Helmerich & Payne
Annual Report 2018

Plain-text annual report

HELMERICH & PAYNE, INC. ANNUAL REPORT FOR 2018 11JAN201919385856 Helmerich & Payne, Inc. 11JAN201919385856 Founded in 1920, Helmerich & Payne, Inc. (H&P) (NYSE: HP) is committed to delivering industry leading levels of drilling productivity and reliability. H&P operates with the highest level of integrity, safety and innovation to deliver superior results for our customers and returns for shareholders. Through its subsidiaries, H&P designs, fabricates and operates high-performance drilling rigs in conventional and unconventional plays around the world. H&P also develops and implements advanced automation, directional drilling and survey management technologies. H&P’s fleet includes 350 land rigs in the U.S., 32 international land rigs and eight offshore platform rigs. For more information, see H&P online at www.hpinc.com. Financial Highlights Years Ended September 30, 2018 2017 2016 Operating Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net Income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted Earnings (loss) per Share . . . . . . . . . . . . . . . . . . . . . . . Dividends Declared per Share . . . . . . . . . . . . . . . . . . . . . . . . . Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (in thousands, except per share amounts) $1,804,741 (128,212) (1.20) 2.80 397,567 6,439,988 $2,487,268 482,672 4.37 2.82 466,584 6,214,867 $1,624,332 (56,828) (0.54) 2.78 257,169 6,832,019 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  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2018 OR For the transition period from to Commission file number 1-4221 HELMERICH & PAYNE, INC. (Exact Name of Registrant as Specified in Its Charter) Delaware (State or Other Jurisdiction of Incorporation or Organization) 1437 S. Boulder Ave., Suite 1400, Tulsa, Oklahoma (Address of Principal Executive Offices) 73-0679879 (I.R.S. Employer Identification No.) 74119-3623 (Zip Code) Securities registered pursuant to Section 12(b) of the Act: (918) 742-5531 Registrant’s telephone number, including area code Title of Each Class Common Stock ($0.10 par value) Name of Each Exchange on Which Registered New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  No  Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  No  Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  No  Indicate by check mark whether the Registrant has submitted electronically 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 S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer  Smaller reporting company  Accelerated filer  Emerging Growth Company  Non-accelerated filer  If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No  At March 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 non-affiliates 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 10-K. 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 10-K relates. HELMERICH & PAYNE, INC. INDEX TO FORM 10-K YEAR ENDED SEPTEMBER 30, 2018 PART I Page 4 4 16 30 30 30 30 31 31 Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 2. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 3. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 4. PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 6. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 8. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART III Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . . . Item 14. Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART IV Item 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 16. Form 10-K Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SIGNATURES 33 34 52 54 107 107 107 108 108 108 108 108 108 109 109 111 112 2 CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K (“Form 10-K”) 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 forward-looking statements are disclosed in this Form 10-K under Item 1A— “Risk Factors,” as well as in Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All subsequent written and oral forward-looking statements attributable to 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 forward-looking statements based on changes in internal estimates, expectations or otherwise, except as required by law. 3 Item 1. BUSINESS Overview PART I 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, multi-tenant 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: U.S. Land Fleet SCR (4) Total Fleet AC (FlexRig3) (1) Rigs Total AC (FlexRig4) (2) Rigs Total AC (FlexRig5) (3) Rigs Total Rigs Total Current Location Available Contracted Available (5) Contracted Available Contracted Available Contracted Available Contracted 133 34 28 7 8 3 8 5 4 1 1 232 TX OK NM ND CO PA LA OH WY UT WV Totals 110 18 26 4 — 2 7 3 2 — — 172 141 20 27 13 — 5 7 4 2 — — 219 202 36 29 27 23 11 10 6 4 1 1 350 38 1 — 11 21 4 — — — 1 — 76 22 15 2 3 2 1 1 2 2 — 1 51 22 15 2 3 2 2 2 2 2 — 1 53 1 1 — — 6 — — — — 1 — 9 1 — — — — — 1 — — — — 2 — — — — — — — — — — — — Total Rigs (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. Super-Spec Fleet (207 Super-Spec Rigs as of 9/30/18) WY 3 PA 4 CO 2 WV 1 OH 6 ND 9 LA 8 OK 26 NM 28 TX 120 The following table sets forth certain information concerning our offshore drilling rigs as of September 30, 2018: Offshore Fleet Current Location Louisiana (2) . . . . . Gulf of Mexico . . . Totals . . . . . . . . . . Shallow Water (1) Deep Water (1) Total Available Rigs Contracted Total Available Rigs Contracted Total Available Rigs Contracted - 6 6 Total Fleet - 3 3 2 3 5 - 3 3 2 6 8 - 3 3 (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: AC (FlexRig3) AC (FlexRig4) International Land Fleet Other AC SCR (1) Total Fleet Rigs Total Total Current Total Location Available Contracted Available Contracted Available Contracted Available Contracted Available Contracted 15 5 1 - 21 Argentina . . Colombia . . Bahrain . . . U.A.E. . . . . . Totals . . . . . . 4 3 3 - 10 11 2 - - 13 11 2 - 2 15 19 8 3 2 32 - 2 - - 2 4 - 1 - 5 4 2 - - 6 - 1 - - 1 - 1 - - 1 Total Total Rigs Rigs Rigs Rigs (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) EOG Resources, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . $ 2018 2017 2016 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: U.S. Land Year Ended September 30, Offshore International Land 2018 2017 2016 2018 2017 2016 2018 2017 2016 Average active rigs per day . . . . . . . . . . . Average utilization (1) . 213.6 156.5 101.0 61 % 45 % 30 % 5.6 70 % 6.2 74 % 7.4 82 % 18.3 13.6 14.7 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 fixed-term 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, multi-tenant 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 FlexTorque™ . . . . . . . Hardware and software designed to decrease downhole drilling vibration and "slip-stick" during drilling. This Description 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 10-K. 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 10 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 multi-well and multi-year 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 “well-to-well” or for a fixed term. “Well-to-well” 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. 11 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: Reportable Segment U.S. Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Backlog Revenue 9/30/2018 9/30/2017 (in billions) 0.9 $ — 0.2 1.1 $ 0.9 — 0.4 1.3 $ Percentage Reasonably Expected to be Filled in Fiscal Year 2020 and Thereafter 24.9 % — % 31.0 % 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 fixed-term 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 part-time 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. 12 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 13 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 14 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 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, earnings releases, and financial statements are made available free of charge on the investor relations section of our website as soon as reasonably practicable after we electronically file such materials with, or furnish 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 10- K 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. 15 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 fixed-term 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. 17 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 cost-effective 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 18 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 anti-indemnity laws. Our customers and other third parties may also dispute, or be unable to meet, their contractual indemnification obligations to us. Accordingly, we may be unable to transfer these risks to our 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 self-insures a number of other risks, including loss of earnings and business interruption, and most cyber risks. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage. If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition and results of operations. Our insurance will not in all situations provide sufficient funds to protect us from all 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 19 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 20 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. 21 Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti-bribery legislation could adversely affect our business. The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti-bribery laws in other jurisdictions, including the United Kingdom Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices and impact our business. Although we have programs in place requiring compliance with anti-bribery legislation, any failure to comply with the FCPA or other anti-bribery legislation could subject us to civil and criminal penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operation. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs or other assets. 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 22 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 fixed-term contracts may, in certain instances, be terminated without an early termination payment. Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be 23 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 long-term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply, the acquisition of a vendor by a competitor, increased demands in the industry or other reasons beyond our control. Similarly, certain key rig components, parts and equipment are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from us or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, downturn in the energy industry or reduction or unavailability of credit. If we are unable to procure certain of such rig components, parts or equipment, our ability to maintain, improve, upgrade or construct drilling rigs could be impaired, which could have a material adverse effect on our business, financial condition and results of operations. 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 24 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 25 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 long-term success. The declaration and amount of future dividends is at the discretion of our Board of Directors and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board of Directors deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. There can be no assurance that we will 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 market-related 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 after-tax value reflected in the equity section of the balance sheet. However, where a decline in fair value below our cost basis is considered to be other than temporary, the change in value is recorded as a charge through earnings. During the fourth quarter of fiscal year 2016, we determined that a loss was other-than-temporary 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 long-term 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. 29 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 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. Item 4. MINE SAFETY DISCLOSURES Not applicable. 30 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. Stock Price Range and Dividends $83.46 $81.11 $62.17 $64.15 $69.08 $50.08 $65.61 $50.02 $58.12 $42.34 $74.33 $73.60 $62.64 $61.85 $69.08 $58.82 $0.70 $0.70 $0.70 $0.70 $0.70 $0.70 $0.70 $0.71 1Q 17 2Q 17 3Q 17 4Q 17 1Q 18 2Q 18 3Q 18 4Q 18 Stock price low Stock price high Dividend 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. Company / Index Helmerich & Payne, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S&P 500 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S&P 1500 Oil & Gas Drilling Index . . . . . . . . . . . . . . . . . . . . . . . . . PHLX Oil Service Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sep 14 Sep 15 Sep 16 Sep 17 Sep 18 100 213.72 107.52 160.53 130.54 119.00 100 142.89 142.02 163.93 194.44 187.00 55.00 100 103.39 62.00 100 100.00 44.91 62.00 47.75 66.00 40.37 58.00 Base Period Sep 13 INDEXED RETURNS Years Ending Comparison of Cumulative Five Year Total Return $250 $200 $150 $100 $50 $0 Sep 13 Sep 14 Sep 15 Sep 16 Sep 17 Sep 18 Helmerich & Payne, Inc. S&P 500 Index S&P 1500 Oil & Gas Drilling Index PHLX Oil Service Index 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 10-K. 32 Item 6. SELECTED FINANCIAL DATA The following table summarizes selected financial information and should be read in conjunction with Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8—“Financial Statements and Supplementary Data” included in this Form 10-K. Five-year Summary of Selected Financial Data Statements of Operations Selected Data 2018 2017 2016 (in thousands except per share amounts) 2015 2014 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,487,268 $ 1,804,741 $ 1,624,332 $ 3,161,702 $ 3,715,968 523,984 583,802 Depreciation and amortization . . . . . . . . . . . . . . . . . . . 135,273 200,619 Selling, general and administrative . . . . . . . . . . . . . . . 706,610 493,010 Income (loss) from continuing operations . . . . . . . . . . . (47) (10,338) Loss from discontinued operations . . . . . . . . . . . . . . . . 706,563 482,672 Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 585,543 151,002 (127,863) (349) (128,212) 608,039 134,712 420,474 (47) 420,427 598,587 146,183 (52,990) (3,838) (56,828) Per Share Data Basic earnings (loss) per share from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Basic loss per share from discontinued operations . . . Basic earnings (loss) per share . . . . . . . . . . . . . . . . . . Diluted earnings (loss) per share from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted loss per share from discontinued operations . . Diluted earnings (loss) per share . . . . . . . . . . . . . . . . . 4.49 (0.10) 4.39 4.47 (0.10) 4.37 (1.20) — (1.20) (1.20) — (1.20) (0.50) (0.04) (0.54) (0.50) (0.04) (0.54) Cash dividends declared per common share . . . . . . . . 2.82 2.80 2.78 3.88 — 3.88 3.85 — 3.85 2.75 6.52 — 6.52 6.44 — 6.44 2.63 Balance Sheet Data Property, plant and equipment, net . . . . . . . . . . . . . . . Total assets (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt to capital ratio (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net working capital (3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,857,382 6,214,867 493,968 5,001,051 6,439,988 492,902 5,144,733 6,832,019 491,847 5,563,170 7,147,242 492,443 5,188,544 6,725,316 39,502 10.1 % 10.6 % 9.7 % 9.1 % 0.8 % 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. 33 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 10-K as well as the Consolidated Financial Statements and related notes thereto included in Item 8— “Financial Statements and Supplementary Data” of this Form 10-K. Our future operating results may be affected by various trends and factors which are beyond our control. 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. 34 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. 35 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 after-tax 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 long-lived 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 fixed-rate 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 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,068,195 1,348,533 Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58,157 Selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 505,112 Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,695 Asset impairment charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Segment operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 150,698 Operating Statistics (1): Revenue days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig revenue per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig expense per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig margin per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77,980 23,411 14,182 9,229 350 2018 % Change 2017 (in thousands, except operating statistics) 43.7 % $ 1,439,523 37.0 984,205 14.7 50,712 1.1 499,486 100.0 — (258.8) (94,880) $ $ $ $ 57,120 22,607 14,623 7,984 350 45 % 36.5 % 3.6 (3.0) 15.6 — 35.6 61 % (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” 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 fixed-term contracts. Fixed-term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term (except in limited circumstances including sustained unacceptable performance by us). 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 fixed-term contracts, and 96 were working well-to-well. At November 9, 2018, the number of existing rigs under fixed-term contracts in the segment was 141 and the number of rigs working in the spot market was 95. 39 Offshore Operations Segment Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Segment operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Operating Statistics (1): Revenue days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig revenue per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig expense per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig margin per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2018 % Change 2017 (in thousands, except operating statistics) 4.6 % 5.1 21.6 (11.7) 7.9 136,263 96,593 3,705 11,764 24,201 142,500 101,477 4,507 10,392 26,124 $ $ 2,036 35,331 26,009 9,322 8 $ $ $ 70 % 2,277 34,332 23,172 11,160 8 74 % (10.6)% 2.9 12.2 (16.5) — (5.4) (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” 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 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset impairment charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Segment operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Operating Statistics (1): Revenue days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig revenue per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig expense per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig margin per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2018 % Change 2017 (in thousands, except operating statistics) 11.9 % 8.8 18.5 (12.7) 100.0 (90.5) 212,972 163,486 3,088 53,622 — (7,224) 238,356 177,938 3,658 46,826 10,617 (683) $ 6,696 33,830 24,211 9,620 32 49 % $ $ $ 4,951 40,979 29,761 11,218 38 36 % 35.2 % (17.4) (18.7) (14.2) (15.8) 36.1 (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses of $11,828 and $10,074 for fiscal years 2018 and 2017, respectively. Also excluded are the effects of currency revaluation income and expense. 40 Operating Loss The International Land segment had an operating loss of $0.7 million for fiscal year 2018 compared to an operating loss of $7.2 million for fiscal year 2017. Revenue Our activity has increased primarily in response to higher commodity prices. We experienced a 35.2 percent increase in revenue days when comparing fiscal year 2018 to fiscal year 2017. The average number of active rigs was 18.2 during fiscal year 2018 compared to 13.6 during fiscal year 2017. Direct Operating Expenses Although direct operating expenses increased in fiscal year 2018 to $177.9 million from $163.5 million in fiscal year 2017, the average rig expense per day decreased by $5,550, an 18.7 percent decrease as compared to the fiscal year 2017 average rig expense. Included in direct operating expenses are foreign currency transaction losses of $4.0 million and $6.0 million for fiscal years 2018 and 2017, respectively. The losses are primarily due to an ongoing devaluation of the Argentine peso beginning in December 2015. Depreciation Depreciation expense decreased 12.7 percent in fiscal year 2018 compared to fiscal year 2017. This decrease was due to several rig components in Argentina that became fully depreciated during fiscal year 2018. Asset Impairment Charge During the fourth quarter of fiscal year 2018, after ceasing operations in Ecuador, we entered into a sales negotiation with respect to six conventional rigs, 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 related to these rigs. 