consolidated operating revenues during fiscal 2016 and approximately 2 percent ($70.1 million) of our consolidated operating revenues during fiscal 2015. Revenues from drilling services performed for our two customers in Colombia totaled approximately 2 percent of consolidated operating revenues and approximately 18 percent of international operating revenues during fiscal 2017. The Colombian drilling contracts are primarily with large international or national oil companies.

Ecuador

At the end of fiscal 2017, we had six rigs in Ecuador. At the end of fiscal 2017 and 2016, all of our rigs in Ecuador were idle. The utilization rate in Ecuador was 4 percent in fiscal 2016 and 29 percent in fiscal 2015. Revenues generated by Ecuadorian drilling operations were insignificant during fiscal 2017 compared to contributing less than 1 percent during fiscal 2016 ($4.9 million) of our consolidated operating revenues and 1 percent in fiscal 2015 ($31.0 million) of our consolidated operating revenues.

UAE—Abu Dhabi

At the end of fiscal 2017, we had two rigs in the UAE. The utilization rate in the UAE was 8 percent in fiscal 2017, compared to 100 percent in fiscal 2016 and in fiscal 2015. Revenues generated by drilling operations in the UAE contributed less than 1 percent ($8.2 million) during fiscal 2017 of our consolidated operating revenues compared to approximately 2 percent during fiscal 2016 and fiscal 2015 ($34.6 million and $47.7 million, respectively) of our consolidated operating revenues. The UAE drilling contracts are with a single national oil company that contributed approximately 4 percent of international operating revenues during fiscal 2017.

Bahrain

At the end of fiscal 2017, we had three rigs in Bahrain. The utilization rate in Bahrain was 33 percent in fiscal 2017 and fiscal 2016, compared to 56 percent in fiscal 2015. Revenues generated by drilling operations in Bahrain contributed 1 percent during fiscal 2017, fiscal 2016 and fiscal 2015 ($10.0 million, $10.2 million and $41.9 million, respectively) of our consolidated operating revenues. Bahrain drilling contracts are with a single national oil company that contributed approximately 5 percent of international operating revenues during fiscal 2017.

FINANCIAL

For information relating to revenues, total assets and operating income by reportable operating segments, see Note 15—“Segment Information” included in Item 8—“Financial Statements and Supplementary Data” of this Form 10‑K.

EMPLOYEES

We had 7,270 employees within the United States (5 of which were part‑time employees) and 853 employees in international operations as of September 30, 2017.

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.

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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 and market expectations regarding such prices.

Oil prices declined significantly during the second half of 2014. Volatility and the overall decline in prices continued through 2015 and into early 2016. For example, in July of 2014 oil prices exceeded $100 per barrel. Oil prices dropped below $30 per barrel in early 2016.  In fiscal 2016 oil prices rebounded but nevertheless remained volatile and continued to fluctuate in fiscal 2017 above and below $50 per barrel.  The precipitous drop in oil prices and volatility over the last three years significantly affected the capital spending budgets of our customers, particularly in 2015 and 2016.  As such, demand for our drilling services significantly declined from late 2014 through the first half of fiscal 2016. At December 31, 2014, 294 out of an available 337 land rigs were working in the U.S. Land segment. In contrast, at June 30, 2016, 89 out of an available 348 land rigs were contracted in the U.S. Land segment.  Due to the modest rebound in oil prices we have experienced an increase in the demand for our drilling services since May of 2016.  Nevertheless, our active rig count has remained below the height of drilling activity experienced in 2014 when oil prices were significantly higher.  As of November 16, 2017, 200 rigs were contracted in the U.S. Land segment. In the event oil prices remain depressed for a sustained period, or decline again, our U.S. Land, International Land and Offshore segments may again experience significant declines in both drilling activity and spot dayrate pricing which could have a material adverse effect on our business, financial condition and results of operations. 

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

·

the demand for oil and natural gas;

·

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

·

the worldwide economy;

·

expectations about future oil and natural gas prices;

·

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

·

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

·

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

·

domestic and international tax policies;

·

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

·

technological advances;

·

the development and exploitation of alternative fuels;

·

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

·

local and international political, economic and weather conditions; and

·

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

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

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

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

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

We have a facility located near the Houston, Texas ship channel where we upgrade and repair rigs and perform fabrication work, and our principal fabricator and other vendors are also located in the gulf coast region. Due to their location, these facilities are exposed to potentially greater hurricane damage.

