10-K 1 hp-20180930x10k.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, 2018

 

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 14221

HELMERICH & PAYNE, INC.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware

730679879

(State or Other Jurisdiction of

(I.R.S. Employer Identification No.)

Incorporation or Organization)

 

1437 S. Boulder Ave., Suite 1400, Tulsa, Oklahoma

741193623

(Address of Principal Executive Offices)

(Zip Code)

(918) 7425531

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 wellknown 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes   No 

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation SK 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 10K or any amendment to this Form 10K. 

 

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a nonaccelerated 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 12b2 of the Exchange Act.

 

Large accelerated filer 

Smaller reporting company 

    

Accelerated filer 

Emerging Growth Company 

    

Nonaccelerated filer 

 

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 12b2 of the Exchange Act). Yes   No 

 

At March 29, 2018, the last business day of the Registrant’s most recently completed second fiscal quarter, the aggregate market value of the Registrant’s common stock held by nonaffiliates was approximately $7.25 billion based on the closing price of such stock on the New York Stock Exchange on such date of $66.56.

 

Number of shares of common stock outstanding at November 8, 2018: 109,038,462

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s 2019 Proxy Statement for the Annual Meeting of Stockholders to be held on March 5, 2019 are incorporated by reference into Part III of this Form 10K. The 2019 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 10K relates.

 

 

 


 

HELMERICH & PAYNE, INC.

INDEX TO FORM 10K

YEAR ENDED SEPTEMBER 30, 2018

 

 

    

 

    

Page

PART I 

 

 

 

4

Item 1. 

 

Business

 

4

Item 1A. 

 

Risk Factors

 

16

Item 1B. 

 

Unresolved Staff Comments

 

30

Item 2. 

 

Properties

 

30

Item 3. 

 

Legal Proceedings

 

30

Item 4. 

 

Mine Safety Disclosures

 

30

PART II 

 

 

 

31

Item 5. 

 

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

 

31

Item 6. 

 

Selected Financial Data

 

33

Item 7. 

 

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

 

34

Item 7A. 

 

Quantitative and Qualitative Disclosures About Market Risk

 

52

Item 8. 

 

Financial Statements and Supplementary Data

 

54

Item 9. 

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

107

Item 9A. 

 

Controls and Procedures

 

107

Item 9B. 

 

Other Information

 

107

PART III 

 

 

 

108

Item 10. 

 

Directors, Executive Officers and Corporate Governance

 

108

Item 11. 

 

Executive Compensation

 

108

Item 12. 

 

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

 

108

Item 13. 

 

Certain Relationships and Related Transactions, and Director Independence

 

108

Item 14. 

 

Principal Accountant Fees and Services

 

108

PART IV 

 

 

 

109

Item 15. 

 

Exhibits and Financial Statement Schedules

 

109

Item 16. 

 

Form 10‑K Summary

 

111

SIGNATURES 

 

113

 

 

2


 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10K (“Form 10K”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Form 10-K, including without limitation, statements regarding our 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,” “predict,” “project,” “target,” “continue,” or the negative thereof or similar terminology. Forward-looking statements are based upon current plans, estimates, and expectations that are subject to risks, uncertainties, and assumptions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Actual results may vary materially from those indicated or anticipated by such forward-looking statements. The inclusion of such statements should not be regarded as a representation that such plans, estimates, or expectations will be achieved.

These forward-looking statements include, among others, such things as:

·

our business strategy;

·

the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures, and the number of rigs we plan to construct or acquire;

·

the volatility of future oil and natural gas prices;

·

changes in future levels of drilling activity and capital expenditures by our customers, whether as a result of global capital markets and liquidity, changes in prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs, or increase our capital expenditures and the construction or acquisition of rigs;

·

changes in worldwide rig supply and demand, competition, or technology;

·

possible cancellation, suspension, renegotiation or termination (with or without cause) of our contracts as a result of general or industry-specific economic conditions, mechanical difficulties, performance or other reasons;

·

expansion and growth of our business and operations;

·

our belief that the final outcome of our legal proceedings will not materially affect our financial results;

·

impact of federal and state legislative and regulatory actions affecting our costs and increasing operation restrictions or delay and other adverse impacts on our business;

·

environmental or other liabilities, risks, damages or losses, whether related to storms or hurricanes (including wreckage or debris removal), collisions, grounding, blowouts, fires, explosions, other accidents, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;

·

our financial condition and liquidity;

·

tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes; and

·

potential long-lived asset impairments.

Important factors that could cause actual results to differ materially from our expectations or results discussed in the forwardlooking statements are disclosed in this Form 10K 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 forwardlooking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by such cautionary statements. Because of the underlying risks and uncertainties, we caution you against placing undue reliance on these forward-looking statements. We assume no duty to update or revise these forwardlooking statements based on changes in internal estimates, expectations or otherwise, except as required by law.

3


 

PART I

Item 1.  BUSINESS

Overview

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 provide performance-driven drilling services and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. We are an important vendor for a number of oil and gas exploration and production companies, but we focus exclusively on the drilling segment of the oil and gas production value chain.

Our global contract drilling business is composed of three reportable business segments: U.S. Land, Offshore and International Land. During the fiscal year ended September 30, 2018, our U.S. Land operations were located in Colorado, Louisiana, Ohio, Oklahoma, New Mexico, North Dakota, Pennsylvania, Texas, Utah, West Virginia and Wyoming. Our Offshore operations were conducted in the Gulf of Mexico. Our International Land operations had rigs located in five international locations during fiscal year 2018: Argentina, Bahrain, Colombia, Ecuador and United Arab Emirates (“U.A.E.”).

We focus on research and development of technology designed to improve the efficiency and accuracy of drilling operations, as well as wellbore quality and placement. Our research and development endeavors include ongoing improvements of our rig fleet and advancements in rig technology, including our FlexApp™ services, development of a proprietary Bit Guidance System™, offered as a service through MOTIVE Drilling Technologies, Inc. (“MOTIVE”), which we acquired in June 2017, and 3D geomagnetic reference modeling and measurement while drilling survey correction services, offered through Magnetic Variation Services, LLC (“MagVAR”), which we acquired in December 2017. 

We also own, develop and operate limited commercial real estate properties. Our real estate investments, which are located exclusively within Tulsa, Oklahoma, include a shopping center containing approximately 441,000 leasable square feet, multitenant industrial warehouse properties containing approximately one million leasable square feet and approximately 210 acres of undeveloped real estate.

4


 

Drilling Fleet

The following map and table sets forth certain information concerning our U.S. land drilling rigs as of September 30, 2018:

Picture 1

 

 

 

 

 

 

 

 

 

 

 

U.S. Land Fleet

 

AC (FlexRig3) (1)

AC (FlexRig4) (2)

AC (FlexRig5) (3)

SCR (4)

Total Fleet

Current

Total

Rigs

Total

Rigs

Total

Rigs

Total

Rigs

Total

Rigs

Location

Available

Contracted

Available (5)

Contracted

Available

Contracted

Available

Contracted

Available

Contracted

TX

141

110

38

 1

22

22

 1

 —

202

133

OK

20

18

 1

 1

15

15

 —

 —

36

34

NM

27

26

 —

 —

 2

 2

 —

 —

29

28

ND

13

 4

11

 —

 3

 3

 —

 —

27

 7

CO

 —

 —

21

 6

 2

 2

 —

 —

23

 8

PA

 5

 2

 4

 —

 2

 1

 —

 —

11

 3

LA

 7

 7

 —

 —

 2

 1

 1

 —

10

 8

OH

 4

 3

 —

 —

 2

 2

 —

 —

 6

 5

WY

 2

 2

 —

 —

 2

 2

 —

 —

 4

 4

UT

 —

 —

 1

 1

 —

 —

 —

 —

 1

 1

WV

 —

 —

 —

 —

 1

 1

 —

 —

 1

 1

Totals

219

172

76

 9

53

51

 2

 —

350

232

 

(1)

The FlexRig3 is equipped with a 750,000 lb. mast, Varco TDS-11HP top drive and Gardner Denver PZ-11 mud pumps. It can be equipped with an optional skidding or walking system for pad work and 7,500 psi high pressure mud system. This rig is capable of horizontal and vertical drilling.

(2)

The FlexRig4 model is a trailerized rig designed to be highly mobile. The rig is equipped with a 300,000 lb. or 500,000 lb. mast, 400HP top drive and Gardner Denver HS-2250 or PZ-11 mud pumps. Range 3 drill pipe is used without setback. The rig is capable of horizontal and vertical drilling.

(3)

The FlexRig5 base configuration includes a 100 foot, bi-directional skidding system with an optional package that extends to 200 feet. It includes a 750,000 lb. mast, Varco TDS-11HP top drive and Gardner Denver mud pumps. An optional third pump and 7,500 psi high pressure mud system can also be used. This rig is capable of horizontal and vertical drilling.

(4)

A silicon-controlled-rectifier (“SCR”) system converts alternate current (“AC”) produced by one or more AC generator sets into direct current (“DC”).

(5)

Two Domestic FlexRig4 rigs completed their conversions to Domestic FlexRig3’s in the fourth fiscal quarter of 2018. Two Domestic FlexRig4 rigs began the conversion process and three additional rigs are planned for conversion to be completed during the first fiscal quarter of 2019.

5


 

We operate a large fleet of super-spec rigs, which are generally considered to include rig specifications of an AC drive with 1,500 horse power drawworks, 750,000 lbs. hookload ratings, 7,500 psi mud circulating systems and multiple-well pad drilling systems. The chart below depicts the states in which our super-spec rigs operate.  

 

Picture 8

The following table sets forth certain information concerning our offshore drilling rigs as of September 30, 2018:

 

 

 

 

 

 

 

 

Offshore Fleet

Current

Shallow Water (1)

Deep Water (1)

Total Fleet

Location

Total Available

Rigs Contracted

Total Available

Rigs Contracted

Total Available

Rigs Contracted

Louisiana (2)

 2

 -

 -

 -

 2

 -

Gulf of Mexico

 3

 3

 3

 3

 6

 6

Totals

 5

 3

 3

 3

 8

 6

 

(1)

Deep water rigs operate on floating facilities and shallow water rigs operate on fixed facilities.

(2)

Rigs are idle, stacked on land and not in state waters.

 

The following table sets forth certain information concerning our international land drilling rigs as of September 30, 2018:

 

 

 

 

 

 

 

 

 

 

 

 

International Land Fleet

 

AC (FlexRig3)

AC (FlexRig4)

Other AC

SCR (1)

Total Fleet

Current

Total

Rigs

Total

Rigs

Total

Rigs

Total

Rigs

Total

Rigs

Location

Available

Contracted

Available

Contracted

Available

Contracted

Available

Contracted

Available

Contracted

Argentina

11

11

 4

 4

 -

 -

 4

 -

19

15

Colombia

 2

 2

 3

 -

 1

 1

 2

 2

 8

 5

Bahrain

 -

 -

 3

 1

 -

 -

 -

 -

 3

 1

U.A.E.

 2

 -

 -

 -

 -

 -

 -

 -

 2

 -

Totals

15

13

10

 5

 1

 1

 6

 2

32

21

 

(1)

During the fourth quarter of fiscal year 2018, we ceased operations in Ecuador. On October 1, 2018, we executed a sales agreement with respect to the six conventional rigs present in the country, pursuant to which the rigs, together with associated equipment and machinery will be sold to a third party to be recycled. Prior to the sale that was executed on October 1, 2018, certain components of these rigs that are not subject to the sale agreement were transferred to the United States. As such, these rigs have been excluded from the table.