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). Utilization Utilization increased from 36 percent in fiscal year 2017 to 49 percent in fiscal year 2018. The increase was driven by the increase in rig activity as discussed above. Other Operations Results of our other operations, excluding corporate selling, general and administrative costs and corporate depreciation, are as follows: Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset impairment charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2018 % Change 2017 (in thousands, except operating statistics) 139.1 % 139.3 799.8 62.6 100.0 280.4 38,217 $ 44,390 15,801 8,332 5,637 15,983 18,552 1,756 5,124 — (9,449) (35,943) $ Operating Loss Other operations in fiscal year 2018 had an operating loss of $35.9 million compared to an operating loss of $9.4 million in fiscal year 2017. The change was primarily driven by the acquisition of MagVAR in December 2017 and twelve full months of operations of MOTIVE, which was acquired in June 2017. Refer to Note 3— Business Combinations of the Consolidated Financial Statements for additional disclosures. Asset Impairment Charge 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 where $4.7 million goodwill was allocated. This impairment loss is included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018. 41 Results of Operation for the Fiscal Years Ended September 30, 2017 and 2016 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 Loss Our net loss for fiscal year 2017 was $128.2 million ($1.20 loss per share) compared to a net loss of $56.8 million ($0.54 loss per share) for fiscal year 2016. Net loss in fiscal years 2017 and 2016 includes after-tax income from early termination revenue associated with drilling contracts terminated prior to the expiration of their fixed term of $20.2 million ($0.18 per share) and $139.3 million ($1.29 per share), respectively. Net loss in fiscal years 2017 and 2016 includes after-tax gains from the sale of assets of $14.3 million ($0.13 per share) and $6.1 million ($0.06 per share), respectively. Included in our fiscal year 2016 net loss is an after-tax loss of $15.9 million ($0.15 loss per share) from an other-than-temporary impairment of our marketable equity security position in Atwood Oceanics, Inc. (“Atwood”). Net loss in fiscal year 2016 also includes an after-tax loss of $12.0 million ($0.11 loss per share) from the settlement of litigation and a $3.8 million loss ($0.04 loss per share) from discontinued operations. Revenue Consolidated operating revenues were $1.8 billion in fiscal year 2017 and $1.6 billion in fiscal year 2016, including early termination revenue of $29.4 million and $219.0 million in each respective fiscal year. 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 57,120 in fiscal year 2017 and 36,984 in fiscal year 2016. Interest and Dividend Income Interest and dividend income was $5.9 million and $3.2 million in fiscal year 2017 and 2016, respectively. The higher income in fiscal year 2017 was primarily due to higher earnings on available cash equivalents and short-term investments. Direct Operating Expenses Direct operating costs in fiscal year 2017 were $1.2 billion and $0.9 billion in fiscal year 2016. The increase in fiscal year 2017 from fiscal year 2016 was primarily due to an increase in drilling activity. General and Administrative Expense General and administrative expenses totaled $151.0 million in fiscal year 2017 and $146.2 million in fiscal year 2016. During fiscal year 2017, we incurred transaction costs of $3.2 million related to our acquisition of MOTIVE. In addition, bonuses paid to employees increased in fiscal year 2017. Depreciation and Amortization Depreciation and amortization expense was $585.5 million in fiscal year 2017 and $598.6 million in fiscal year 2016. Depreciation and amortization includes abandonments of equipment of $42.6 million in fiscal year 2017 and $39.3 million in fiscal year 2016. Additionally, we recorded impairment charges on rig and rig related equipment of $6.3 million in fiscal year 2016. Depreciation expense, exclusive of abandonments, decreased three percent in fiscal year 2017 from fiscal year 2016. The decrease is primarily due to relatively lower levels of capital expenditures during fiscal year 2017 and legacy assets reaching the end of their depreciable lives. Abandonments were primarily due to the abandonment of used drilling equipment in both fiscal years. Interest Interest expense net of amounts capitalized totaled $19.7 million in fiscal year 2017 and $22.9 million in fiscal year 2016. Interest expense is primarily attributable to fixed-rate debt outstanding. There was a favorable adjustment to interest expense of $5.2 million in fiscal year 2017 related to the reversal of previously booked uncertain tax positions where the statute of limitations had expired. Capitalized interest was $0.3 million and $2.8 million in fiscal years 2017 and 2016, respectively. All of the capitalized interest is attributable to our rig construction and upgrade program. Income Taxes We had an income tax benefit of $56.7 million in fiscal year 2017 compared to an income tax benefit of $19.7 million in fiscal year 2016. The effective income tax rate was 30.7 percent in fiscal year 2017 and 27.1 percent in fiscal year 2016. 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. 42 Research and Development During fiscal years 2017 and 2016, we incurred $12.0 million and $10.3 million, respectively, of research and development expenses primarily related to the ongoing development of the rotary steerable system tools. U.S. Land Operations Segment Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,439,523 984,205 Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,712 Selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 499,486 Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset impairment charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Segment operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (94,880) Operating Statistics (1): Revenue days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig revenue per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig expense per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig margin per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57,120 22,607 14,623 7,984 350 2017 % Change 2016 (in thousands, except operating statistics) 15.9 % $ 1,242,462 63.0 603,800 1.3 50,057 (1.7) 508,237 (100.0) 6,250 (228.0) 74,118 $ $ $ $ 36,984 31,369 14,117 17,252 348 30 % 54.4 % (27.9) 3.6 (53.7) 0.6 50.0 45 % (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses of $148,218 and $82,337 for fiscal years 2017 and 2016, respectively. Operating Income (Loss) In fiscal year 2017, the U.S. Land segment had an operating loss of $94.9 million compared to operating income of $74.1 million in fiscal year 2016. Included in U.S. land revenues for fiscal years 2017 and 2016 is approximately $24.5 million and $219.0 million, respectively, from early termination of fixed-term contracts. Revenue Excluding early termination revenue of $428 and $5,921 per day for fiscal years 2017 and 2016, respectively, average revenue per day for fiscal year 2017 decreased by $3,269 to $22,179 from $25,448 in fiscal year 2016. Our activity increased year-over-year in response to higher commodity prices, resulting in a 54 percent increase in revenue days when comparing fiscal year 2017 to fiscal year 2016. However, legacy term contracts at high dayrates made up a lower proportion of our fiscal year 2017 activity due to continued contract expirations. Further, newly contracted rigs which made up a majority of our fiscal year 2017 activity were priced at relatively lower levels which reflected depressed market conditions. Direct Operating Expenses The average rig expense per day increased to $14,623 in fiscal year 2017 from $14,117 in fiscal year 2016. This increase was primarily attributable to start-up expenses related to rigs returning to work during fiscal year 2017. Depreciation Depreciation includes charges for abandoned equipment of $42.2 million and $38.8 million in fiscal years 2017 and 2016, respectively. Included in abandonments in fiscal year 2017 are older rig components that were replaced by upgrades to our rig fleet to meet customer demands for additional capabilities. Included in abandonments in fiscal year 2016 is the retirement of used drilling equipment. Excluding the abandonments, depreciation in fiscal year 2017 decreased from fiscal year 2016, primarily due to relatively low levels of capital expenditures during fiscal year 2017 and fiscal year 2016 and certain legacy assets reaching the end of their depreciable lives in fiscal year 2017 and fiscal year 2016. Asset Impairment Charge During fiscal year 2016, we recorded an asset impairment charge in the U.S. Land segment of $6.3 million to reduce the carrying value of rig and rig related equipment classified as held for sale to their estimated fair values, based on expected sales prices. Utilization Rig utilization increased to 45 percent in fiscal year 2017 from 30 percent in fiscal year 2016. The total number of rigs at September 30, 2017 was 350 compared to 348 rigs at September 30, 2016. The net increase is due to two new FlexRigs completed in fiscal year 2017 and included in our operating statistics. At September 30, 2017, 197 out of 350 existing rigs in the U.S. Land segment were generating revenue. Of the 197 rigs generating revenue, 100 were under fixed-term contracts, and 97 were working in the spot market. 