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

With the exception of “named wind storm” risk in the Gulf of Mexico, we insure rigs and related equipment at values that approximate the current replacement cost on the inception date of the policies. However, we self‑insure large deductibles under these policies. We also carry insurance with varying deductibles and coverage limits with respect to offshore platform rigs and “named wind storm” risk in the Gulf of Mexico.

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

If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition and results of operations. Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes aggregate policy limits. As a result, we retain the risk

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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 2018, 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.

Global economic conditions may adversely affect our business.

Global economic conditions and volatility in oil and natural gas prices may impact the ability or desire of our customers to maintain or increase spending on exploration and development drilling and whether customers and/or vendors and suppliers will be able to access financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations. In the event the strength of the global economic environment fails to gain momentum or deteriorates in 2018, industry fundamentals may be impacted and result in stagnant or reduced demand for drilling rigs. Furthermore, these factors may result in certain of our customers experiencing bankruptcy or otherwise becoming unable to pay vendors, including us. The global economic environment in the past has experienced significant deterioration in a relatively short period of time and there can be no assurance that the global economic environment will not quickly deteriorate again due to one or more factors. These conditions could have a material adverse effect on our business, financial condition and results of operations.

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

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

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

The oil and natural gas services industry in the United States has experienced downturns in demand during the last decade, including a significant downturn that started in 2014 and bottomed out in 2016. Today, as was the case following past downturns, there are substantially more drilling rigs available than necessary to meet the modest rebound in demand observed in 2016 and 2017. As a result of the current excess of available and more competitive drilling rigs, we may continue to experience difficulty in replacing fixed‑term contracts, extending expiring contracts or obtaining new contracts in the spot market, and the day rates (and other material terms) under new contracts may be on substantially less favorable rates and terms. As such, we may have difficulty sustaining or increasing rig utilization and profit margins in the future, we may lose market share and price may be a primary factor in the award of contracts for drilling services.

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

In fiscal 2017, we received approximately 55 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 25 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.

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

The market for our services is characterized by continual technological developments that have resulted in, and will likely continue to result in, substantial improvements in the functionality and performance of rigs and equipment. Our customers increasingly demand the services of newer, higher specification drilling rigs. This results in a bifurcation of the drilling fleet and is evidenced by the higher specification drilling rigs (e.g., AC rigs) generally operating at higher overall utilization levels and day rates than the lower specification drilling rigs (e.g., mechanical or SCR rigs). In addition, a significant number of lower specification rigs are being stacked and/or removed from service. As a result of this bifurcation, a higher level of capital expenditures will be required to maintain and improve existing rigs and equipment and purchase and construct newer, higher specification drilling rigs to meet the increasingly sophisticated needs of our customers.

Since the late 1990’s we have increased our drilling rig fleet through new construction. We also continue to modify our existing rig fleet to meet customer requirements.  We have upgraded FlexRigs to super-spec rigs, developed walking rigs, and made other improvements.  Although we take measures to ensure that we use advanced oil and natural gas drilling technology, changes in technology or improvements in competitors’ equipment could make our equipment less competitive. There can be no assurance that we will:

·

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

·

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

·

successfully deploy idle, stacked, new or upgraded drilling rigs;

·

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

·

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

·

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

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

Technology disputes could negatively impact our operations or increase our costs.

 

Drilling rigs use proprietary technology and equipment which can involve potential infringement of a third party’s rights, including patent rights. The majority of the intellectual property rights relating to our drilling rigs are owned by us or certain of our supplying vendors.  However, in the event that we or one of our supplying vendors becomes involved in a dispute over infringement rights relating to equipment owned or used by us, we may lose access to important equipment, or we could be required to cease use of some equipment or forced to modify our drilling rigs. We could also be required to pay license fees or royalties for the use of equipment. Technology disputes involving us or our supplying vendors could have a material adverse impact on our business, financial condition and results of operation.

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

 

It is a common practice in our industry for our customers to recover natural gas and oil from shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations using water, sand and other additives pumped under high pressure into the formation. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure, waste disposal and/or well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Members of the U.S. Congress and a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing and the possibility of more stringent regulation. Further, we conduct drilling activities in numerous states, including Oklahoma. In recent years, Oklahoma has experienced an increase in earthquakes. Some parties believe that there is a correlation between hydraulic fracturing related activities and the increased occurrence of seismic activity. The extent of this correlation, if any, is the subject of studies of both state and federal agencies the results of which remain uncertain. Depending on the outcome of these or other studies pertaining to the impact of hydraulic fracturing, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing activities. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques, operational delays or increased operating and compliance costs in the production of oil and natural gas from shale plays, added difficulty in performing hydraulic fracturing, and potentially a decline in the completion of new oil and gas wells.