6


 

Contract Drilling

General

We are the largest provider of advanced technology AC drive land rigs in the Western Hemisphere. Operating principally in North and South America, we specialize in shale and unconventional resource plays drilling challenging and complex wells in oil and gas producing basins in the United States and in international locations. In the United States, we have a diverse mix of customers consisting of large independent, major, mid-sized and small oil companies that are focused on unconventional shale basins. In South America, our customers primarily include major international and national oil companies. We don’t operate any mechanical rigs.

Revenue from individual customers that are 10% or more of our total revenues are as follows:

 

 

 

 

 

 

 

 

 

 

(In thousands)

2018

 

2017

 

2016

EOG Resources, Inc.

$

258,194

 

$

163,582

 

$

124,262

 

 

The following table presents our average active rigs per day (a measure of activity and utilization over the fiscal year) and average utilization for the fiscal years 2018, 2017, and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended September 30,

 

 

U.S. Land

 

Offshore

 

International Land

 

 

    

2018

    

2017

    

2016

    

2018

    

2017

    

2016

    

2018

    

2017

    

2016

 

Average active rigs per day

 

213.6

 

156.5

 

101.0

 

5.6

 

6.2

 

7.4

 

18.3

 

13.6

 

14.7

 

Average utilization (1)

 

61

%  

45

%  

30

%  

70

%  

74

%  

82

%  

49

%  

36

%  

39

%  

 

(1)

A rig is considered to be utilized when it is operated (or otherwise deployed for a customer) or being moved, assembled or dismantled pursuant to a drilling contract.

Our Segments

U.S. Land Segment

We believe we operate the largest technologically advanced AC drive drilling rig fleet in the United States and have a presence in most of the U.S. shale and unconventional basins. We have a leading market share in the three most active basins, which include the Permian Basin, Eagle Ford Shale, and Woodford Shale. More than 95 percent of our active rigs are drilling horizontal or directional wells. As of September 30, 2018, we had over 20 percent of the total market share in U.S. land drilling and over 40 percent of the super-spec market share in U.S. land drilling.

As of September 30, 2018, 232 of our 350 marketed rigs were under contract, 136 were under fixedterm contracts, and 96 were working well-to-well. Over the past three fiscal years, we have reinvested in our fleet, upgrading over 162 rigs to industry-leading super-spec designed to drill the most complex unconventional wells.

Our U.S. Land segment contributed approximately 83 percent ($2.1 billion) of our consolidated operating revenues during fiscal year 2018, compared with approximately 80 percent ($1.4 billion) and 77 percent ($1.2 billion) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively. In the United States, we draw our customers primarily from the major oil companies, large independent oil companies and small cap oil companies.

Offshore Segment

Our Offshore Drilling segment has been in operation since 1968 and currently consists of eight rigs, six of which are on operator-owned platforms, which operate solely in the Gulf of Mexico. We supply the rig equipment and crews and the operator who owns the platform will typically provide production equipment or other necessary facilities. Our offshore rig fleet operates on both conventional jacket style platforms and floating platforms attached to the sea floor with mooring lines, such as Spars and Tension Leg Platforms. Additionally, we provide management contract services to customer platforms where the customer owns the drilling rig.

7


 

As of September 30, 2018, six of the eight offshore rigs were under contract. Our Offshore operations contributed approximately 6 percent ($142.5 million) of our consolidated operating revenues during fiscal year 2018, compared to approximately 8 percent ($136.3 million) and 9 percent ($138.6 million) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 60 percent ($85.8 million) of offshore revenues during fiscal year 2018.

International Land Segment

Our International Land segment operates primarily in Argentina and Colombia, in addition to smaller operations in Bahrain and U.A.E. During the fourth quarter of fiscal year 2018, we ceased operations in Ecuador. As of September 30, 2018, we had 21 land rigs contracted for work in locations outside of the United States. Our International Land operations contributed approximately 10 percent ($238.4 million) of our consolidated operating revenues during fiscal year 2018, compared with approximately 12 percent ($213.0 million) and 14 percent ($229.9 million) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively.

Argentina As of September 30, 2018, we had 19 rigs in Argentina. Revenues generated by Argentine drilling operations contributed approximately 8 percent ($190.0 million) of our consolidated operating revenues during fiscal year 2018 compared to approximately 9 percent ($157.3 million) and 10 percent ($159.4 million) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 7 percent of our consolidated operating revenues and approximately 71 percent of our international operating revenues during fiscal year 2018. The Argentine drilling contracts are primarily with large international or national oil companies. As of September 30, 2018, we believe we had approximately 20 percent of total market share and approximately 40 percent of the unconventional horizontal drilling market share in Argentina.

Colombia As of September 30, 2018, we had eight rigs in Colombia. Revenues generated by Colombian drilling operations contributed approximately 2 percent ($38.8 million) of our consolidated operating revenues in fiscal year 2018, compared to approximately 2 percent ($37.6 million) and 1 percent ($20.5 million) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively. Revenues from drilling services performed for our two largest customers in Colombia totaled approximately 1 percent of our consolidated operating revenues and approximately 13 percent of our international operating revenues during fiscal year 2018. The Colombian drilling contracts are primarily with large international or national oil companies.

Other Operations

Other Operations include additional non-reportable operating segments.  Revenues included in “other” consist of drilling technology services as well as real estate rental income. Our drilling technology focuses on improving the efficiency and accuracy of drilling operations and wellbore quality through the following service offerings: (i) a proprietary Bit Guidance System™, offered as a service through MOTIVE, which we acquired in June 2017, and (ii) 3D geomagnetic reference modeling and measurement while drilling survey correction services, offered through MagVAR, which we acquired in December 2017.

We also own, develop and operate limited commercial real estate properties. Our real estate investments, which are located exclusively within Tulsa, Oklahoma, include a shopping center, multitenant industrial warehouse properties, and undeveloped real estate.

We have established a wholly-owned captive insurance company to insure various risks of our operating subsidiaries. The amount of actual cash investments held by the captive insurance company varies, depending on the amount of premiums paid to the captive insurance company, the timing and amount of claims paid by the captive insurance company, and the amount of dividends paid by the captive insurance company.

Internal Restructuring

We may reorganize our active International Land drilling operations and our Offshore Drilling operations into separate, wholly-owned subsidiaries of Helmerich & Payne, Inc. through an internal restructuring transaction. This may result in the transfer of certain assets from Helmerich & Payne International Drilling Co. to other wholly-owned subsidiaries of Helmerich & Payne, Inc. We believe that reorganizing these businesses into separate wholly-owned subsidiaries of Helmerich & Payne, Inc. will foster operational efficiency, simplify our organizational structure and provide additional clarity in our internal reporting.  Any such internal reorganization would not impact our segment reporting.

8


 

Rigs, Equipment, R&D, and Facilities

During the late 1990’s, we undertook a strategic initiative to develop a new generation drilling rig that would be the safest, fastest-moving and highest performing rig in the land drilling market. Our first “FlexRig®” entered the market in 1998. The original 18 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. From 2002 to 2004, we designed, built and delivered 32 of the next generation, AC drive rigs, known as “FlexRig3,” which incorporated new drilling technology and improved the safety and environmental design. The FlexRig3s found immediate success by delivering higher value wells to the customer. This was the beginning of the AC land rig revolution. We also changed our pricing and contracting strategy, and beginning in 2005, all new FlexRigs were built supported by a firm contract and attractive returns. To date, we have built 232 FlexRig3’s and our strategy included building them under a term contract with substantial payback at attractive rates of return. An important part of our strategy was to design a rig that could support continuous improvement through upgrade capability of the hardware and software on the rigs to take advantage of technology improvements and lengthening the industry rig replacement cycle. These upgrades included, but were not limited to, enhanced drilling control systems and software, skid and walking systems for drilling multiple well pads, 7,500 psi mud systems, set back capacity to accommodate the pipe that the longer laterals demanded, and additional mud system capacity.

A strategic advantage is our ability to utilize our AC rig design and operational and engineering expertise to exploit different well depths and designs that customers demand. In 2006, we introduced the FlexRig4, which was designed to efficiently drill shallower wells on multi-well pads. The FlexRig4 design offers two options that include trailerized or multi-well pad drilling capability, both of which incorporate additional environmental and safety by design improvements. While the trailerized FlexRig4 design provides for more efficient moves between individual well pads, the multi-well pad design uses a skidding capability that allows for drilling multiple wells from a single pad, which results in a reduced environmental impact and increased production from a smaller footprint.

In 2011, we announced the introduction of the FlexRig5. The FlexRig5 was designed for deeper wells than the FlexRig4 and long lateral drilling of multiple wells from a single location, and is designed for drilling horizontally in unconventional shale reservoirs. The new design preserves the key performance features of the FlexRig3 design, but adds a bi-directional skidding system and equipment capacities suitable for wells in excess of 25,000 feet of measured depth.

We have an important advantage in the super-spec space in that our FlexRig3’s and FlexRig5’s are ideally suited for super-spec upgrades, and we have more upgradeable rigs than our competitors. Going forward, we will continue to focus on investing capital to grow the size of our super-spec fleet. During fiscal year 2018, we converted two FlexRig4’s to super-spec capacity and upgraded 52 of our other rigs to super-spec, including 51 FlexRig3’s and one FlexRig5. As of September 30, 2018, we held over 40 percent of the super-spec market share in U.S. land drilling. Our competency in design and construction allows us to efficiently upgrade our rigs to super-spec, and our financial strength enables us to continue such upgrades as long as market demand for such rigs remains high and there remains a supply of economically viable super-spec upgradable rigs. We do these upgrades at our fabrication facility in Houston, Texas.

Years of designing and building our fleet of AC drive FlexRigs has given us many competitive benefits. One key advantage is fleet uniformity. We have overseen the design and assembly of all of our AC FlexRigs, and our different rig classes share many common components.  We co-designed the control systems for our rigs and have the right to make any changes or modifications to those systems that we desire. A uniform fleet creates an adaptive environment to reach maximum efficiency for employees, equipment and technology and is critical to our ability to provide consistent, safe and reliable operations in increasingly complex basins. In addition, our fleet has greater scale than any other competitor, which enables us to upgrade our existing FlexRigs to super-spec in a capital efficient way. High levels of uniformity in crew training and rotation, as well as parts and supplies improve our cost-effectiveness, and our ability to control and remove safety exposures across a more standard fleet allows us to deliver higher performance in a safer and more reliable manner for the customer. Further, our fleet is supported by a Company-owned supply chain that provides standardized materials directly to the rigs from our regional warehouses.

A long-standing challenge in our industry is providing high quality and consistent results. In addressing the challenge of providing safe, high quality and consistent results, we utilize process excellence techniques that are developed internally. We provide experienced drilling and maintenance support for our operations, which provides value by reducing nonproductive time in our operations and improving drilling performance through our Center of Excellence (“COE”). The COE is manned 24 hours a day, seven days a week, with the ability to monitor and detect trends in drilling and drilling services performance onboard our rigs. Our monitoring group within the COE provides real-time help and feedback to our wellsite employees, as well as our customers, to fully optimize our operational performance. Additionally,

9


 

our COE has a staff of performance engineers that work with our customers to enhance drilling program execution and overall drilling performance. The monitoring group and our performance engineers capture our drilling work steps to ensure we have high quality and reliable results for our customers.

We currently have three facilities that provide vertically integrated solutions for drilling rig manufacturing, upgrades, retrofits and modifications, as well as overhauling, recertification, and repairs as it relates to our rigs and equipment. These facilities all utilize lean manufacturing processes to enhance quality and efficiency as well as provide important insights in the maintenance and wear of equipment on our rigs. We have a fabrication and assembly facility near Houston, Texas as well as a fabrication facility near Tulsa, Oklahoma. Additionally, we lease an industrial facility near Tulsa, Oklahoma that we utilize for FlexRig equipment repairs and overhauls.