43 Offshore Operations Segment Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Segment operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Operating Statistics (1): Revenue days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig revenue per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig expense per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig margin per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 % Change 2016 (in thousands, except operating statistics) (1.7)% (9.7) 7.0 (5.9) 54.6 138,601 106,983 3,464 12,495 15,659 136,263 96,593 3,705 11,764 24,201 $ $ 2,277 34,332 23,172 11,160 8 $ $ $ 74 % 2,708 26,973 19,381 7,592 9 82 % (15.9)% 27.3 19.6 47.0 (11.1) (9.8) (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses of $21,578 and $23,138 for fiscal years 2017 and 2016, 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 2017, the Offshore segment had operating income of $24.2 million compared to operating income of $15.7 million in fiscal year 2016. Revenue Average rig revenue per day and average rig margin per day increased in fiscal year 2017 compared to fiscal year 2016 primarily due to receiving full pricing during fiscal year 2017 after receiving lower pricing while on standby or other special dayrates during fiscal year 2016. Depreciation Depreciation decreased slightly by 5.9 percent in fiscal year 2017 compared to fiscal year 2016 due to the sale of a rig during fiscal year 2017 and some assets becoming fully depreciated during the year. Direct Operating Expenses Direct operating expense in fiscal year 2017 decreased by 9.7 percent compared to fiscal year 2016. This decrease was primarily due to two less rigs working during the year. International Land Operations Segment Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Segment operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Operating Statistics (1): Revenue days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average rig revenue per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig expense per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Average rig margin per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Number of rigs at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 % Change 2016 (in thousands, except operating statistics) (7.4)% $ 212,972 163,486 3,088 53,622 (7,224) 229,894 183,969 2,909 57,102 (14,086) $ 4,951 40,979 29,761 11,218 38 36 % $ $ $ 5,364 39,044 28,638 10,406 38 39 % (11.1) 6.2 (6.1) 48.7 (7.7)% 5.0 3.9 7.8 - (7.7) (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses of $10,074 and $20,458 for fiscal years 2017 and 2016, respectively. Also excluded are the effects of currency revaluation income and expense. Operating Loss The International Land segment had an operating loss of $7.2 million for fiscal year 2017 compared to an operating loss of $14.1 million for fiscal year 2016. Revenue Excluding early termination revenue of $955 per day in fiscal year 2017, the average rig margin per day for fiscal year 2017 compared to fiscal year 2016 decreased by $143 to $10,263. Low oil prices continued to have a negative effect on customer spending. As a result, we experienced an 8 percent decrease in revenue days when 44 comparing fiscal year 2017 to fiscal year 2016. The average number of active rigs was 13.6 during fiscal year 2017 compared to 14.7 during fiscal year 2016. Direct Operating Expenses Although direct operating expenses decreased in fiscal year 2017 to $163.5 million from $184.0 million in fiscal year 2016, the average rig expense per day increased $1,123 or 4 percent as compared to the fiscal year 2016 average rig expense. Included in direct operating expenses are foreign currency transaction losses of $6.0 million and $9.8 million for fiscal years 2017 and 2016, respectively. The fiscal year 2016 losses were primarily due to a devaluation of the Argentine peso in December 2015. Depreciation Depreciation decreased slightly by 6.1 percent in fiscal year 2017 compared to fiscal year 2016 due to some assets becoming fully depreciated during the year. Other Operations Results of our other operations, excluding corporate selling, general and administrative costs and corporate depreciation, are as follows: Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Direct operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2017 15,983 $ 18,552 % Change 2016 (in thousands, except operating statistics) 20.4 % 15.0 805.2 15.4 26.1 13,275 16,132 194 4,440 (7,491) 1,756 5,124 (9,449) $ Operating Loss Other operations in fiscal year 2017 had an operating loss of $9.4 million compared to an operating loss of $7.5 million in fiscal year 2016. The change was primarily driven by the acquisition of MOTIVE in June 2017. Refer to Note 3—Business Combinations of the Consolidated Financial Statements for additional disclosures. 45 Liquidity and Capital Resources Sources of Liquidity Our sources of available liquidity include existing cash balances on hand, cash flows from operations, and availability under our credit facility. Our liquidity requirements include meeting ongoing working capital needs, funding our capital expenditure projects, paying dividends declared, and repaying our outstanding indebtedness. Historically, we have financed operations primarily through internally generated cash flows. During periods when internally generated cash flows are not sufficient to meet liquidity needs, we will borrow from available credit sources, access capital markets or sell our portfolio securities. Likewise, if we are generating excess cash flows, we may invest in highly rated short-term money market and debt securities. These investments can include U.S. Treasury securities, U.S. Agency issued debt securities, corporate bonds, certificates of deposit and money market funds. We have continued to reinvest maturities and earnings during fiscal years 2018 and 2017. The securities are recorded at fair value. We may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity as necessary, fund our additional purchases, exchange or redeem Senior Notes, or repay any amounts under our credit facility. Our ability to access the debt and equity capital markets depends on a number of factors, including our credit rating, market and industry conditions and market perceptions of our industry, general economic conditions, our revenue backlog and our capital expenditure commitments. Cash Flows Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling rigs under contract, the dayrates we receive under those contracts, the efficiency with which we operate our drilling units, the timing of collections on outstanding accounts receivable, the timing of payments to our vendors for operating costs, and capital expenditures. To date, general inflationary trends have not had a material effect on our operating margins. As of September 30, 2018, we had $284.4 million of cash on hand and $41.5 million of short-term investments. Our cash flows for the fiscal years ended September 30, 2018, 2017 and 2016 are presented below: (in thousands) Net cash provided (used) by: 2018 Year Ended September 30, 2017 2016 As adjusted (Note 2) Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 544,531 (472,362) (309,189) (237,020) $ 361,631 (444,988) (300,829) $ (384,186) $ 754,531 (234,219) (344,135) $ 176,177 Operating Activities Net working capital excluding cash and short-term investments increased $87.6 million to $412.6 million as of September 30, 2018 from $325.0 million as of September 30, 2017 due primarily to an increase in accounts receivable and inventories of materials and supplies, offset by an increase in accrued liabilities. Net cash provided from operating activities was $544.5 million in fiscal year 2018 compared to $361.6 million in fiscal year 2017. The $182.9 million increase in cash provided by operating activities is primarily due to an increase in net income due to increased activity during the fiscal year. In fiscal year 2016, net cash provided from operating activities was $754.5 million. The $392.9 million decrease in cash provided by operating activities between fiscal years 2017 and 2016 was primarily due to a larger net loss reported in fiscal year 2017. Investing Activities Capital Expenditures Our investing activities are primarily related to capital expenditures for our fleet. Our capital expenditures were $466.6 million in 2018, $397.6 million in fiscal year 2017 and $257.2 million in fiscal year 2016. Our fiscal year 2019 capital spending is currently estimated to be between $650 million and $680 million. This estimate includes normal capital maintenance requirements, capital spending related to reactivating idle rigs, tubulars and other upgrades primarily related to improving our existing rig fleet. 46 Acquisition of Business During fiscal years 2018 and 2017, we paid $47.9 million and $70.4 million, respectively, net of cash acquired, for the acquisition of drilling technology companies. Sale of Assets Our proceeds from asset sales totaled $44.4 million in fiscal year 2018, $23.4 million in fiscal year 2017 and $21.8 million in fiscal year 2016. Income from asset sales in fiscal year 2018 totaled $22.7 million, $20.6 million in fiscal year 2017 and $9.9 million in fiscal year 2016. In each year we had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business included in operating activity within the statement of cash flow. Stock Portfolio Held We manage a portfolio of marketable securities consisting of common shares of Ensco plc (“Ensco”) and Schlumberger, Ltd. that, at the close of fiscal year 2018, had a fair value of $82.5 million. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. The portfolio is recorded at fair value on our balance sheet. During the fourth quarter of fiscal year 2016, we determined that the decline in fair value below our cost basis in Atwood Oceanics, Inc. (“Atwood”) was other than temporary. As a result, we recorded a non-cash charge totaling $26.0 million. In May 2017, Ensco announced that it entered into a definitive merger agreement under which Ensco would acquire Atwood in an all-stock transaction. The transaction closed on October 6, 2017. Under the terms of the merger agreement, we received 1.60 shares of Ensco for each share of our Atwood common stock. The securities in our portfolio are subject to a wide variety of market-related risks that could substantially reduce or increase the fair value of the holdings. In general, the portfolio is recorded at fair value on the balance sheet with changes in unrealized after-tax value reflected in the equity section of the balance sheet. Our stock portfolio held as of September 30, 2018 is presented below: Number September 30, 2018 Ensco plc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,400,000 $ Schlumberger, Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 467,500 $ of Shares Cost Basis Market Value (in thousands, except share amounts) 54,016 28,480 82,496 38,473 $ 34,760 $ 3,713 Financing Activities The increase of $8.4 million in net cash used by financing activities in fiscal year 2018 from fiscal year 2017 was primarily due to an excess tax benefit from stock-based compensation that occurred in 2017 and not in 2018. The decrease of $43.3 million in net cash used by financing activities between fiscal years 2017 and 2016 was primarily due to $40.0 million in cash used to payback long-term debt in fiscal year 2016. Dividends We paid dividends of $2.82, $2.80, and $2.78 per share during fiscal years 2018, 2017 and 2016, respectively. Total dividends were $308.4 million, $305.5 million, and $300.2 million in fiscal years 2018, 2017 and 2016, respectively. Adjusting for stock splits accordingly, we have increased the effective annual dividend per share every fiscal year for the past 46 years. The declaration and amount of future dividends is at the discretion of our Board of Directors and subject to our financial condition, results of operations, cash flows, and other factors our Board of Directors deems relevant. Credit Facilities On July 13, 2016, we entered into a $300 million unsecured revolving credit facility (the “2016 Credit Facility”) with a maturity date of July 13, 2021. The 2016 Credit Facility had a maximum of $75 million available to use as letters of credit. The majority of any borrowings under the facility would accrue interest at a spread over the London Interbank Offered Rate (LIBOR). We also paid a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees were determined according to a scale based on the Company’s debt to total capitalization ratio. The spread over LIBOR ranged from 1.125 percent to 1.75 percent per annum and commitment fees ranged from 0.15 percent to 0.30 percent per annum. Based on our debt to total capitalization on September 30, 2018, the spread over LIBOR and commitment fees would be 1.125 percent and 0.15 percent, respectively. There was a financial covenant in the facility that required us to maintain a total debt to total capitalization ratio of less than 50 percent. The 2016 Credit Facility contained additional terms, conditions, restrictions and covenants that we believe were usual and customary in 47 unsecured debt arrangements for companies of similar size and credit quality, including a limitation that priority debt (as defined in the agreement) could not exceed 17.5 percent of the net worth of the Company. As of September 30, 2018, there were no borrowings, but there were three letters of credit outstanding in the amount of $39.3 million. At September 30, 2018, we had $260.7 million available to borrow under the 2016 Credit Facility. Subsequent to September 30, 2018, the Company decreased one of the three letters of credit by $1.3 million, which increased availability under the facility to $262.0 million. Subsequent to our fiscal year-end, on November 13, 2018, we entered into a $750 million unsecured revolving credit facility (the “2018 Credit Facility”). In connection with entering into the 2018 Credit Facility, we terminated the 2016 Credit Facility. See Note 19-–Subsequent Events to our Consolidated Financial Statements for more information about the 2018 Credit Facility. The Company has a $12 million unsecured standalone line of credit facility, which is purposed for the issuance of bid and performance bonds, as needed, for international land operations. The Company currently has no outstanding obligations against this facility. The applicable agreements for all unsecured debt contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2018, we were in compliance with all debt covenants, and we anticipate that we will continue to be in compliance for the next fiscal year. Repurchase and Retirement of Common Shares We did not have any active stock repurchase program in fiscal years 2018, 2017, or 2016. We have an evergreen authorization to purchase up to four million shares per fiscal year. Future Cash Requirements Our operating cash requirements, scheduled debt repayments, interest payments, any declared dividends, and estimated capital expenditures, including our rig upgrade construction program, for fiscal year 2019 are expected to be funded through current cash and cash to be provided from operating activities. However, there can be no assurance that we will continue to generate cash flows at current levels. The long-term debt to total capitalization ratio was 10.1 percent at September 30, 2018 compared to 10.6 percent at September 30, 2017. Off-balance Sheet Arrangements We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K. For information regarding our drilling contract backlog, see Item 1— “Business — Contract Backlog”. 48 Material Commitments Our contractual obligations as of September 30, 2018 are summarized in the table below in thousands: Payments due by year Contractual Obligations — $ 500,000 Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . $ 500,000 $ 33,906 Interest (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,095 Operating leases (2) . . . . . . . . . . . . . . . . . . . . . . . . . — Purchase obligations (2) . . . . . . . . . . . . . . . . . . . . . Total contractual obligations . . . . . . . . . . . . . . $ 793,468 $ 142,734 $ 29,920 $ 27,607 $ 27,235 $ 26,971 $ 539,001 23,250 9,113 110,371 150,156 32,941 110,371 23,250 4,357 — 23,250 3,721 — 23,250 3,985 — 23,250 6,670 — Total 2021 2022 2023 2020 — $ — $ — $ — $ 2019 After 2023 (1) Interest on fixed-rate debt was estimated based on principal maturities. See Note 7--Debt to our Consolidated Financial Statements. (2) See Note 15—Commitments and Contingencies to our Consolidated Financial Statements. The above table does not include obligations for our pension plan or amounts recorded for uncertain tax positions. In fiscal years 2018 and 2017, we did not make any contributions to the pension plan. Contributions may be made in fiscal year 2019 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond fiscal year 2019 are difficult to estimate due to multiple variables involved. At September 30, 2018, we had $17.1 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in Note 8—Income Taxes to our Consolidated Financial Statements. Critical Accounting Policies and Estimates Accounting policies that we consider significant are summarized in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties to our Consolidated Financial Statements included in Part II, Item 8 – Financial Statements and Supplementary Data of this report. The preparation of our financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. These estimates and assumptions are evaluated on an on- going basis. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies and estimates used in our financial statements. Property, Plant and Equipment Property, plant and equipment, including renewals and betterments, are capitalized at cost, while maintenance and repairs are expensed as incurred. The interest expense applicable to the construction of qualifying assets is capitalized as a component of the cost of such assets. We account for the depreciation of property, plant and equipment using the straight-line method over the estimated useful lives of the assets considering the estimated salvage value of the property, plant and equipment. Both the estimated useful lives and salvage values require the use of management estimates. Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation or result in abandonments. For the fiscal years presented in this report, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations. Impairment of Long-lived Assets, Goodwill and Other Intangible Assets Management assesses the potential impairment of our long-lived assets and finite-lived intangibles whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts and/or overall changes in general market conditions. If a review of the long-lived assets and finite-lived intangibles indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge 49 is made, as required, to adjust the carrying value to the estimated fair value. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig’s marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics including utilization. The fair value of drilling rigs is determined based upon either an income approach using estimated discounted future cash flows or market approach, considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors. The use of different assumptions could increase or decrease the estimated fair value of assets and could therefore affect any impairment measurement. We review goodwill and indefinite-lived intangible assets for impairment annually in the fourth fiscal quarter or more frequently if events or changes in circumstances indicate that the carrying amount of such goodwill and indefinite- lived intangible assets may exceed their fair value. For impairment testing, goodwill is evaluated at the reporting unit level. We initially assess goodwill for impairment based on qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount. If further testing is necessary or a quantitative test is elected, we quantitatively compare the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds the fair value, an impairment charge will be recognized in an amount equal to the excess; however, the loss recognized would not exceed the total amount of goodwill allocated to that reporting unit. Impairment for indefinite-lived intangible assets is measured as the difference between the fair value of the asset and its carrying value. 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 drilling rig’s 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 an 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 fiscal years 2018 and 2016, we recognized $23.1 million and $6.3 million, respectively of asset impairment charges. Self-Insurance Accruals We self-insure a significant portion of expected losses relating to workers’ compensation, general liability, employer’s liability and automobile liability. Generally, deductibles range from $1 million to $5 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events but there can be no assurance that such coverage will respond or be adequate in all circumstances. Estimates are recorded for incurred outstanding liabilities for workers’ compensation and other casualty claims. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred. Estimates for liabilities and retained losses are based on adjusters’ estimates, our historical loss experience and statistical methods that we believe are reliable. We also engage an actuary to perform a periodic review of our domestic casualty losses. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs. 50 Our wholly-owned captive insurance company finances a significant portion of the physical damage risk on company-owned drilling rigs as well as international casualty deductibles. An actuary reviews our captive losses on an annual basis. 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. We self-insure a number of other risks, including loss of earnings and business interruption, and most cyber risks. Revenue Recognition Contract drilling revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met. Pension Costs and Obligations Our pension benefit costs and obligations are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan assets. Our discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was increased to 4.27 percent from 3.79 percent as of September 30, 2018 to reflect changes in the market conditions for high-quality fixed-income investments. The expected return on plan assets is determined based on historical portfolio results and future expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated from future periods. We anticipate pension expense to decrease by approximately $1.4 million in fiscal year 2019 from fiscal year 2018. Stock-Based Compensation Historically, we have granted stock-based awards to key employees and non-employee directors as part of their compensation. We estimate the fair value of all stock option awards as of the date of grant by applying the Black-Scholes option-pricing model. The application of this valuation model involves assumptions, some of which are judgmental and highly sensitive. These assumptions include, among others, the expected stock price volatility, the expected life of the stock options and the risk-free interest rate. Expected volatilities were estimated using the historical volatility of our stock based upon the expected term of the option. The expected term of the option was derived from historical data and represents the period of time that options are estimated to be outstanding. The risk-free interest rate for periods within the estimated life of the option was based on the U.S. Treasury Strip rate in effect at the time of the grant. The fair value of each award is amortized on a straight-line basis over the vesting period for awards granted to employees and non- employee directors. The fair value of restricted stock awards is determined based on the closing price of our common stock on the date of grant. We amortize the fair value of restricted stock awards to compensation expense on a straight-line basis over the vesting period. New Accounting Standards See Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties to our Consolidated Financial Statements for recently adopted accounting standards and new accounting standards not yet adopted. 51 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Foreign Currency Exchange Rate Risk Our drilling contracts in foreign countries generally provide for payment in U.S. dollars. However, in Argentina, while the contract is denominated in the U.S. dollar, we are paid in Argentine pesos. The Argentine branch of one of our second-tier subsidiaries then converts the Argentine pesos to U.S. dollars through the Argentine Foreign Exchange Market and then remits the dollars to its U.S. parent. In the future, other contracts or applicable law may require payments to be made in foreign currencies. As such, there can be no assurance that we will not experience in Argentina or elsewhere a devaluation of foreign currency, foreign exchange restrictions or other difficulties repatriating U.S. dollars even if we are able to negotiate the contract provisions designed to mitigate such risks. In the future, we may incur currency devaluations, foreign exchange restrictions or other difficulties repatriating U.S. dollars in Argentina or elsewhere, which could have a material adverse impact on our business, financial condition and results of operations. At September 30, 2018, a hypothetical decrease in value of 10 percent would result in an insignificant decrease in value of our monetary assets and liabilities denominated in Argentine pesos by approximately $4,595. 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. Commodity Price Risk The demand for contract drilling services is derived from exploration and production companies spending money to explore and develop drilling prospects in search of crude oil and natural gas. Their spending is driven by their cash flow and financial strength, which is affected by trends in crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including global supply and demand, the establishment of and compliance with production quotas by oil exporting countries, worldwide economic conditions and geopolitical factors. Crude oil and natural gas prices have historically been volatile and very difficult to predict with any degree of certainty. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining future spending levels. This volatility can lead many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices. Credit and Capital Market Risk Customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets, as experienced in the past, can make it difficult for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in customer credit defaults or reduced demand for our services, which could have a material adverse effect on our business, financial condition and results of operations. Similarly, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by, among other things, oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health of the drilling and overall oil and gas industry, and the liquidity of the capital markets. Many of the factors that affect our ability to access capital markets are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations. Further, we attempt to secure favorable prices through advanced ordering and purchasing for drilling rig components. While these materials have generally been available at acceptable prices, there is no assurance the prices will not vary significantly in the future. Any fluctuations in market conditions causing increased prices in materials and supplies could have a material adverse effect on future operating costs. Interest Rate Risk Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on any borrowings from our revolving credit facility. There were no outstanding borrowings under this facility at September 30, 2018, and our 52 outstanding debt consisted of $500 million in a senior unsecured note, which has a fixed rate of 4.65 percent. At September 30, 2018, the average interest rate risk on our fixed-rate debt of $500 million was estimated to be 4.65 percent after 2023. Comparatively, we estimated our interest rate risk at September 30, 2017 to be 4.65 percent after 2022. The fair value of the fixed-rate debt was estimated to be $509.3 million and $529.0 million for fiscal years 2018 and 2017, respectively. Equity Price Risk On September 30, 2018, we had a portfolio of securities with a total fair value of $82.5 million. The total fair value of the portfolio of securities was $70.2 million at September 30, 2017. A hypothetical 10 percent decrease in the market prices for all securities in our portfolio as of September 30, 2018 would decrease the fair value of our available-for-sale securities by $8.3 million. We make no specific plans to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the fair value of our holdings. The portfolio is recorded at fair value on the balance sheet with changes in unrealized after-tax value reflected in the equity section of the balance sheet unless a decline in fair value below our cost basis is considered to be other than temporary in which case the change is recorded through earnings. At November 8, 2018, the total fair value of our securities decreased to approximately $68.5 million. Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements. 53 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to Consolidated Financial Statements Management’s Report on Internal Control over Financial Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Financial Statements: Page 55 56 Consolidated Balance Sheets at September 30, 2018 and 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Operations for the Years Ended September 30, 2018, 2017 and 2016 . . . . . Consolidated Statements of Comprehensive Income (Loss) for the Years Ended September 30, 2018, 2017 and 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2018, 2017 and 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the Years Ended September 30, 2018, 2017 and 2016 . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 59 60 61 62 63 54 Management’s Report on Internal Control over Financial Reporting Management of Helmerich & Payne, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting was designed under the supervision of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America, and includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and the Board of Directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018. In making this assessment, management used the criteria established in the Internal Control— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the criteria in Internal Control-Integrated Framework (2013), management has concluded that the Company maintained effective internal control over financial reporting as of September 30, 2018. Ernst & Young LLP, an independent public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018, as stated in their report which appears herein. Helmerich & Payne, Inc. by /s/ John W. Lindsay John W. Lindsay Director, President and Chief Executive Officer /s/ Mark W. Smith Mark W. Smith Vice President and Chief Financial Officer November 16, 2018 November 16, 2018 55 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders of Helmerich & Payne, Inc. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. (the Company) as of September 30, 2018 and 2017, and the related consolidated statements of operations, comprehensive income (loss), shareholders' equity and cash flows for each of the three years in the period ended September 30, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2018, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 16, 2018, expressed an unqualified opinion thereon. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits include performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. We have served as the Company’s auditor since 1994. Tulsa, Oklahoma November 16, 2018 /s/Ernst & Young LLP 56 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders of Helmerich & Payne, Inc. Opinion on Internal Control over Financial Reporting We have audited Helmerich & Payne, Inc.’s internal control over financial reporting as of September 30, 2018, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Helmerich & Payne, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2018, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets as of September 30, 2018 and 2017, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2018, and the related notes and our report dated November 16, 2018 expressed an unqualified opinion thereon. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Tulsa, Oklahoma November 16, 2018 /s/ Ernst & Young LLP 57 HELMERICH & PAYNE, INC. Consolidated Balance Sheets (in thousands except share data and per share amounts) Assets Current Assets: September 30, 2018 2017 Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable, net of allowance of $6,217 and $5,721, respectively . . . . . . . . . . . . . . . . . . . . Inventories of materials and supplies, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Noncurrent Assets: $ 284,355 41,461 565,202 158,134 66,398 1,115,550 98,696 4,857,382 $ 521,375 44,491 477,074 137,204 55,123 1,235,267 84,026 5,001,051 Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64,777 73,207 5,255 143,239 51,705 50,785 17,154 119,644 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,214,867 $ 6,439,988 Liabilities and Shareholders’ Equity Current Liabilities: Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 132,664 244,504 377,168 $ 135,628 208,757 344,385 Noncurrent Liabilities: Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Noncurrent liabilities - discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total noncurrent liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Commitments and Contingencies (Note 15) 493,968 853,136 93,606 14,254 1,454,964 492,902 1,332,689 101,409 4,012 1,931,012 Shareholders' Equity: Common stock, $.10 par value, 160,000,000 shares authorized, 112,008,961 and 111,956,875 shares issued as of September 30, 2018 and 2017, respectively, and 108,993,718 and 108,604,047 shares outstanding as of September 30, 2018 and 2017, respectively . . . . . . . . . . . . . Preferred stock, no par value, 1,000,000 shares authorized, no shares issued . . . . . . . . . . . . . . . . . Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Treasury stock, at cost, 3,015,243 shares and 3,352,828 shares as of September 30, 2018 and 2017, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities and stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,201 — 500,393 4,027,779 16,550 11,196 — 487,248 3,855,686 2,300 (173,188) 4,382,735 $ 6,214,867 (191,839) 4,164,591 $ 6,439,988 The accompanying notes are an integral part of these consolidated financial statements. 58 HELMERICH & PAYNE, INC. Consolidated Statements of Operations (in thousands, except per share amounts) Operating revenues Year Ended September 30, 2017 2018 2016 Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,449,051 $ 1,788,758 $ 1,610,957 13,275 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,624,232 38,217 2,487,268 15,983 1,804,741 Operating costs and expenses Contract drilling operating expenses, excluding depreciation and amortization . . . . . . . Operating expenses applicable to other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Research and development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset impairment charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gain on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . Other income (expense) 1,626,387 26,223 583,802 18,167 200,619 23,128 (22,660) 2,455,666 31,602 1,242,605 6,712 585,543 12,047 151,002 — (20,627) 1,977,282 (172,541) 892,748 6,057 598,587 10,269 146,183 6,250 (9,896) 1,650,198 (25,966) Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gain (loss) on investment securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,166 (22,913) (25,989) (965) (46,701) (72,667) Income (loss) from continuing operations before income taxes . . . . . . . . . . . . . . . . . . . . . (19,677) Income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (52,990) Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,360 Income from discontinued operations before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . 6,198 Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,838) Net Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 482,672 $ (128,212) $ (56,828) Basic earnings per common share: 8,017 (24,265) 1 486 (15,761) 15,841 (477,169) 493,010 23,389 33,727 (10,338) 5,915 (19,747) — 1,775 (12,057) (184,598) (56,735) (127,863) 3,285 3,634 (349) Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Diluted earnings per common share: Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.49 $ (0.10) $ 4.39 $ 4.47 $ (0.10) $ 4.37 $ (1.20) $ — $ (1.20) $ (1.20) $ — $ (1.20) $ (0.50) (0.04) (0.54) (0.50) (0.04) (0.54) Weighted average shares outstanding (in thousands): Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108,851 109,387 108,500 108,500 107,996 107,996 The accompanying notes are an integral part of these consolidated financial statements. 59 HELMERICH & PAYNE, INC. Consolidated Statements of Comprehensive Income (Loss) (in thousands) Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 482,672 $ (128,212) $ Other comprehensive income (loss), net of income taxes: 2018 2016 (56,828) Year Ended September 30, 2017 Unrealized appreciation (depreciation) on securities, net of income taxes of $3.3 million at September 30, 2018, ($0.5) million at September 30, 2017 and $1.7 million at September 30, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reclassification of realized losses in net income, net of income taxes of $0.6 million at September 30, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Minimum pension liability adjustments, net of income taxes of $1.9 million at September 30, 2018, $1.9 million at September 30, 2017 and ($1.4) million at September 30, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,001 (829) 2,772 — — 926 5,249 14,250 3,333 2,504 (2,525) 1,173 (55,655) Comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 496,922 $ (125,708) $ The accompanying notes are an integral part of these consolidated financial statements. 60 . C N I , E N Y A P & H C R E M L E H I y t i u q E l ’ s r e d o h e r a h S f o s t n e m e t a t S d e t a d i l o s n o C 6 4 8 , 5 9 8 , 4 $ ) 3 6 3 , 2 8 1 ( $ 0 2 2 , 3 ) 7 7 3 , 1 ( $ l a t o T t n u o m A s e r a h S e m o c n I ) s s o L ( k c o t S y r u s a e r T e v i s n e h e r p m o C d e t a l u m u c c A r e h t O i d e n a t e R i s g n n r a E , 6 4 3 8 4 6 4 , $ 1 4 1 0 2 4 , $ l a n o i t i d d A n I - d a P i l a t i p a C k c o t S n o m m o C t n u o m A 9 9 0 1 1 , $ s e r a h S 7 8 9 0 1 1 , . . . . . . . . . . . . . . . . . . . . . . . . . . 5 1 0 2 , 0 3 r e b m e t p e S , e c n a a B l ) s t n u o m a e r a h s r e p t p e c x e , s d n a s u o h t n i ( 3 7 1 , 1 ) 8 2 8 , 6 5 ( ) 1 1 7 , 1 0 3 ( 4 3 9 0 4 0 , 1 ) 2 1 9 , 3 ( 3 8 3 , 4 2 2 1 ) 9 1 9 , 5 ( 9 9 3 3 7 1 , 1 ) 8 2 8 6 5 ( , ) 1 1 7 1 0 3 ( , 5 2 9 , 0 6 5 , 4 ) 0 7 2 , 8 8 1 ( 2 2 3 , 3 ) 4 0 2 ( , 7 0 8 9 8 2 4 , 4 0 5 , 2 ) 2 1 2 , 8 2 1 ( ) 9 0 9 , 5 0 3 ( 4 1 4 , 4 4 3 5 , 0 1 ) 8 4 8 , 5 ( 3 8 1 , 6 2 ) 6 4 2 , 5 ( 8 8 7 7 6 , 1 ) 7 5 ( 4 0 5 , 2 ) 2 1 2 8 2 1 ( , ) 9 0 9 5 0 3 ( , 1 9 5 , 4 6 1 , 4 ) 9 3 8 , 1 9 1 ( 3 5 3 , 3 0 0 3 , 2 , 6 8 6 5 5 8 3 , 0 5 2 , 4 1 2 7 6 , 2 8 4 ) 4 2 0 , 0 1 3 ( 0 5 2 , 4 1 2 7 6 2 8 4 , ) 4 2 0 0 1 3 ( , 4 3 9 7 3 9 6 , ) 3 4 9 3 ( , 3 8 3 4 2 , 2 5 4 8 4 4 , 2 2 9 1 0 2 2 3 9 1 0 4 1 1 1 , 0 0 4 1 1 1 , 4 1 4 4 , 8 3 7 5 1 , ) 9 3 5 7 ( , 3 8 1 6 2 , 8 4 2 7 8 4 , 2 4 4 1 5 1 4 2 4 1 6 9 1 1 1 , 7 5 9 1 1 1 , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s s o l t e N . e m o c n i i e v s n e h e r p m o c r e h t O i : e m o c n I e v s n e h e r p m o C ) e r a h s r e p l 8 7 . 2 $ ( d e r a c e d s d n e d v D i i l d e h h t i w s e r a h s f o t e n , s n o i t p o k c o t s e e y o p m e f o e s c r e x E i l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s e x a t e e y o p m e r o f l s d r a w a d e s a b - k c o t s f o t i f e n e b x a T r o f l d e h h t i w s e r a h s f o t e n , s d r a w a k c o t s d e t c i r t s e r f o g n i t s e V . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s e x a t e e y o p m e l . n o i t a s n e p m o c d e s a b - k c o t S . 6 1 0 2 , 0 3 r e b m e t p e S , e c n a a B l i : e m o c n I e v s n e h e r p m o C . . . . . . . . . . . . . . . . s s o l t e N s s o l i e v s n e h e r p m o c r e h t O ) e r a h s r e p l 0 8 . 2 $ ( d e r a c e d s d n e d v D i i l d e h h t i w s e r a h s f o t e n , s n o i t p o k c o t s e e y o p m e f o e s c r e x E i l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s e x a t e e y o p m e r o f l s d r a w a d e s a b - k c o t s f o t i f e n e b x a T r o f l d e h h t i w s e r a h s f o t e n , s d r a w a k c o t s d e t c i r t s e r f o g n i t s e V . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s e x a t e e y o p m e l . n o i t a s n e p m o c d e s a b - k c o t S . 7 1 0 2 , 0 3 r e b m e t p e S , e c n a a B l : e m o c n i i e v s n e h e r p m o C . . . . . . . . . . . . . . . e m o c n i t e N . e m o c n i i e v s n e h e r p m o c r e h t O ) e r a h s r e p l 2 8 . 