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

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

We evaluate our drilling rigs and other assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss may exist when the estimated future cash flows are less than the carrying amount of the asset. Lower utilization and day rates adversely affect our revenues and profitability. Prolonged periods of low utilization and day rates may result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable. For example, in fiscal 2015, we performed an impairment evaluation of all our long‑lived drilling assets. Our evaluation resulted in $39.2 million of impairment charges to reduce the carrying value of seven SCR land rigs within our International Land segment to their estimated fair value. Similarly, during the third quarter of fiscal 2016 we recorded a $6.3 million impairment charge to reduce the carrying value of certain rig and rig related equipment classified as held for sale in our U.S. Land segment to their estimated fair values. Although we are actively marketing idle drilling rigs in our fleet, there can be no assurance that we will be able to obtain future contracts for all of our rigs. As of September 30, 2017, we assessed our idle drilling rigs and determined no additional impairment charges were necessary. However, drilling rigs in our fleet may become impaired in the future if market conditions deteriorate or if oil and gas prices decline further or remain low for a prolonged period.

Department of Interior investigation could adversely affect our business.

On November 8, 2013, the United States District Court for the Eastern District of Louisiana approved the previously disclosed October 30, 2013 plea agreement between our wholly owned subsidiary, Helmerich & Payne International Drilling Co. (“H&PIDC”), and the United States Department of Justice, United States Attorney’s Office for the Eastern District of Louisiana (“DOJ”). The court’s approval of the plea agreement resolved the DOJ’s investigation into certain choke manifold testing irregularities that occurred in 2010 at one of H&PIDC’s offshore platform rigs in the Gulf of Mexico. We also engaged in discussions with the Inspector General’s office of the Department of Interior

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(“DOI”) regarding the same events that were the subject of the DOJ’s investigation. Although we do not presently anticipate any further action by the DOI in this matter, we can provide no assurances as to the timing or eventual outcome of the DOI’s consideration of the matter. Refer also to Item 3—“Legal Proceedings” and Note 14—“Commitments and Contingencies” included in Item 8—“Financial Statements and Supplementary Data” of this Form 10‑K for discussion of this subject.

Our business and results of operations may be adversely affected by foreign political, economic and social instability risks, foreign currency restrictions and devaluation, and various local laws associated with doing business in certain foreign countries.

We currently have drilling operations in South America and the Middle East. 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.  Today, our contracts for work in foreign countries generally provide for payment in U.S. dollars.  However, in Argentina we are paid in Argentine pesos.  The Argentine branch of one of our second-tier subsidiaries then remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars. 

Estimates from published sources indicate that Argentina is a highly inflationary country, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period based on inflation data published by the respective governments.  Regardless, all of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations.

   

In December 2015, the Argentine peso experienced a sharp devaluation resulting in a foreign currency loss of $8.4 million for fiscal 2016.  Subsequent to the sharp devaluation, the Argentine peso significantly stabilized and the Argentine Foreign Exchange Market controls now place fewer restrictions on repatriating U.S. dollars.  For fiscal 2017, we experienced a  foreign currency loss of $4.0 million in Argentina.  Our aggregate foreign currency losses for fiscal 2016 and 2017 were $9.3 million and $7.1 million, respectively.  In the future, other contracts or applicable law may require payments to be made in foreign currencies.  As such, there can be no assurance that we will not experience in Argentina or elsewhere a devaluation of foreign currency, foreign exchange restrictions or other difficulties repatriating U.S. dollars even if we are able to negotiate contract provisions designed to mitigate such risks.  In 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.

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

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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 2017, approximately 12 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2017, approximately 92 percent of the international operating revenues were from operations in South America. Substantially all of the South American operating revenues were from Argentina and Colombia. 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.

Drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.

We currently own and operate rigs that are contracted with foreign national oil companies.  In the future we may expand our international operations and enter into additional, significant contracts with national oil companies.  The terms of these contracts may contain non-negotiable provisions and may expose us to greater commercial, political, operational and other risks than we assume in other contracts.  Foreign contracts may expose us to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, or under certain conditions that may not provide us with an early termination payment.  We can provide no assurance that increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks.  Risks that accompany contracts with national oil companies could ultimately have a material adverse impact on our business, financial condition and results of operation

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

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

Failure to comply with governmental and environmental laws could adversely affect our business.