During fiscal year 2018, we commercialized our FlexApp services, which include several new software applications that layer on top of our FlexRig drilling control systems. These applications are enabled by our uniform digital fleet, and are designed to provide additional value to our customers’ well programs by providing a platform for machine-human collaboration during the drilling process to improve efficiency. The FlexApps can help play an important role in deploying our strategy as we strive towards autonomous drilling. The FlexApps that are currently in use include the following:

 

 

 

Application Name

    

Description

FlexTorque™

 

Hardware and software designed to decrease downhole drilling vibration and "slip-stick" during drilling. This increases drilling efficiencies and extends bit and downhole tool life eliminating customers' costly nonproductive time.

FlexConnect™

 

Software to optimize slip-to-slip connection time, which reduces customer nonproductive time and improves rig performance consistency across our rig fleet.

Flex-Oscillator 2.0™

 

Rig control software that automates drill string rotation during directional "slide" operations, which reduces downhole drag and the potential for stuck pipe. Additionally, it allows for more effective directional drilling.  

FlexB2D™

 

Software to engage and disengage the bit during connections in an established controlled and consistent manner allowing for better bit and downhole tool life, better drilling parameters and less costly bit trips out of the hole.

FlexDrill 1.0™

 

Software licensed from ExxonMobil to maximize the bit's rate of penetration, which we have automated, allowing the drilling control system to achieve the ideal mechanical specific energy at the bit.

FlexGuide™

 

Powered by both MOTIVE and MagVAR software that utilizes a drill bit guidance system and geomagnetic survey correction, respectively, allowing for higher quality wellbores with a scalable, repeatable data driven platform approach and a reduction of surveying uncertainty by 50-60% while increasing horizontal well economics and reducing risk. 

 

We have historically offered ancillary services, which are now referred to as FlexServices™. These services include trucking, surface equipment, casing running tool services and pipe rental.

 

Markets and Competition

Our business largely depends on the level of capital spending by oil and gas companies for exploration and production activities. Sustained increases or decreases in the prices of oil and natural gas generally have a material impact on the exploration and production activities of our customers. As such, significant declines in the prices 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 range between $50 and $77 per barrel in fiscal year 2018. The decline in prices continued to negatively affect demand for services in fiscal year 2016 but showed some recovery in fiscal years 2017 and 2018.  As of September 30, 2018, we had 259 rigs under contract, compared to 218 and 118 rigs under contract as of September 30, 2017 and 2016, respectively. 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 10K.

Our industry is highly competitive and we strive to differentiate our services based upon the quality of our FlexRigs and our engineering design expertise, operational efficiency, software technologies, and safety and environmental awareness. The number of available rigs generally exceeds demand in many of our markets, resulting in significant price competition. With respect to the super-spec market, however, the industry tends to have utilization closer to 100 percent and higher pricing. We compete against many drilling companies, some of whom 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

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

Drilling Contracts

Our drilling contracts are obtained through competitive bidding or as a result of direct negotiations with customers. Our contracts vary in their terms and rates depending on the nature of the operations to be performed, the duration of the work, the amount and type of equipment and services provided, the geographic areas involved, market conditions and other variables. Our contracts often cover multiwell and multiyear projects. Except for a limited number of rigs operated under master agreements, each drilling rig operates under a separate drilling contract.

During fiscal year 2018, substantially all of our drilling services were performed on a “daywork” contract basis, under which we charged a 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 may also enter into contracts where we charge a fixed rate per foot of hole drilled to a stated depth, with a fixed rate per day for the remainder of the hole. Contracts performed on a “footage” basis generally involve a greater element of risk to the contractor compared to contracts performed on a “daywork” basis. Also, we may enter into “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 also actively pursue “performance daywork” contracts. These contracts typically have a lower dayrate portion and give us the opportunity to share in the well cost savings based on meeting or exceeding certain key performance indicators that are mutually agreed on by ourselves and our customers.

The duration of our drilling contracts are generally either “welltowell” or for a fixed term. “Welltowell” contracts can be terminated at the option of either party upon the completion of drilling of any one well. Fixed-term contracts generally have a minimum term of at least six months up to multiple years. These contracts customarily provide for termination at the election of the customer, but may include an “early termination payment” to be paid to us if the contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances such as destruction of a drilling rig, 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 of the rig.

Contract Backlog

As of September 30, 2018 and 2017, our drilling contract backlog, being the expected future dayrate revenue from executed contracts with original terms of 365 days or greater, was $1.1 billion and $1.3 billion, respectively. The decrease in backlog at September 30, 2018 from September 30, 2017 is primarily due to contract pricing modifications and a change in certain contracts from fixed term to well-to-well related to our international land segment in fiscal year 2018. Approximately 26 percent of the total September 30, 2018 backlog is reasonably expected to be filled in fiscal year 2020 and thereafter.  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. Upon adoption of Accounting Standard Update No. 2014-09, Revenue from Contracts with Customers (Topic 606): Revenue from Contracts with Customers, we will be required to disclose our drilling contract backlog within the Notes to the Consolidated Financial Statements included in Part II, Item 8– “Financial Statements and Supplementary Data” of this report.

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The following table sets forth the total backlog by reportable segment as of September 30, 2018 and 2017, and the percentage of the September 30, 2018 backlog reasonably expected to be filled in fiscal year 2020 and thereafter:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percentage Reasonably

 

 

 

Total Backlog

 

Expected to be Filled in

 

 

 

Revenue

 

Fiscal Year 2020

 

Reportable Segment

    

9/30/2018

    

9/30/2017

    

and Thereafter

 

 

 

(in billions)

 

 

 

U.S. Land

 

$

0.9

 

$

0.9

 

24.9

%

Offshore

 

 

 —

 

 

 —

 

 —

%

International Land

 

 

0.2

 

 

0.4

 

31.0

%

 

 

$

1.1

 

$

1.3

 

  

 

 

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. In addition, contract terms could be modified or extended after the initial contract is signed. Accordingly, the actual amount of revenue earned may vary from the backlog reported. For further information, see Item 1A—“Risk Factors — Our current backlog of contract drilling revenue may continue to decline and may not be ultimately realized as fixedterm contracts may in certain instances be terminated without an early termination payment.”

Employees

One of our core values is striving for a culture that embraces organizational health and actively controlling and removing exposures (“C.A.R.E.”) for the safety and wellbeing of our employees. Our employees actively C.A.R.E. for those around them, as demonstrated through, among other things, employee support of the H&P Way Fund, our Company’s charitable fund that provides assistance to employees and their families experiencing unexpected and unavoidable emergencies. This is fundamental to our commitment to take care of our employees and to make the communities where they live and work better places. We pride ourselves on being a service company and focus on maintaining a service attitude for customers. We have a long history of emphasizing creativity and seek to maintain an innovative spirit in all facets of doing business. Our employees are strong team players who work closely with our customers to deliver value for customers and shareholders. Designing, building, upgrading, deploying, and operating rigs requires hard working teams willing to teach, learn, and communicate to achieve a high level of performance on a consistent and repeatable basis.

As of September 30, 2018, we had 8,780 employees within the United States (12 of whom were parttime employees) and 997 employees in international operations. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be robust. None of our U.S. employees are represented by a union. However, some of our international employees are unionized.

Insurance and Risk Management

Our operations are subject to a number of operational risks, including personal injury and death, 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. Furthermore, 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.

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, or subcontractors and/or suppliers or by reason of state anti-indemnity laws. Our customers and other third parties may also dispute these indemnification provisions, or we may be unable to transfer these risks to our drilling customers or other third parties by contract or indemnification agreements.

We insure land rigs and related equipment at values that approximate the current replacement costs 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.

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We have insurance coverage for comprehensive general liability, automobile liability, workers’ 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 workers’ compensation, general liability and automobile liability programs. We self-insure 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.

Our insurance may not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations. Our coverage includes aggregate policy limits. As a result, we retain the risk for any loss in excess of these limits. No assurance can be given that all or a portion of our coverage will not be cancelled, 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.

Government Regulations

Our operations are subject to a variety of national, state, local and international environmental, health and safety laws, regulations, treaties and conventions. We monitor our compliance with environmental regulations in each country of operation and have seen an increase in environmental regulation. We have made and will continue to make the required expenditures to comply with current and future environmental requirements. We do not anticipate that compliance with currently applicable environmental rules and regulations and required controls will significantly change our competitive position, capital spending or earnings during 2019, as these regulations are generally imposed on exploration and production companies instead of contract drilling companies. We believe we are in material compliance with applicable environmental rules and regulations and that the cost of such compliance is not material to our business or financial condition. For a more detailed description of the environmental rules and regulations applicable to our operations, see Item 1A— “Risk Factors — Failure to comply with or changes to governmental and environmental laws could adversely affect our business.”

Sustainability

At the direction of the oil and gas exploration and production companies we work with, we contract to drill oil and gas wells. The exploration and production companies determine whether and when to extract those resources from the ground, following completion of the well. Below are summaries of what we do and what we do not do, the latter of which is provided because it is often incorrectly assumed that our operations overlap with exploration and production, midstream and downstream parts of the oil and gas sector in ways they do not.

What We Do

·

Strive to make drilling for oil and gas safer and more efficient

·

Build and renovate drilling rigs at three industrial facilities in Texas and Oklahoma

·

Oversee drilling operations on our rigs on customer sites

·

Drill predominantly on-shore in the U.S.

 

What We Do Not Do

·

Hydraulic fracturing

·

Buy, lease, prepare, manage or restore land on which rigs are located, or have responsibility for the protection of wildlife or biodiversity of our customers’ properties

·

Pump or extract oil or gas from the ground

·

Procure, transport or pump water underground, or treat, store, manage or remove waste water from the drilling sites, or arrange for its disposal

·

Assume responsibility for the prevention of fugitive releases or emissions associated with the oil and gas exploration or production process

·

Engage in oil and gas transport, refining or storage

·

Engage in downstream operations

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Thus, many of the environmental and safety risks associated with the oil and gas sector fall outside the scope of our operations and areas of responsibility. Our most critical responsibility is therefore the safety of our employees and the employees of our customers. To be successful, we strive to be leaders in innovation, technology, cost competitiveness, safety, customer service, relationship tending, and reputation management.  To maintain this leadership edge and generate shareholder value, we invest in our employees, customers, communities, and other stakeholders in the ways listed below.

 

Recruiting

Our recruiting practices and decisions on whom to hire are among our most important activities. In addition to traditional school recruiting events, we utilize social media and local job fairs across the U.S. to find diverse, motivated and responsible employees.

Education and Training

The employment opportunities we offer are key to successful recruiting.  To attract motivated employees, we rely on our organizational development team. This team offers talent management, mentoring programs, change management initiatives, and diversity, inclusion and succession management programs, as well as educational assistance programs and ongoing training and development opportunities.

Health and Welfare

We support our employees’ and their families’ health with full medical, dental, and vision insurance for employees and their families, life insurance and long-term disability plans, and health care and dependent care flexible spending accounts. We foster teamwork and a sense of community amongst our employees through our H&P Way Fund that provides assistance to employees and their families experiencing emergencies.

Retirement

 We provide a 401(k) plan with a company match.

Safety

All of our safety programs are designed to comply with applicable laws and industry standards as well as to benefit employees, customers and communities. We have a dedicated Health, Safety and Environmental (“HSE”) function overseen by senior executives and implemented at every H&P drilling rig and facility worldwide. Our safety-focused C.A.R.E. program promotes employee and customer safety and well-being.  In addition, we incorporate safety features into our rig designs through our Safety by Design program. The success of our safety initiatives, including our C.A.R.E. and Safety by Design programs, and the Company’s performance with respect to safety metrics are important elements of the compensation of our executives, as discussed further in our proxy statement. 

Our Safety by Design program helps us:

·

Identify and work to eliminate hazards in the rig design phase

·

Use leading-edge technology to enhance efficiency and thus reduce the number and severity of safety risks

·

Standardize designs, which can reduce the variability in the types of rigs we use to allow our employees to have a greater familiarity with the rigs than would be achieved if they had to master a wider variety of rig types

·

Design and configure loads and interconnects with rig moves in mind. By striving to integrate equipment to the greatest extent possible, we minimize risks associated with moves and risks associated with double handling

 

Our COE promotes process excellence and safety by providing experienced drilling and maintenance real-time support around the clock to our operations.  Our COE Call Center and Real-Time Monitoring Groups are staffed with experienced systems technicians who work with field personnel to leverage each group’s knowledge in troubleshooting rig

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events.  In addition, experienced engineers monitor safety critical alarms and perform daily safety performance and data analysis throughout the fleet.

In the event that an incident does occur, we have developed and implemented a comprehensive Emergency Management and Crisis Response Plan to help ensure H&P has the ability to respond promptly and effectively to the most severe adverse situations or crises.

Environmental Management

H&P does not itself lease properties used for the operations of its customers.  However, many of our customers operate in regions that have stringent safety and environmental laws and regulations, with which we comply as applicable. The standards we employ include:

·

Applying industry-accepted environmental best practices

·

Minimizing rig physical footprints, and using technology to configure drilling rigs, where appropriate, for space efficient multi-well pads, all to minimize the impact on the environment in which we and our customers operate

·

Conversion of many of our rigs to allow partial substitution of cleaner burning natural gas as a fuel source to reduce air emissions

·

Upgrading our drilling rig fleet to utilize AC drive power and control systems which are more energy efficient and have significantly lower noise levels as compared to SCR and mechanical drilling rigs

·

Using a variety of recycling and other initiatives in our facilities and operations to minimize waste

 

Ethics and Compliance

 

We expect corporate, professional and personal responsibility from each of our employees as well as compliance with high ethical standards to achieve operational excellence. In addition to the corporate governance oversight provided by the Board of Directors and its committees, management observes and enforces our Code of Business Conduct and Ethics (“Code”) described on our website. Our Code provides employees with the tools to make consistent, ethical decisions and emphasizes the duty to report any concerns or violations.

In addition to our Code, we have and enforce a Code of Ethics for Principal Executive Officers and Senior Financial Officers and a Foreign Corrupt Practices Act Compliance Policy. 

We believe this focus on finding and getting the best out of our people, our programs, our standards and our technology collectively support our operations, our reputation and our returns.

 

Available Information

Our website is located at www.hpinc.com. Annual reports on Form 10K, quarterly reports on Form 10Q, current reports on Form 8K, 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 such materials to, the SEC. The information contained on our website, or accessible from our website, is not incorporated into, and should not be considered part of, this annual report on Form 10K or any other documents we file with, or furnish to, the SEC. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with 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.

Investors and others should note that we announce material financial information to our investors using our investor relations website (https://helmerichandpayneinc.gcs-web.com/), SEC filings, press releases, public conference calls and webcasts. We use these channels as well as social media to communicate with our stockholders and the public about our company, our services and other issues. It is possible that the information we post on social media could be deemed to be material information. Therefore, we encourage investors, the media, and others interested in our company to review the information we post on the social media channels listed on our investor relations website.

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Item 1A.  RISK FACTORS

 

An investment in our securities involves a variety of risks. In addition to the other information included and incorporated by reference in this annual report and the risk factors discussed elsewhere in this report, the following risk factors should be carefully considered, as they could have a material adverse effect on our business, financial condition and results of operations. There may be other additional risks, uncertainties and matters not presently known to us or that we believe to be immaterial that could nevertheless have a material adverse effect on our business, financial condition and results of operations.

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

Our business depends on the conditions of the land and offshore oil and natural gas industry. Demand for our services and the rates we are able to charge for such services depend 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 continued to fluctuate in fiscal year 2018, but have settled into a range between approximately $50 and $77 per barrel.   Oil prices began rebounding in February 2016, and we began experiencing increased demand for our services in May 2016.  Nevertheless, both the industry’s active rig count and our active rig count have remained below the peak drilling activity level reached in 2014 when oil prices were significantly higher.  As of November 8, 2018, 236 rigs included in our U.S. Land segment were under contract, of which 146 were fixed term and 90 were well-to-well. In the event oil prices become 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 and production levels can be volatile and are impacted by many factors beyond our control, including:

·

the domestic and foreign supply of, and demand for, oil, natural gas and related products;

·

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

·

uncertainty in capital and commodities markets and the ability of oil and natural gas producers to access capital;

·

the worldwide economy;

·

expectations about future oil and natural gas prices and production levels;

·

the availability of and constraints in pipeline, storage and other transportation capacity in the basins in which we operate, including, for example, takeaway constraints experienced in the Permian Basin;

·

actions of The Organization of Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production levels, including announcements of potential changes to such levels;

·

the levels of production of oil and natural gas of non-OPEC countries;

·

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

·

tax policies of the United States and other countries involved in global energy markets;

·

political and military conflicts in oil producing regions or other geographical areas or acts of terrorism in the United States or elsewhere;

·

technological advances that are related to oil and natural gas recovery or that affect the global demand for energy;

·

the development and exploitation of alternative energy sources;

·

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

·

local and international political, economic and weather conditions, especially in oil and natural gas producing countries;

·

laws and governmental regulations affecting the use of oil and natural gas; and

·

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

The level of land and offshore exploration, development and production activity and the prices of oil and natural gas are volatile and are 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 customers’ expectations of

16


 

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 would likely have a material adverse effect on our business, financial condition and results of operations.

Global economic conditions and volatility in oil and gas prices may adversely affect our business.

Global economic conditions and/or 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. Furthermore, our customers, vendors and/or suppliers may be unable to access financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations. An economic slowdown or recession in the United States or in any other country that significantly affects the supply of or demand for oil or natural gas could negatively impact our operations and therefore adversely affect our results. Challenging economic conditions 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.

The contract drilling business is highly competitive. Competition in contract drilling involves such factors as price, efficiency, condition, type and operational capability of equipment, reputation, operating safety, environmental impact, customer relations, rig availability and excess rig capacity in the industry. 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, which could result in an oversupply of rigs in any region, leading to increased price competition.

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. Furthermore, in the event that commodity prices decline, the strategy of differentiation may be less effective if the lower demand for drilling and related technology services intensifies price competition and diminishes the importance of other factors.

We periodically seek to increase the prices on our services to offset rising costs and to generate higher returns for our stockholders. However, we operate in a very competitive industry and we are not always successful in raising or maintaining our existing prices. With the active rig count below the peak seen in 2014 and many rigs, including highly capable AC rigs, still idle, there is considerable pricing pressure in the industry. Even if we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset rising costs without adversely affecting our activity levels. The inability to maintain our pricing and to increase our pricing as costs increase could have a material adverse effect on our business, financial position, results of operations and cash flows.

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. Following such a downturn, there may be substantially more drilling rigs available than necessary to meet demand as oil and natural gas prices, as well as drilling activity, rebound. In the event of a glut of available and more competitive drilling rigs, we may continue to experience difficulty in replacing fixedterm contracts, extending expiring contracts or obtaining new contracts in the spot market, and new contracts may contain lower dayrates and substantially less favorable terms. As such, we may have difficulty sustaining or increasing rig utilization and profit margins in the future, which 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 and it may become necessary to incur higher levels of capital expenditures in order to keep pace with the bifurcation of rigs in 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 dayrates than the lower specification drilling rigs (e.g., SCR rigs). In addition, a significant number of lower specification rigs are being stacked and/or removed from service. As a result of this demand for high-spec rigs, 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.

Although we take measures to ensure that we develop and 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 or unscheduled delays in delivery of equipment or materials, inadequate levels of skilled labor, 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 costeffective manner suitable to customer needs, demand for our services could decline and we could lose market share. One or more technologies that we may implement in the future may not work as we expect and our business, financial condition, results of operations and reputation could be adversely affected as a result. Additionally, new technologies, services or standards could render some of our services, drilling rigs or equipment obsolete, which could reduce our competitiveness and have a material adverse impact on our business, financial condition and results of operations.

Our drilling related 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 operations are subject to the many hazards inherent in the business, including inclement weather, blowouts, explosions, well fires, loss of well control, pollution, and reservoir damage. These hazards could cause significant environmental damage, personal injury and death, suspension of operations, serious damage or destruction of equipment and property and substantial damage to producing formations and surrounding lands and waters. An accident resulting in significant environmental damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local authorities. Such an accident and subsequent crisis management efforts could cause us to incur substantial expenses in connection with investigation and remediation as well as cause lasting damage to our reputation. 

Our Offshore Drilling operations are also subject to potentially significant risks and liabilities attributable to or resulting from adverse environmental conditions, 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 Drilling operations may also be negatively affected by a blowout or an uncontrolled release of oil or hazardous substances 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, which may increase with any climate change. See below “— The physical effects of climate change and the regulation of greenhouse gases and climate change could have a negative impact on our business.” Damage caused

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by high winds and turbulent seas could potentially curtail operations on our 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 also own 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 and could be exposed to damage or disruption by hurricanes and other extreme weather conditions, including coastal flooding, which in turn could affect our business, financial condition and results of operations.

It is customary in our business to have mutual indemnification agreements with customers on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property. 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 antiindemnity 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 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.

We insure land 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, workers’ 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 workers’ compensation, general liability and automobile liability programs. The Company selfinsures 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 losses and liabilities that could result from our operations. Our coverage includes aggregate policy limits. As a result, we retain the risk for any loss in excess of these limits. No assurance can be given that all or a portion of our coverage will not be cancelled during fiscal year 2019, 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.

The physical effects of climate change and the regulation of greenhouse gases and climate change could have a negative impact on our business.

The physical and regulatory effects of climate change could have a negative impact on our operations, our customers’ operations and the overall demand for our products. 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, regional, national and international regulatory bodies on GHG emissions and climate change issues. Legislation to regulate GHG emissions has periodically been introduced in the U.S. Congress and such legislation may be proposed in the future. In addition, in December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (the “UNFCCC”) in Paris, France in creating an agreement (the “Paris Agreement”) that requires member countries to review and “represent a progression” in their intended nationally determined GHG contributions, which set GHG emission reduction goals every five years beginning in 2020. The agreement entered into full force in November 2016. On June 1, 2017, the President of the United States announced that the U.S. planned to withdraw from the Paris Agreement and to seek negotiations to either reenter the Paris Agreement on different terms or establish a new

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framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The aim of the Paris Agreement was to hold the increase in the average global temperature to well below 2ºC (3.6ºF) above pre-industrial levels with efforts to limit the rise to 1.5ºC (2.7ºF) to protect against the more severe consequences of climate forecasted by scientific studies. These consequences include increased coastal flooding, droughts and associated wild fires, heavy precipitation events, stresses on water supply and agriculture, increased poverty, and negative impacts on health. In connection with the decision to adopt the Paris Agreement, the UNFCCC invited the Intergovernmental Panel on Climate Change (the “IPCC”) to prepare a special report focused on the impacts of an increase in the average global temperature of 1.5ºC above pre-industrial levels and related GHG emission pathways. The 2018 IPCC Report concludes that the measures set forth in the Paris Agreement are insufficient and that more aggressive targets and measures will be needed. The 2018 IPCC Report indicates that GHGs must be reduced from 2010 levels by 45 percent by 2030 and 100 percent by 2050 to prevent global warming of 1.5ºC above pre-industrial levels.