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

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.

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Our current backlog of contract drilling revenue may continue to decline and may not be ultimately realized as fixed‑term contracts may in certain instances be terminated without an early termination payment.

Fixed‑term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. Even if an early termination payment is owed to us, a customer may be unable or may refuse to pay the early termination payment. We also may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, such as depressed market conditions. As of September 30, 2017, our contract drilling backlog was approximately $1.3 billion for future revenues under firm commitments. Our contract drilling backlog may continue to decline over time as existing contract term coverage may not be offset by new term contracts as a result of any number of factors, such as low or declining oil prices and capital spending reductions by our customers. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse impact on our business, financial condition and results of operations.

Our contract drilling expense includes fixed costs that may not decline in proportion to decreases in rig utilization and dayrates.

 

Our contract drilling expense includes all direct and indirect costs associated with the operation, maintenance and support of our drilling equipment, which is often not affected by changes in dayrates and utilization.  During periods of reduced revenue and/or activity, certain of our fixed costs (such as depreciation) may not decline and often we may incur additional costs.  During times of reduced utilization, reductions in costs may not be immediate as we may incur additional costs associated with maintaining and cold stacking a rig, or we may not be able to fully reduce the cost of our support operations in a particular geographic region due to the need to support the remaining drilling rigs in that region. Accordingly, a decline in revenue due to lower dayrates and/or utilization may not be offset by a corresponding decrease in contract drilling expense which could have a material adverse impact on our business, financial condition and results of operations.

 

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

 

At September 30, 2017, we had a portfolio of securities with a total fair value of approximately $70.1 million, consisting of Atwood Oceanics, Inc. (“Atwood”) and Schlumberger, Ltd. The total fair value of the portfolio of securities was $71.5 million at September 30, 2016.   In May of 2017, Ensco plc (“Ensco”) announced that it entered into a definitive merger agreement under which Ensco would acquire Atwood in an all-stock transaction. The transaction closed on October 6, 2017.  Under the terms of the merger agreement, we received 1.60 shares of Ensco for each share of our Atwood common stock. The securities in our portfolio are subject to a wide variety of market‑related risks that could substantially reduce or increase the fair value of the holdings. In general, 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.  However, where a decline in fair value below our cost basis is considered to be other than temporary, the change in value is recorded as a charge through earnings.  During the fourth quarter of fiscal 2016, we determined that a loss was other‑than‑temporary and we recognized a $26.0 million impairment charge.  No such impairment charge was recognized in fiscal 2017.   At November 16, 2017, the fair value of the portfolio had decreased to approximately $63.2 million. 

We may reduce or suspend our dividend in the future.

We have paid a quarterly dividend for many years. Our most recent, quarterly dividend was $0.70 per share. In the future, our Board of Directors may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position the Company for long‑term success. The declaration and amount of future dividends is at the discretion of our Board of Directors and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board of Directors deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. There can be no assurance that we will continue to pay a dividend in the future.

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Legal proceedings could have a negative impact on our business.

The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. In addition, during periods of depressed market conditions we may be subject to an increased risk of our customers, vendors, former employees and others initiating legal proceedings against us. Lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations. Any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.

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

Certain key rig components, parts and equipment are either purchased from or fabricated by a single or limited number of vendors, and we have no long‑term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply, the acquisition of a vendor by a competitor, increased demands in the industry or other reasons beyond our control. Similarly, certain key rig components, parts and equipment are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from us or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, downturn in the energy industry or reduction or unavailability of credit. If we are unable to procure certain of such rig components, parts or equipment, our ability to maintain, improve, upgrade or construct drilling rigs could be impaired, which could have a material adverse effect on our business, financial condition and results of operations.

We may have additional tax liabilities and/or be limited in our use of net operating losses and tax credits.

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. Our ability to benefit from our deferred tax assets depends on us having sufficient future taxable income to utilize our net operating loss and tax credit carryforwards before they expire.   Our net operating loss and tax credit carryforwards are subject to review and potential disallowance upon audit by the tax authorities of the jurisdictions where these tax attributes are incurred. Future changes to tax laws (including tax treaties) could also impact our effective rate.

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

Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by major U.S. credit rating agencies. Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, commodity pricing levels and other considerations. A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.

Our ability to access capital markets could be limited.

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

15


 

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

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

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

Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”) and including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. The United States Congress may consider legislation to reduce GHG emissions. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse impact on our business, financial condition and results of operations. Further, to the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of or access to capital. Climate change and GHG regulation could also reduce the demand for hydrocarbons and, ultimately, demand for our services.