It is not possible at this time to predict the timing and effect of climate change or to predict the effect of the Paris Agreement or whether additional GHG legislation, regulations or other measures will be adopted. However, more aggressive efforts by governments and non-governmental organizations to reduce GHG emissions appear likely based on the findings set forth in the 2018 IPCC Report and 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 negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide. An increased focus by the public on the reduction of GHG emissions as well as the results of the physical impacts of climate change could affect the demand for our customers’ products and have a negative effect on our business.

Beyond financial and regulatory impacts, the projected severe effects of climate change have the potential to directly affect our facilities and operations and those of our customers. See above “—Our drilling related 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 business is subject to cybersecurity risks.

Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Cybersecurity risks 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, interruptions in communication, loss of our intellectual property or theft of our FlexRig and other sensitive or proprietary technology (which could have a negative impact on our ability to compete), loss or damage to our data delivery systems, or other electronic security, including with our property and equipment. These cybersecurity risks could disrupt our operations, negatively impact our ability to compete and result in injury to our reputation, downtime, loss of revenue, and increased costs to prevent, respond to or mitigate cybersecurity events. It is possible that our business, financial and other systems could be compromised, which could go unnoticed for a prolonged period of time. While various procedures and controls can be utilized to mitigate exposure to such risk, cyber incidents and attacks are evolving and unpredictable. Additionally, customers or third parties upon whom we rely face similar threats, which could directly or indirectly impact our business and operations. The occurrence of a cyber-incident or attack could have a material adverse effect on our business, financial condition and results of operations.

Our acquisitions, dispositions and investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.

We continually seek opportunities to maximize efficiency and value through various transactions, including purchases or sales of assets, businesses, investments, or joint venture interests. For example, in December 2017, we completed the acquisition of Magnetic Variation Services, LLC. We also completed a merger transaction with MOTIVE 

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Drilling Technologies, Inc. in June 2017. These strategic transactions, among others, are intended to (but may not) result in the realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or income, or the reduction of risk. Acquisition transactions may use cash on hand or be financed by additional borrowings or by the issuance of our common stock. These transactions may also affect our liquidity, consolidated results of operations and consolidated financial condition.

 

These transactions also involve risks, and we cannot ensure that:

 

·

any acquisitions we attempt will be completed on the terms announced, or at all;

·

any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated benefits;

·

any acquisitions would be successfully integrated into our operations and internal controls;

·

the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, including under the FCPA, or that we will appropriately quantify the exposure from known risks;

·

any disposition would not result in decreased earnings, revenue, or cash flow;

·

use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other uses; or

·

any dispositions, investments, or acquisitions, including integration efforts, would not divert management resources.

 

We have allocated a portion of the purchase price of certain acquisitions to goodwill and other intangible assets. Generally, the amount allocated is the excess of the purchase price over the net identifiable assets acquired. At September 30, 2018, we had goodwill of $64.8 million and other intangible assets of $73.2 million. If we experience future negative changes in our business climate or our results of operations such that we determine that goodwill or intangible assets are impaired, we will be required to record impairment charges with respect to such assets.

During the fourth quarter of fiscal year 2018, we  recorded goodwill and intangible assets impairment losses of $5.6 million related to the TerraVici reporting unit, one of our technology reporting units, which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018. Our goodwill impairment analysis performed on our remaining technology reporting units in the fourth quarter of fiscal years 2018 and 2017 did not result in impairment charges.

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, or a third party’s infringement of our rights, including patent rights. The majority of the intellectual property rights relating to our drilling rigs and technology services 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 of intellectual property rights relating to equipment owned or used by us, we may lose access to important equipment or technology, be required to cease use of some equipment or technology be forced to modify our drilling rigs or technology, or be required to pay license fees or royalties for the use of equipment or technology. In addition, we may lose a competitive advantage in the event we are unsuccessful in enforcing our rights against third parties. As a result, any technology disputes involving us or our customers or vendors could have a material adverse impact on our business, financial condition and results of operations.

 

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

Unexpected or 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 create unforeseen liabilities, reduce our ability to provide drilling and related technology services, reduce demand for our services, or make it more difficult or costly to provide services, any of which may ultimately have a material adverse effect on our business, financial condition and results of operations.

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

The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar antibribery 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 antibribery laws may conflict with local customs and practices and impact our business. Although we have programs in place requiring compliance with antibribery legislation, any failure to comply with the FCPA or other antibribery 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.

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 services we provide.

 

We do not engage in any hydraulic fracturing activities. However, 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 oil and gas development, including 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. 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 services we provide. For example, the Environmental Protection Agency has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels. Widespread regulation significantly restricting or prohibiting hydraulic fracturing or other drilling activity by our customers could have a material adverse impact on our business, financial condition and results of operations. Further, we conduct drilling activities in numerous states, including Oklahoma, where seismic activity may occur. In recent years, Oklahoma has experienced an increase in earthquakes. Although the extent of any correlation has been and remains the subject of studies of both federal and state agencies, some parties believe that there is a correlation between hydraulic fracturing related activities and the increased occurrence of seismic activity. As a result, 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, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide.

Government policies, mandates, and regulations specifically affecting the energy sector and related industries, regulatory policies or matters that affect a variety of businesses, taxation polices, and political instability could adversely affect our financial condition and results of operations.

 

Energy production and trade flows are subject to government policies, mandates, regulations, and trade agreements. Governmental policies affecting the energy industry, such as taxes, tariffs, duties, price controls, subsidies, incentives, foreign exchange rates, and import and export restrictions, can influence the viability and volume of production of certain commodities, the volume and types of imports and exports, whether unprocessed or processed commodity products are traded, and industry profitability.  For example, the decision of the U.S. government to impose tariffs on certain Chinese imports and the resulting retaliation by the Chinese government imposing a 10 percent tariff on U.S. liquefied natural gas have disrupted aspects of the energy market. Disruptions of this sort can affect the price of oil and natural gas and may cause our customers to change their plans for exploration and production levels, in turn reducing the demand for our services. Future government policies may adversely affect the supply of, demand for, and prices of oil and

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natural gas, restrict our ability to do business in existing and target markets, and adversely affect our business, financial condition and results of operations.

 

Our business, financial condition and results of operations could be affected by political instability and by changes in other governmental policies, mandates, regulations, and trade agreements, including monetary, fiscal and environmental policies, laws, regulations, acquisition approvals, and other activities of governments, agencies, and similar organizations.  These risks include, but are not limited to, changes in a country’s or region’s economic or political conditions, local labor conditions and regulations, safety and environmental regulations, reduced protection of intellectual property rights, changes in the regulatory or legal environment, restrictions on currency exchange activities, currency exchange fluctuations, burdensome taxes and tariffs, enforceability of legal agreements and judgments, adverse tax, administrative agency or judicial outcomes, and regulation or taxation of greenhouse gases.  International risks and uncertainties, including changing social and economic conditions as well as terrorism, political hostilities, and war, could limit our ability to transact business in these markets and could adversely affect our business, financial condition and results of operations.

 

Legal claims and litigation 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. We design much of our own equipment and fabricate and upgrade such equipment in facilities that we operate. We also design and develop our own technology. If such equipment or technology fails to perform as expected, or if we fail to maintain or operate the equipment properly, there could be personal injuries, property damage, and environmental contamination, which could result in claims against us. 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 impact 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.

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, which may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Additionally, during the recent period of sustained declines in oil and natural gas prices, there was a significant decline in the oil field services workforce. This has reduced the available skilled labor force available to the energy industry, which could also result in higher labor costs. 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.

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 year 2018, we received approximately 50 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 24 percent of our consolidated operating revenues from our three largest customers (including their affiliates). If one or more of our larger customers terminated their contracts, failed to renew existing contracts with us, or refused to award us with new contracts, it could have a material adverse effect on our business, financial condition and results of operations. Further, consolidation among oil and natural gas exploration and production companies may reduce the number of available customers.

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

Fixedterm 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

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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, 2018, our contract drilling backlog was approximately $1.1 billion for future revenues under firm commitments. Our contract drilling backlog may decline over time as existing contract term coverage may not be offset by new term contracts or price modifications for existing 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 contracts with national oil companies may expose us to greater risks than we normally assume in contracts with non-governmental customers.

We currently own and operate rigs and have deployed technology under contracts with foreign national oil companies.  In the future, we may expand our international land 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, or the amount of technology deployed, 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 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.

 

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 longterm 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.

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. Suppliers may experience quality control issues as they seek to rapidly increase production of equipment and supplies necessary for our operations. Additionally, suppliers may seek to increase prices for equipment and supplies, which we are unable to pass through to

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our customers, either due to contractual obligations or market constraints in the contract drilling business. 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.

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

Certain of our international employees are unionized, and efforts may be made from time to time to unionize other portions of our workforce.  We may in the future be subject to strikes or work stoppages and other labor disruptions in connection with unionization efforts or renegotiation of existing contracts with unions representing our international employees. Additional unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs, reduce our revenues or limit our operational flexibility.

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 for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Lower utilization and dayrates adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates may result in the recognition of impairment charges if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of an asset group may not be recoverable. 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. For example, in fiscal years 2018 and 2016, we recognized impairment charges of $17.5 million and $6.3 million, respectively, related to tangible assets and equipment.

Any impairment could have a material adverse effect on our consolidated financial statements. The facts and circumstances included in our impairment assessments are described in Part II, Item 8— “Financial Statements and Supplementary Data.”

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 and other tax liabilities. 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. Tax rates in the various jurisdictions in which our subsidiaries are organized and conduct their operations may change significantly as a result of political or economic factors beyond our control. It is also possible that future changes to tax laws (including tax treaties in any of the jurisdictions that we operate in) 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. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes an annual limitation on the amount of net operating losses and other pre-change tax attributes (such as tax credits) that may be used to offset taxable income by a corporation that has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more shareholders (or groups of shareholders) that are each deemed to own at least 5 percent of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage during a rolling three-year period. As of September 30, 2018, we have not experienced an ownership change and, therefore, our utilization of our net operating loss carryforwards was not subject to an annual limitation. However, if we were to experience ownership changes in the future as a result of subsequent shifts in our stock ownership, our ability to use our pre-change net operating loss carryforwards to offset future taxable income may be subject to limitations, which could potentially result in increased future tax liability to us. Furthermore, our acquisition of MOTIVE caused MOTIVE to undergo an ownership change and, as a result, the pre-change net operating losses of MOTIVE are subject to limitation under Section 382; however, based on the amount of such net operating losses subject to the limitation, we do not expect that the application of the Section 382 limitation will have a material impact on our overall future tax liabilities. In addition, at the state level, there may be periods during which the use of net operating loss carryforwards is suspended or otherwise limited, which could accelerate or permanently increase state taxes owed. In any case, our net operating loss and tax credit carryforwards are subject to review and potential disallowance upon audit by

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the tax authorities of the jurisdictions where these tax attributes are incurred. Additionally, our future effective tax rates could be adversely affected by changes in tax laws (including tax treaties) or their interpretation.

On December 22, 2017, the President of the United States signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Reform Act”) that significantly reforms the Code. The Tax Reform Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, (v) imposes new limitations on the deductibility of interest expense, (vi) imposes a type of minimum tax designed to reduce the benefits derived from intercompany transactions and payments that result in base erosion, and (vii) provides for more general changes to the taxation of corporations, including changes to cost recovery rules. These tax law changes could have the effect of causing us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain cases, could cause us to incur income tax liability that we might otherwise not have incurred, in the absence of these tax law changes. Additionally, the Tax Reform Act is complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Reform Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Reform Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could adversely affect our financial position, income tax provision, net income, or cash flows.

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 $0.71 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 longterm 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 not reduce our dividend or that we will continue to pay a dividend in the future.

A downgrade in our credit ratings 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.

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

 

At September 30, 2018, we had a portfolio of securities with a total fair value of approximately $82.5 million, consisting of Ensco plc (“Ensco”) and Schlumberger, Ltd. The total fair value of the portfolio of securities was $70.2 million at September 30, 2017. The portfolio is recorded at fair value on the balance sheet with changes in unrealized aftertax 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 year 2016, we determined that a loss was otherthantemporary and we recognized a $26.0 million

26


 

impairment charge.  No impairment charges were recognized in fiscal year 2017 or 2018.   At November 8, 2018, the fair value of the portfolio decreased to approximately $68.5 million. 

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.

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 (including technology 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, while our dayrate is denominated in U.S. dollars, 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. Argentina also has a history of implementing currency controls, which restrict the conversion and repatriation of U.S. dollars. These controls were not in place during this past fiscal year.

Argentina’s economy is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period based on inflation data published by the respective governments.  Nonetheless, 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.

For fiscal year 2018, we experienced aggregate foreign currency losses of $3.6 million in Argentina.  Our aggregate foreign currency losses for fiscal year 2018 and 2017 were $4.0 million and $7.1 million, respectively. However, in the future, we may incur larger currency devaluations, foreign exchange restrictions or other difficulties repatriating U.S. dollars from Argentina or elsewhere, 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 have limited control or 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

27


 

be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable.

During fiscal year 2018, approximately 9.6 percent of our consolidated operating revenues were generated from the international contract drilling business and approximately 96.0 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 operations.

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

Many aspects of our operations are subject to various laws and regulations in the jurisdictions where we operate, including those relating to drilling practices and comprehensive and frequently changing laws and regulations relating to the safety and to the protection of human health and the environment. Environmental laws apply to the oil and gas industry including those regulating air emissions, discharges to water, and the transport, storage, use, treatment, disposal and remediation of, and exposure to, solid and hazardous wastes and materials. These laws can have a material adverse effect on the drilling industry, including our operations, and compliance with such laws may require us to make significant capital expenditures, such as the installation of costly equipment or operational changes, and may affect the resale values or useful lives of our drilling rigs. If we fail to comply with these laws and regulations, we could be exposed to substantial administrative, civil and criminal penalties, delays in permitting or performance of projects and, in some cases, injunctive relief. Violations of environmental laws may also result in liabilities for personal injuries, property and natural resource damage and other costs and claims. 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.

Additional legislation or regulation and changes to existing legislation and regulation may reasonably be anticipated, and the effect thereof on our operations cannot be predicted. The expansion of the scope of laws or regulations protecting the environment has accelerated in recent years, particularly outside the United States, and we expect this trend to continue. To the extent new laws are enacted or other governmental actions are taken that prohibit or restrict drilling in areas where we operate or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or the drilling industry, in particular, our business or prospects could be materially adversely affected.

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, including any future 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.

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

Our current debt agreements pertaining to certain longterm unsecured debt and our unsecured revolving credit facility contain, and our future financing arrangements likely will 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 therein) of less than 50 percent and certain priority debt (as

28


 

defined therein) may not exceed 17.5 percent of our net worth (as defined therein). Such restrictions may limit our ability to successfully execute our business plans, which may have adverse consequences on our operations.

Certain provisions of our corporate governing documents could make an acquisition of our company more difficult.

The following provisions of our charter documents, as currently in effect, and Delaware law could discourage potential proposals to acquire us, delay or prevent a change in control of us or limit the price that investors may be willing to pay in the future for shares of our common stock:

·

our certificate of incorporation permits our Board of Directors to issue and set the terms of preferred stock and to adopt amendments to our bylaws;

·

our bylaws contain restrictions regarding the right of stockholders to nominate directors and to submit proposals to be considered at stockholder meetings;

·

our bylaws restrict the right of stockholders to call a special meeting of stockholders; and 

·

we are subject to provisions of Delaware law which restrict us from engaging in any of a broad range of business transactions with an “interested stockholder” for a period of three years following the date such stockholder became classified as an interested stockholder.

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Item 1B.  UNRESOLVED STAFF COMMENT

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 fiscal year 2018 and that remain unresolved.

Item 2.  PROPERTIES

 

Contract Drilling Operations

 

Our property consists primarily of drilling rigs and ancillary equipment.  We own substantially all of the equipment used in our businesses.  For further information on the status of our drilling fleet, see Item 1— “Business.”

 

Real Property

 

Our corporate headquarters is in leased office space and is located at 1437 South Boulder Avenue, Tulsa, Oklahoma, 74119.  

 

We own or lease office and yard space to support our ongoing operations. These include field and district offices in Texas, Oklahoma, Louisiana, Mississippi, Colorado, Wyoming, North Dakota, Ohio, Pennsylvania, Colombia, Argentina, and Bahrain. In addition, we have a fabrication and assembly facility near Houston, Texas as well as a fabrication facility and a maintenance and overhaul facility near Tulsa, Oklahoma.

 

We also own several commercial real estate properties for investment purposes. Our real estate investments are located exclusively within Tulsa, Oklahoma, and include a shopping center, multi-tenant industrial warehouse properties, and undeveloped real estate.

 

Item 3.  LEGAL PROCEEDINGS

Venezuela Expropriation

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

 

Item 4.  MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Market Information and Dividends

The principal market on which our common stock is traded is the New York Stock Exchange under the symbol “HP.”  As of November 8, 2018, there were 394 record holders of our common stock as listed by our transfer agent’s records.

We have paid quarterly cash dividends on our common stock during the past two fiscal years. Payment of future dividends will depend on earnings and other factors.

Picture 2

 

31


 

Performance Graph

The following performance graph reflects the yearly percentage change in our cumulative total stockholder return on common stock as compared with the cumulative total return on the S&P 500 Index and the S&P 1500 Oil and Gas Drilling Index. All cumulative returns assume an initial investment of $100, the reinvestment of dividends and are calculated on a fiscal year basis ending on September 30 of each year.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

INDEXED RETURNS

 

    

Base Period

    

Years Ending

Company / Index

    

Sep 13

    

Sep 14

    

Sep 15

    

Sep 16

    

Sep 17

    

Sep 18

Helmerich & Payne, Inc.

 

100

 

213.72

 

107.52

 

160.53

 

130.54

 

119.00

S&P 500 Index

 

100

 

142.89

 

142.02

 

163.93

 

194.44

 

187.00

S&P 1500 Oil & Gas Drilling Index

 

100

 

103.39

 

44.91

 

47.75

 

40.37

 

55.00

PHLX Oil Service Index

 

100

 

100.00

 

62.00

 

66.00

 

58.00

 

62.00

 

Picture 4

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

Stock Portfolio

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

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Item 6.  SELECTED FINANCIAL DATA

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

Fiveyear Summary of Selected Financial Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

2018

    

2017

    

2016

    

2015

    

2014

 

 

 

(in thousands except per share amounts)

 

Statements of Operations Selected Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

    

$

2,487,268

    

$

1,804,741

    

$

1,624,332

    

$

3,161,702

    

$

3,715,968

 

Depreciation and amortization

 

 

583,802

 

 

585,543

 

 

598,587

 

 

608,039

 

 

523,984

 

Selling, general and administrative

 

 

200,619

 

 

151,002

 

 

146,183

 

 

134,712

 

 

135,273

 

Income (loss) from continuing operations

 

 

493,010

 

 

(127,863)

 

 

(52,990)

 

 

420,474

 

 

706,610

 

Loss from discontinued operations

 

 

(10,338)

 

 

(349)

 

 

(3,838)

 

 

(47)

 

 

(47)

 

Net income (loss)

 

 

482,672

 

 

(128,212)

 

 

(56,828)

 

 

420,427

 

 

706,563

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Per Share Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic earnings (loss) per share from continuing operations

 

 

4.49

 

 

(1.20)

 

 

(0.50)

 

 

3.88

 

 

6.52

 

Basic loss per share from discontinued operations

 

 

(0.10)

 

 

 —

 

 

(0.04)

 

 

 —

 

 

 —

 

Basic earnings (loss) per share

 

 

4.39

 

 

(1.20)

 

 

(0.54)

 

 

3.88

 

 

6.52

 

Diluted earnings (loss) per share from continuing operations

 

 

4.47

 

 

(1.20)

 

 

(0.50)

 

 

3.85

 

 

6.44

 

Diluted loss per share from discontinued operations

 

 

(0.10)

 

 

 —

 

 

(0.04)

 

 

 —

 

 

 —

 

Diluted earnings (loss) per share

 

 

4.37

 

 

(1.20)

 

 

(0.54)

 

 

3.85

 

 

6.44

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash dividends declared per common share

 

 

2.82

 

 

2.80

 

 

2.78

 

 

2.75

 

 

2.63

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment, net

 

 

4,857,382

 

 

5,001,051

 

 

5,144,733

 

 

5,563,170

 

 

5,188,544

 

Total assets (1)

 

 

6,214,867

 

 

6,439,988

 

 

6,832,019

 

 

7,147,242

 

 

6,725,316

 

Long term debt

 

 

493,968

 

 

492,902

 

 

491,847

 

 

492,443

 

 

39,502

 

Debt to capital ratio (2)

 

 

10.1

%

 

10.6

%

 

9.7

%

 

9.1

%

 

0.8

%

Net working capital (3)

 

 

412,566

 

 

325,016

 

 

292,857

 

 

316,070

 

 

408,931

 

 

(1)

Total assets for all years include amounts related to discontinued operations. Our Venezuelan subsidiary was classified as discontinued operations on June 30, 2010, after the seizure of our drilling assets in that country by the Venezuelan government.

(2)

The debt to capital ratio is calculated by dividing total debt by total capitalization (total debt plus shareholders’ equity). The debt to capital ratio is not a measure of operating performance or liquidity defined by U.S. GAAP and may not be comparable to similarly titled measures presented by other companies.  

(3)

Net working capital is calculated as current assets, excluding cash and short-term investments, less current liabilities.

 

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

The following discussion should be read in conjunction with Part I of this Form 10K as well as the Consolidated Financial Statements and related notes thereto included in Item 8— “Financial Statements and Supplementary Data” of this Form 10K. Our future operating results may be affected by various trends and factors which are beyond our control. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report under “Cautionary Note regarding Forward-Looking Statements” and Item 1A-- “Risk Factors.” Accordingly, past results and trends should not be used by investors to anticipate future results or trends.

Executive Summary

Helmerich & Payne, Inc. provides performance-driven drilling services and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. As of September 30, 2018, our drilling rig fleet included a total of 390 drilling rigs. Our contract drilling segments consist of the U.S. Land segment with 350 rigs, the Offshore segment with 8 offshore platform rigs and the International Land segment with 32 rigs as of September 30, 2018. At the close of fiscal year 2018, we had 259 contracted rigs, of which 153 were under a  fixed term contract and 106 were working well-to-well, compared to 218 contracted rigs at the same time during the prior year. As the U.S. land drilling industry recovered from an all-time low of approximately 380 active rigs in the summer of 2016 to over 1,000 rigs as of September 30, 2018, we led the way in reactivating rigs in the United States and gained significant market share in the process. We believe that our success during this time frame is validation of the capabilities of our land drilling fleet and our decisions during the downturn to prepare for an eventual improvement in the business, and our ability to deliver best-in-class field performance and customer satisfaction. Our long-term strategy remains focused on innovation, technology, safety, operational excellence and reliability.  As we move forward, we believe that our advanced uniform rig fleet, financial strength, long term contract backlog and strong customer and employee base position us very well to take advantage of future opportunities. 

Market Outlook

Our revenues are derived from the capital expenditures of companies involved in the exploration, development and production of crude oil and natural gas (“E&Ps”).  At the core, the level of capital expenditures is dictated by current and expected future prices of crude oil and natural gas, which are determined by various supply and demand factors.  Both commodities have historically been, and we expect them to continue to be, cyclical and highly volatile.