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

We greatly depend on the efforts of our executive officers and other key employees to manage our operations. The loss of members of management could have a material effect on our business. Similarly, we utilize highly skilled personnel in operating and supporting our businesses. In times of high utilization, it can be difficult to retain, and in some cases find, qualified individuals. Although to date our operations have not been materially affected by competition for personnel, an inability to obtain or find a sufficient number of qualified personnel could have a material adverse effect on our business, financial condition and results of operations.

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

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

Our business is subject to cybersecurity risks.

Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Cybersecurity attacks could include, but are not limited to, malicious software, attempts to gain unauthorized access to our data and the unauthorized release, corruption or loss of our data and personal information, loss of our intellectual property, theft of our FlexRig and other technology, loss or damage to our data delivery systems, other electronic security breaches that could lead to disruptions in our critical systems, and increased costs to prevent, respond to or mitigate cybersecurity events. It is possible that our business, financial and other systems could be

16


 

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.

Unexpected events could disrupt our business and adversely affect our results of operations.

Unexpected and entirely unanticipated events, including, without limitation, computer system disruptions, unplanned power outages, fires or explosions at drilling rigs, natural disasters such as hurricanes and tornadoes, war or terrorist activities, supply disruptions, failure of equipment, changes in laws and/or regulations impacting our businesses, pandemic illness and other unforeseeable circumstances that may arise from our increasingly connected world or otherwise could adversely affect our business.  It is not possible for us to predict the occurrence or consequence of any such events. However, any such events could reduce our ability to provide drilling services, reduce demand for our services, or make it more difficult or costly to provide services which ultimately may have a material adverse effect on our business, financial condition and results of operations.

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, sell or otherwise dispose of assets, enter into new lines of business, and merge or consolidate. In addition, our credit facility requires us to maintain a funded leverage ratio (as defined) of less than 50 percent and certain priority debt (as defined) may not exceed 17.5% of our net worth (as defined). Such restrictions may limit our ability to successfully execute our business plans, which may have adverse consequences on our operations.

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

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

Item 1B.  UNRESOLVED STAFF COMMENTS

We have received no written comments regarding our periodic or current reports from the staff of the SEC that were issued 180 days or more preceding the end of our 2017 fiscal year and that remain unresolved.

17


 

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, 2017:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Optimum

 

 

 

Drawworks:

Location

    

Rig

    

Depth (Feet)*

    

Rig Type

    

Horsepower

FlexRigs

 

 

 

 

 

 

 

 

Texas

 

212

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

214

 

22,000

 

AC (FlexRig3)

 

1,500

Utah

 

215

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

216

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

218

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

220

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

221

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

222

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

223

 

22,000

 

AC (FlexRig3)

 

1,500

Pennsylvania

 

225

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

226

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

227

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

228

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

231

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

232

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

233

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

236

 

22,000

 

AC (FlexRig3)

 

1,500

North Dakota

 

239

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

240

 

22,000

 

AC (FlexRig3)

 

1,500

Pennsylvania

 

241

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

242

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

244

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

245

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

246

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

247

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

248

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

249

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

250

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

251

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

252

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

253

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

254

 

22,000

 

AC (FlexRig3)

 

1,500

North Dakota

 

255

 

22,000

 

AC (FlexRig3)

 

1,500

North Dakota

 

256

 

22,000

 

AC (FlexRig3)

 

1,500

Wyoming

 

257

 

22,000

 

AC (FlexRig3)

 

1,500

North Dakota

 

258

 

22,000

 

AC (FlexRig3)

 

1,500

North Dakota

 

259

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

260

 

22,000

 

AC (FlexRig3)

 

1,500

California

 

261

 

22,000

 

AC (FlexRig3)

 

1,500

New Mexico

 

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

Colorado

 

271

 

18,000

 

AC (FlexRig4)

 

1,500

18


 

 

 

 

 

Optimum

 

 

 

Drawworks:

Location

    

Rig

    

Depth (Feet)*

    

Rig Type

    

Horsepower

North Dakota

 

272

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

273

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

274

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

275

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

276

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

277

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

278

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

279

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

280

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

281

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

282

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

283

 

8,000

 

AC (FlexRig4)

 

1,150

Pennsylvania

 

284

 

18,000

 

AC (FlexRig4)

 

1,500

Pennsylvania

 

285

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

286

 

18,000

 

AC (FlexRig4)

 

1,500

Pennsylvania

 