With respect to U.S. Land Drilling, the resurgence of oil and natural gas production coming from the United States brought about by unconventional shale drilling for oil has significantly impacted the supply of oil and natural gas. The advent of unconventional drilling in the United States began in earnest in 2009 and continues to evolve as E&Ps drill longer lateral wells. During this time, we designed, built and delivered new technology AC drive rigs (FlexRigs) to the market at a fast pace, substantially growing our fleet.  The pace of progress of unconventional drilling was interrupted by a decrease in crude oil prices in late 2014 from $106 per barrel in June 2014 to below $30 per barrel in early 2016.

Late in 2017, crude oil prices began to recover, along with the level of activity in unconventional drilling. Throughout this time, the length of the lateral section of wells drilled in the U.S. has continued to grow.  The progression of longer lateral wells has required many of the industries’ rigs to be upgraded to certain specifications in order to meet the technical challenges of drilling longer lateral wells.  The upgraded rigs meeting those specifications are commonly referred to in the industry as super-spec rigs and have the following specific characteristics: AC Drive, 1,500 horsepower drawworks, 750,000 lbs. hookload rating, 7,500 psi mud circulating system and multiple-well pad capability. 

 

Beginning in 2018, we saw the demand for super-spec rigs increase, as crude oil ranged between  $59 and $66 per barrel.  During 2018, the demand for super-spec rigs continued to increase and we benefitted by gaining market share as a result of having the largest super-spec fleet in the industry and having the largest number of rigs that could readily and economically be upgraded to the super-spec classification.  During fiscal year 2018, we converted two FlexRig4’s to super-spec capacity and upgraded 52 of our other rigs to super-spec, including 51 FlexRig3’s and one FlexRig5.  As of September 30, 2018, we held over 40 percent of the super-spec market share in U.S. land drilling.  Due to our financial strength, we are in the position to continue to upgrade rigs to super-spec as long as market demand for such rigs remains high and we have a supply of economically viable super-spec upgradable rigs.

 

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Thus far in fiscal year 2019, crude oil prices have fallen from recent highs, but are still higher than the average price when exploration and production companies set their 2018 capital budgets. Accordingly, we expect higher levels of exploration and production capital expenditures by our customers in 2019. As such, we expect the demand for super-spec rigs to remain elevated and robust well into fiscal year 2019, and we are well positioned to continue to upgrade our rigs to super-spec to meet our customers’ needs. In addition, there will be more opportunities driven by our marketing efforts for our non super-spec rigs (e.g. FlexRig4) to return to the market, targeting on customer programs that do not require super-spec capabilities and can be offered at a lower price point while still exceeding our return hurdles.  We are also seeing growing interest from customers to enter into multi-year contracts. If the market remains strong and the supply of economically viable super-spec rigs is depleted, the potential for newly built rigs in the industry may return, but we expect that much higher levels of pricing and term contract coverage will be required before the industry sees significant capital deployed for new build rigs.

 

In our International Land Drilling segment, we believe that our market leading position in the Neuquén basin of Argentina may provide opportunities for us to deploy additional AC rigs from the United States.  We have seen periodic spot market work for our deeper drilling 3,000 horsepower rigs in Northern Argentina. Spot market contracts do not have a defined term and operate on a well-by-well basis. In fiscal year 2018, we reactivated four rigs in Colombia with renewed interest in the deeper drilling 3,000 horsepower rigs as well as our two FlexRig3 rigs. We expect Colombia to be a relatively stable market in fiscal year 2019 with potential upside. Overall, we have seen an increase in tendering activity from our customers in the international market resulting from higher oil prices. We believe that our international land operations are a potential area of growth over the next several years, but acknowledge that such growth may be more sporadic than what we expect in the U.S. market.

At this time, our Offshore Drilling operations are expected to report relatively stable utilization and cash flows in the upcoming fiscal year. We anticipate one or more of our platform rigs could either be stacked or placed on a lower margin stack rate towards the end of fiscal year 2019.

Recent Developments

Acquisitions

On December 8, 2017, we completed an acquisition (“MagVAR Acquisition”) of an unaffiliated company, Magnetic Variation Services, LLC (“MagVAR”), which is now a wholly-owned subsidiary of the Company. The operations for MagVAR are included within our other non-reportable business segments.   

Through comprehensive 3D geomagnetic reference modeling, MagVAR provides measurement while drilling (“MWD”) survey corrections by identifying and quantifying MWD tool measurement errors in real-time, greatly improving directional drilling performance and wellbore placement. Founded in 2010, MagVAR will maintain its headquarters in Colorado.

At the effective time of the MagVAR Acquisition, MagVAR shareholders received aggregate cash consideration of $47.9 million, net of customary closing adjustments, and certain management members received restricted stock awards covering 213,904 shares of Helmerich & Payne, Inc. common stock.  At closing, $6.0 million of the cash consideration was placed in escrow, to be released to the sellers twelve months after the acquisition closing date.  Transaction costs related to the MagVAR Acquisition incurred during fiscal year 2018 were approximately $1.2 million and are recorded in the Consolidated Statements of Operations within selling, general and administrative expense.

On June 2, 2017, we completed a merger transaction (“MOTIVE Merger”) pursuant to which an unaffiliated drilling technology company, MOTIVE Drilling Technologies, Inc., a Delaware corporation (“MOTIVE”), was merged with and into our wholly-owned subsidiary Spring Merger Sub, Inc., a Delaware corporation.  MOTIVE survived the transaction and is now a wholly-owned subsidiary of the Company.   

MOTIVE has a proprietary Bit Guidance System™ that is an algorithm-driven system that considers the total economic consequences of directional drilling decisions and is designed to consistently lower drilling costs through more efficient drilling and increased hydrocarbon production through smoother wellbores and more accurate well placement.  Given our strong and longstanding technology and innovation focus, we believe the technology will continue to advance and provide further benefits for the industry.

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At the effective time of the MOTIVE Merger, MOTIVE shareholders received aggregate cash consideration of $74.3 million, net of customary closing adjustments. During fiscal year 2018, MOTIVE shareholders received additional cash consideration of $10.6 million in an earnout payment and may be eligible to receive up to an additional $12.5 million in potential earnout payments based on future performance.  Transaction costs related to the MOTIVE Merger incurred during fiscal year 2017 were $3.2 million and are recorded in the Consolidated Statements of Operations within selling, general and administrative expense.    

Additional information regarding the MagVAR and MOTIVE acquisitions is described in Note 3--Business Combinations to our consolidated financial statements. The operations for MagVAR and MOTIVE are included within our other non-reportable business segments.  The MagVAR and MOTIVE Mergers  were accounted for as a business combination in accordance with Accounting Standards Codification (“ASC”) 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values.

Impairments

Consistent with our policy, we evaluate our drilling rigs and related equipment for impairment whenever events or changes in circumstances indicate the carrying value of these assets may exceed the estimated undiscounted future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessment on the future marketability of specific rigs’ asset group. Given the continued low utilization within our International FlexRig4 asset group and two of our domestic and international conventional rigs’ asset groups, together with the continued delivery of new, more capable rigs, we considered these economic factors to be indicators that these rigs’ asset groups may potentially be impaired.

At September 30, 2018, we performed impairment testing on our International FlexRig4 asset group, which has an aggregate net book value of $63.0 million. We concluded that the net book value of the asset group is recoverable through estimated undiscounted future cash flows with a surplus of approximately 23 percent. The most significant assumptions used in our undiscounted cash flow model include: timing on awards of future drilling contracts, oil prices, operating dayrates, operating costs, rig reactivation costs, drilling rig utilization, revenue efficiency, estimated remaining economic useful life and net proceeds received upon future sale/disposition. The assumptions are consistent with the Company’s internal budgets and forecasts for future years. These significant assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. Although we believe the assumptions used in our analysis are reasonable and appropriate and the asset group weighted average of expected future undiscounted net cash flows exceeds the net book value of the asset group as of the fiscal year 2018 year-end impairment evaluation, different assumptions and estimates could materially impact the analysis and our resulting conclusion.

At September 30, 2018, we engaged a third party independent accounting firm who performed a market valuation, utilizing the market approach, on two of our domestic and international conventional rigs’ asset groups, which have aggregate net book values of $9.0 million and $15.2 million, respectively. We concluded that the fair values of these two asset groups exceed the net book values by approximately 64 percent and 141 percent, respectively, and as such, no impairment was recorded. The significant assumptions in the valuation exercise are classified as Level 2 and Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures.

 

During the fourth quarter of fiscal year 2018, after ceasing operations in Ecuador, within our International Land segment, we entered into a sales negotiation with respect to the six conventional rigs, within a separated international conventional rigs’ asset group, with net book values of $20.8 million, present in the country, pursuant to which the rigs, together with associated equipment and machinery would be sold to a third party to be recycled.  Certain components of these rigs with an $8.5 million net book value, that are not subject to the sale agreement, will be transferred to the United States to be utilized on other FlexRigs with high activity and demand. The sales transaction was completed in November 2018. We recorded a non-cash impairment charge of $9.2 million ($7.0 million, net of tax, or $0.06 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018. As a result, the remaining rig within the same asset group, not to be disposed of, was written down resulting in an additional impairment charge of $1.4 million ($1.0 million, net of tax, or $0.01 per diluted share).

 

Furthermore, during the fourth quarter of fiscal year 2018, within our U.S. Land segment, management committed to a plan to auction several previously decommissioned rigs during fiscal year 2019. As a result, we wrote them down to their estimated fair values. We recorded a non-cash impairment charge of $5.7 million ($4.2 million, net of tax, or $0.04 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018.

36


 

 

During the fourth quarter of fiscal year 2018, and as part of our annual goodwill impairment test, we performed a detailed assessment of the TerraVici technology reporting unit, where $4.7 million goodwill was allocated. We determined that the estimated fair value of this reporting unit was less than its carrying amount and recorded goodwill impairment losses of $4.7 million ($3.5 million, net of tax, or $0.03 per diluted share). In addition, we recorded an intangible asset impairment loss of $0.9 million ($0.7 million, net of tax, or $0.01 per diluted share). These impairment losses are included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018. Our goodwill impairment analysis performed on our remaining technology reporting units in the fourth quarter of fiscal years 2018 and 2017 did not result in impairment charges.

Results of Operations for the Fiscal Years Ended September 30, 2018 and 2017

Consolidated Results of Operations

All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Except as specifically discussed, the following results of operations pertain only to our continuing operations.

Net Income (Loss) Our net income for fiscal year 2018 was $482.7 million ($4.39 earnings per share), compared with net loss of $128.2 million ($1.20 loss per share) for fiscal year 2017. Net income in fiscal year 2018 and net loss in fiscal year 2017 include after-tax income from early termination revenue associated with drilling contracts terminated prior to the expiration of their fixed term of $12.6 million ($0.12 per share) and $20.2 million ($0.18 per share), respectively. Net income in fiscal year 2018 and net loss in fiscal year 2017 include aftertax gains from the sale of assets of $16.7 million ($0.15 per diluted share) and $14.3 million ($0.13 per diluted share), respectively. Additionally, net income in fiscal year 2018 and net loss in fiscal year 2017 includes after-tax income from a tax benefit of $477.2 million ($4.36 per diluted share) and a tax benefit of $56.7 million ($0.52 per diluted share), respectively.

Revenue Consolidated operating revenues were $2.5 billion in fiscal year 2018 and $1.8 billion in fiscal year 2017, including early termination revenue of $17.1 million and $29.4 million in each respective fiscal year.  Excluding early termination revenue, operating revenue increased $694.8 million in fiscal year 2018 compared to fiscal year 2017.  Oil prices steeply declined from over $106 per barrel in June 2014 to below $30 per barrel in early 2016.  During the second half of calendar year 2016, oil prices increased and fluctuated within a $42 to $54 per barrel price range for most of fiscal year 2017. However, during the second half of fiscal year 2018, oil prices were mostly in the $62 to $77 per barrel price range. Primarily as a result of the impact of oil prices on drilling activity by exploration and production companies during that time frame, the number of revenue days in our U.S. Land segment totaled 77,980 in fiscal year 2018, compared to 57,120 in fiscal year 2017.

Asset Impairment Management monitors industry market conditions impacting its longlived assets, intangible assets and goodwill. When required, an impairment analysis is performed to determine if any impairment exists.  During the fourth quarter of fiscal year 2018, and after ceasing operations in Ecuador, we entered into a sales negotiation with respect to the six conventional rigs present in the country, pursuant to which the rigs, together with associated equipment and machinery, would be sold to a third party to be recycled. As a result, we recorded a non-cash impairment charge of $9.2 million. The remaining rig within the same asset group, not to be disposed of, was written down resulting in an additional impairment charge of $1.4 million ($1.0 million, net of tax, or $0.01 per diluted share). Additionally, during the fourth quarter of fiscal year 2018, management committed to a plan to auction several previously decommissioned rigs during fiscal year 2019. As a result, we wrote them down to their estimated fair values and we recorded a non-cash impairment charge of $5.7 million. Furthermore, during the fourth quarter of fiscal year 2018, we recorded goodwill and intangible assets impairment losses of $5.6 million related to the TerraVici technology reporting unit. The fiscal year 2018 asset impairment charges are included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018. We did not record any impairment in fiscal year 2017.

Interest and Dividend Income Interest and dividend income was $8.0 million and $5.9 million in fiscal years 2018 and 2017, respectively.  The higher income in fiscal year 2018 was primarily due to higher earnings on available cash equivalents and short-term investments.  

Direct Operating Expenses Direct operating expenses in fiscal year 2018 were $1.7 billion, compared with $1.2 billion in fiscal year 2017.  The increase in fiscal year 2018 from fiscal year 2017 was primarily attributable to a higher level of activity in fiscal year 2018.

37


 

General and Administrative Expense General and administrative expenses totaled $200.6 million in fiscal year 2018 and $151.0 million in fiscal year 2017.  During fiscal year 2018, we incurred transaction costs of $1.2 million related to our acquisition of MagVAR. Additionally, increased employee general and administrative headcount, primarily as a result of the acquisition of MagVAR and MOTIVE, caused an increase in employee compensation costs, including taxes, benefits and stock-based compensation, compared to fiscal year 2017.

Depreciation and Amortization Depreciation and amortization expense was $583.8 million in fiscal year 2018 and $585.5 million in fiscal year 2017. Depreciation and amortization includes amortization of intangible assets of $5.4 million and $1.1 million in fiscal years 2018 and 2017, respectively, and abandonments of equipment of $27.7 million and $42.6 million in fiscal years 2018 and 2017, respectively. In fiscal year 2018, depreciation expense also includes $9.7 million of accelerated depreciation for components on rigs that are planned for conversion in fiscal year 2019. Depreciation expense, exclusive of abandonments and accelerated depreciation,  increased one percent in fiscal year 2018 from fiscal year 2017. As the drilling markets continued to recover during fiscal year 2017, we began abandoning older rig components that were replaced by upgrades to our rig fleet to meet customer demands for additional capabilities.  This trend continued in fiscal year 2018.

Interest Interest expense, net of amounts capitalized, totaled $24.3 million in fiscal year 2018 and $19.7 million in fiscal year 2017. Interest expense is primarily attributable to fixedrate debt outstanding. Capitalized interest was $0.4 million and $0.3 million in fiscal years 2018 and 2017, respectively. All of the capitalized interest is attributable to our rig upgrade and rig construction programs.

Income Taxes We had an income tax benefit of $477.2 million in fiscal year 2018 compared to an income tax benefit of $56.7 million in fiscal year 2017. The effective income tax rate was (3,012.3) percent in fiscal year 2018 compared to 30.7 percent in fiscal year 2017. The effective tax rate for fiscal year 2018 was impacted by income tax adjustments related to the reduction of the federal statutory corporate income tax rate as part of the Tax Reform Act, which was enacted on December 22, 2017, and an increase in the deferred state income tax rate. In addition, effective tax rates differ from the U.S. federal statutory rate (24.5 percent for fiscal year 2018 and 35.0 percent for fiscal year 2017) due to non-deductible permanent items and state and foreign income taxes. Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets is based on management’s judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future. See Note 8—Income Taxes to our Consolidated Financial Statements for additional income tax disclosures.

Research and Development During fiscal years 2018 and 2017, we incurred $18.2 million and $12.0 million, respectively, of research and development expenses. The increase in expense is primarily related to the acquisitions of MOTIVE and MagVAR given that a portion of their ongoing expenses are classified as research and development. We anticipate research and development expenses to continue during fiscal year 2019.

Discontinued Operations Expenses incurred within the country of Venezuela are reported as discontinued operations. In March 2016, the Venezuelan government implemented the previously announced plans for a new foreign currency exchange system. Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. and PDVSA Petroleo, S.A. We are seeking damages for the taking of our Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. Activity within discontinued operations for both fiscal years 2017 and 2018 is primarily a result of the impact of exchange rate fluctuations on remaining in country assets and liabilities.

38


 

U.S. Land Operations Segment

 

 

 

 

 

 

 

 

 

 

 

    

2018

    

2017

    

% Change

 

 

(in thousands, except operating statistics)

Operating revenues

 

$

2,068,195

 

$

1,439,523

 

43.7

%

Direct operating expenses

 

 

1,348,533

 

 

984,205

 

37.0

 

Selling, general and administrative expense

 

 

58,157

 

 

50,712

 

14.7

 

Depreciation

 

 

505,112

 

 

499,486

 

1.1

 

Asset impairment charge

 

 

5,695

 

 

 —

 

100.0

 

Segment operating income (loss)

 

$

150,698

 

$

(94,880)

 

(258.8)

 

Operating Statistics (1):

 

 

  

 

 

  

 

  

 

Revenue days

 

 

77,980

 

 

57,120

 

36.5

%

Average rig revenue per day

 

$

23,411

 

$

22,607

 

3.6

 

Average rig expense per day

 

$

14,182

 

$

14,623

 

(3.0)

 

Average rig margin per day

 

$

9,229

 

$

7,984

 

15.6

 

Number of rigs at end of period

 

 

350

 

 

350

 

 —

 

Rig utilization

 

 

61

%  

 

45

%  

35.6

 

 

(1)

Operating statistics for per day revenue, expense and margin do not include reimbursements of “outofpocket” expenses of $242,617 and $148,218 for fiscal years 2018 and 2017, respectively.

 

Operating Income (Loss) In fiscal year 2018, the U.S. Land segment had operating income of $150.7 million compared to an operating loss of $94.9 million in fiscal year 2017. Included in U.S. land revenues for fiscal years 2018 and 2017 is approximately $17.1 million and $24.5 million, respectively, from early termination of fixedterm contracts.  Fixedterm contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term (except in limited circumstances including sustained unacceptable performance by us).

Revenue Excluding early termination revenue of $219 and $428 per day for fiscal years 2018 and 2017, respectively, average revenue per day for fiscal year 2018 increased by $1,013 to $23,192 from $22,179 in fiscal year 2017.  Our activity increased year-over-year in response to higher commodity prices resulting in a 36.5 percent increase in revenue days when comparing fiscal year 2018 to fiscal year 2017.  

Direct Operating Expenses Direct rig expense increased to $1.3 billion in fiscal year 2018 from $984.2 million in fiscal year 2017.  This increase was primarily attributable to increased activity. Additionally, we implemented a wage increase for our field personnel in some regions in April 2018.

General and Administrative Expense In fiscal year 2018, general and administrative expense increased 14.7 percent compared to 2017. This change was primarily driven by an increase in employee headcount, which resulted in an increase in employee compensation, including taxes, benefits and stock-based compensation.

Asset Impairment Charge During the fourth quarter of fiscal year 2018, management committed to a plan to auction several previously decommissioned rigs during fiscal year 2019. As a result, we wrote these rigs down to their estimated fair values and recorded a non-cash impairment charge of $5.7 million, which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018.

 

Depreciation Depreciation includes charges for abandoned equipment of $26.3 million and $42.2 million in fiscal years 2018 and 2017, respectively. In fiscal year 2018, depreciation expense also includes $9.7 million of accelerated depreciation for components on rigs that are scheduled for conversion in fiscal year 2019. As the drilling markets continued to recover during fiscal year 2017, we began abandoning older rig components to meet customer demands for additional capabilities. This trend continued in fiscal year 2018. Excluding the abandonments and accelerated depreciation, depreciation in fiscal year 2018 increased from fiscal year 2017. 

Utilization Rig utilization increased to 61 percent in fiscal year 2018 from 45 percent in fiscal year 2017. The total number of available rigs at both September 30, 2018 and September 30, 2017 was 350. 

At September 30, 2018, 232 out of 350 existing rigs in the U.S. Land segment were generating revenue. Of the 232 rigs generating revenue, 136 were under fixedterm contracts, and 96 were working well-to-well. At November 9, 2018, the number of existing rigs under fixedterm contracts in the segment was 141 and the number of rigs working in the spot market was 95.

39


 

Offshore Operations Segment

 

 

 

 

 

 

 

 

 

 

 

    

2018

    

2017

    

% Change

 

 

(in thousands, except operating statistics)

Operating revenues

 

$

142,500

 

$

136,263

 

4.6

%

Direct operating expenses

 

 

101,477

 

 

96,593

 

5.1

 

Selling, general and administrative expense

 

 

4,507

 

 

3,705

 

21.6

 

Depreciation

 

 

10,392

 

 

11,764

 

(11.7)

 

Segment operating income

 

$

26,124

 

$

24,201

 

7.9

 

Operating Statistics (1):

 

 

  

 

 

  

 

  

 

Revenue days

 

 

2,036

 

 

2,277

 

(10.6)

%

Average rig revenue per day

 

$

35,331

 

$

34,332

 

2.9

 

Average rig expense per day

 

$

26,009

 

$

23,172

 

12.2

 

Average rig margin per day

 

$

9,322

 

$

11,160

 

(16.5)

 

Number of rigs at end of period

 

 

 8

 

 

 8

 

 —

 

Rig utilization

 

 

70

%  

 

74

%  

(5.4)

 

 

(1)

Operating statistics for per day revenue, expense and margin do not include reimbursements of “outofpocket” expenses of $20,279 and $21,578 for fiscal years 2018 and 2017, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.

 

Operating Income In fiscal year 2018, the Offshore segment had operating income of $26.1 million compared to operating income of $24.2 million in fiscal year 2017.

Revenue Average rig revenue per day increased in fiscal year 2018 compared to fiscal year 2017 primarily due to several rigs moving to higher pricing from previous standby or other special dayrates. During April 2018, a previously idle rig commenced work on a customer’s platform.

Direct Operating Expenses Average rig expense increased to $26,009 per day in fiscal year 2018 from $23,172 per day in fiscal year 2017.  This increase was primarily attributable to rig start-up expenses and unfavorable adjustments to self-insurance expenses related to workers’ compensation.

Depreciation Depreciation expense decreased 11.7 percent in fiscal year 2018 compared to fiscal year 2017. This change was primarily driven by two rigs becoming fully depreciated during fiscal year 2018. 

Utilization During the second quarter of fiscal year 2017, we sold one of our offshore rigs.  At September 30, 2018, six of our eight platform rigs were contracted compared to five of the eight available platform rigs at September 30, 2017.

International Land Operations Segment