287

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

288

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

289

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

290

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

293

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

294

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

295

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

296

 

18,000

 

AC (FlexRig4)

 

1,500

Oklahoma

 

297

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

298

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

299

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

300

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

302

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

303

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

304

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

305

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

306

 

8,000

 

AC (FlexRig4)

 

1,150

Colorado

 

307

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

308

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

309

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

310

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

311

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

312

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

313

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

314

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

315

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

316

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

317

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

318

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

319

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

320

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

321

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

322

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

323

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

324

 

18,000

 

AC (FlexRig4)

 

1,500

North Dakota

 

325

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

326

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

327

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

328

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

329

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

330

 

18,000

 

AC (FlexRig4)

 

1,500

19


 

 

 

 

 

Optimum

 

 

 

Drawworks:

Location

    

Rig

    

Depth (Feet)*

    

Rig Type

    

Horsepower

Texas

 

331

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

332

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

340

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

341

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

342

 

18,000

 

AC (FlexRig4)

 

1,500

Colorado

 

343

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

344

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

345

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

346

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

347

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

348

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

349

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

351

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

352

 

8,000

 

AC (FlexRig4)

 

1,150

North Dakota

 

353

 

18,000

 

AC (FlexRig4)

 

1,500

Pennsylvania

 

354

 

18,000

 

AC (FlexRig4)

 

1,500

Texas

 

355

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

356

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

360

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

361

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

362

 

8,000

 

AC (FlexRig4)

 

1,150

Texas

 

370

 

22,000

 

AC (FlexRig3)

 

1,500

West Virginia

 

371

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

372

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

373

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

374

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

375

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

376

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

377

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

378

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

379

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

380

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

381

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

382

 

22,000

 

AC (FlexRig3)

 

1,500

Louisiana

 

383

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

384

 

22,000

 

AC (FlexRig3)

 

1,500

Pennsylvania

 

385

 

22,000

 

AC (FlexRig3)

 

1,500

North Dakota

 

386

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

387

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

388

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

389

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

390

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

391

 

22,000

 

AC (FlexRig3)

 

1,500

North Dakota

 

392

 

22,000

 

AC (FlexRig3)

 

1,500

New Mexico

 

393

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

394

 

22,000

 

AC (FlexRig3)

 

1,500

New Mexico

 

395

 

22,000

 

AC (FlexRig3)

 

1,500

New Mexico

 

396

 

22,000

 

AC (FlexRig3)

 

1,500

Louisiana

 

397

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

398

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

399

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

415

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

416

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

417

 

22,000

 

AC (FlexRig3)

 

1,500

Louisiana

 

418

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

419

 

22,000

 

AC (FlexRig3)

 

1,500

20


 

 

 

 

 

Optimum

 

 

 

Drawworks:

Location

    

Rig

    

Depth (Feet)*

    

Rig Type

    

Horsepower

Texas

 

420

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

421

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

422

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

423

 

22,000

 

AC (FlexRig3)

 

1,500

California

 

424

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

425

 

22,000

 

AC (FlexRig3)

 

1,500

California

 

426

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

427

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

428

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

429

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

430

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

431

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

432

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

433

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

434

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

435

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

436

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

437

 

22,000

 

AC (FlexRig3)

 

1,500

Wyoming

 

438

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

439

 

22,000

 

AC (FlexRig3)

 

1,500

California

 

440

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

441

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

442

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

443

 

22,000

 

AC (FlexRig3)

 

1,500

California

 

444

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

445

 

22,000

 

AC (FlexRig3)

 

1,500

North Dakota

 

446

 

22,000

 

AC (FlexRig3)

 

1,500

Oklahoma

 

447

 

22,000

 

AC (FlexRig3)

 

1,500

Colorado

 

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

Louisiana

 

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

Oklahoma

 

464

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

465

 

22,000

 

AC (FlexRig3)

 

1,500

New Mexico

 

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

Oklahoma

 

470

 

22,000

 

AC (FlexRig3)

 

1,500

Ohio

 

471

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

472

 

22,000

 

AC (FlexRig3)

 

1,500

New Mexico

 

473

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

474

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

475

 

22,000

 

AC (FlexRig3)

 

1,500

21


 

 

 

 

 

Optimum

 

 

 

Drawworks:

Location

    

Rig

    

Depth (Feet)*

    

Rig Type

    

Horsepower

Texas

 

477

 

22,000

 

AC (FlexRig3)

 

1,500

Texas

 

478

 

22,000

 

AC (FlexRig3)

 

1,500