2 $ ( d e r a c e d s d n e d v D i i l d e h h t i w s e r a h s f o t e n , s n o i t p o k c o t s e e y o p m e f o e s c r e x E i l 5 3 4 , 3 2 9 9 , 0 1 ) 2 0 2 ( 7 1 3 ) 3 9 1 , 4 ( 7 8 6 , 1 3 9 5 6 , 7 ) 6 3 1 ( 5 3 7 , 2 8 3 , 4 $ ) 8 8 1 , 3 7 1 ( $ 5 1 0 , 3 0 5 5 , 6 1 $ ) 5 5 5 ( , 9 7 7 7 2 0 4 , ) 7 5 5 7 ( , 2 7 8 ) 7 5 8 1 1 ( , 7 8 6 1 3 , 5 1 1 5 $ 3 9 3 0 0 5 , $ 1 0 2 1 1 , $ 9 0 0 2 1 1 , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s e x a t e e y o p m e r o f l r o f l d e h h t i w s e r a h s f o t e n , s d r a w a k c o t s d e t c i r t s e r f o g n i t s e V . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s e x a t e e y o p m e l . n o i t a s n e p m o c d e s a b - k c o t S ) 2 e t o N ( 9 0 - 6 1 0 2 U S A f o n o i t p o d A . . . . 8 1 0 2 , 0 3 r e b m e t p e S , e c n a a B l 61 . t n e m e a t s t l i a c n a n i f d e t a d i l o s n o c e s e h t f o t r a p l a r g e t n i n a i e r a s e t o n g n y n a p m o c c a e h T HELMERICH & PAYNE, INC. Consolidated Statements of Cash Flows (in thousands) Cash flows from operating activities: 2018 Year Ended September 30, 2017 2016 As adjusted (Note 2) Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 482,672 $ (128,212) $ Adjustment for income from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset impairment charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of debt discount and debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . Provision for (recovery of) bad debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pension settlement charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Gain) loss on investment securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gain from sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income tax (benefit) expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in assets and liabilities increasing (decreasing) cash: 583,802 23,128 1,067 2,193 31,687 913 (1) (22,660) (486,758) 6,710 585,543 — 1,055 2,016 26,183 1,640 — (20,627) (24,111) 543 349 (127,863) 10,338 493,010 Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventories of materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other noncurrent liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by operating activities from continuing operations . . . . . . . . . . . . . . . Net cash provided by (used in) operating activities from discontinued operations . . . . . . Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (85,202) (22,427) (955) (4,461) 33,173 2,268 (10,787) 544,700 (169) 544,531 (97,114) (10,607) 31,434 39,412 (36,120) 3,472 (13,075) 361,781 (150) 361,631 (56,828) 3,838 (52,990) 598,587 6,250 1,168 (2,013) 24,383 4,964 25,989 (9,896) 60,088 151 72,792 1,944 (2,460) (10,907) 49,562 3,703 (16,831) 754,484 47 754,531 Cash flows from investing activities: Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchase of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payment for acquisition of business, net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sale of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from asset sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (466,584) (71,049) (47,886) 68,776 44,381 (472,362) (397,567) (69,866) (70,416) 69,449 23,412 (444,988) (257,169) (57,276) — 58,381 21,845 (234,219) Cash flows from financing activities: (40,000) Payments on long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,111) Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (300,152) Dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,774 Proceeds from stock option exercises . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,646) Payments for employee taxes on net settlement of equity awards . . . . . . . . . . . . . . . . . . (344,135) Net cash used in financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176,177 Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 729,384 Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 284,355 $ 521,375 $ 905,561 — — (305,515) 11,285 (6,599) (300,829) (384,186) 905,561 — — (308,430) 6,355 (7,114) (309,189) (237,020) 521,375 Supplemental disclosure of cash flow information: Cash paid during the period: Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Income tax refund, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 20,502 $ 38,400 $ 22,936 $ 23,463 $ 28,011 24,109 Changes in accounts payable and accrued liabilities related to purchases of property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (2,245) $ (10,539) $ 15,879 The accompanying notes are an integral part of these consolidated financial statements. 62 HELMERICH & PAYNE, INC. Notes to Consolidated Financial Statements NOTE 1 NATURE OF OPERATIONS 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) through its operating subsidiaries 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. 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 primarily 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.”). Additionally, we focus on research and development of technology designed to improve the efficiency and accuracy of drilling operations. 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, multi-tenant industrial warehouse properties, and undeveloped real estate. NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, RISKS AND UNCERTAINTIES Basis of Presentation The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). We classified our former Venezuelan operation as a discontinued operation in the third quarter of fiscal year 2010, as more fully described in Note 4—Discontinued Operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates only to our continuing operations. Principles of Consolidation The consolidated financial statements include the accounts of Helmerich & Payne, Inc. and its domestic and foreign subsidiaries. Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary. Specifically, income and expenses of a subsidiary acquired or disposed of during the fiscal year are included in the consolidated statement of profit or loss and other comprehensive income from the date the Company gains control until the date when the Company ceases to control the subsidiary. All significant intercompany accounts and transactions have been eliminated in consolidation. Foreign Currencies Our functional currency, together with all our foreign subsidiaries, is the U.S. dollar. Monetary assets and liabilities denominated in currencies other than the U.S. dollar are translated at exchange rates in effect at the end of the period, and the resulting gains and losses are recorded on our statement of operations. Aggregate foreign currency losses of $4.0 million, $7.1 million and $9.3 million in fiscal years 2018, 2017 and 2016, respectively, are included in direct operating costs. Use of Estimates The preparation of our financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 63 Cash, Cash Equivalents, and Restricted Cash Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Our cash, cash equivalents and short-term investments are subject to potential credit risk, and certain of our cash accounts carry balances greater than the federally insured limits. We had restricted cash and cash equivalents of $41.8 million and $39.1 million at September 30, 2018 and 2017, respectively. Of the total at September 30, 2018 and 2017, $11.3 million and $9.4 million, respectively, is related to the acquisition of drilling technology companies described in Note 3—Business Combinations, $2.0 million as of both year ends is from the initial capitalization of the captive insurance company, and $28.5 million and $27.7 million, respectively, represents an additional amount management has elected to restrict for the purpose of potential insurance claims in our wholly-owned captive insurance company. The restricted amounts are primarily invested in short-term money market securities. See Note 2 for changes to the presentation of restricted cash effective October 1, 2018. The restricted cash and cash equivalents are reflected in the balance sheet as follows: September 30, 2018 2017 (in thousands) Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 39,830 2,000 $ $ 32,439 6,695 Inventories of Materials and Supplies Inventories are primarily replacement parts and supplies held for consumption in our drilling operations. Inventories are valued at the lower of cost or net realizable value. Cost is determined on a weighted average basis and includes the cost of materials, shipping, duties, labor and manufacturing overhead. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Our reserves during fiscal years 2018 and 2017 were 5.9 percent and 6.3 percent, respectively, of the balance to provide for non-recoverable inventory costs. The reserves for excess and obsolete inventory were $9.9 million and $9.2 million for fiscal years 2018 and 2017, respectively. Investments We maintain investments in equity securities of certain publicly traded companies. The cost of securities used in determining realized gains and losses is based on the average cost basis of the security purchased. We regularly review investment securities for impairment based on criteria that include the extent to which the investment’s carrying value exceeds its related fair value, the duration of the market decline and the financial strength and specific prospects of the issuer of the security. Unrealized gains are recognized in other comprehensive income. Unrealized losses that are other than temporary are recognized in earnings. See Note 2 for changes in accounting for investments effective October 1, 2018. Property, Plant, and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Substantially all property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets after deducting their residual values. The amount of depreciation expense we record is dependent upon certain assumptions, including an asset’s estimated useful life, rate of consumption, and corresponding salvage value. We periodically review these assumptions and may change one or more of these assumptions. Changes in our assumptions may require us to recognize, on a prospective basis, increased or decreased depreciation expense. We capitalize interest on major projects during construction. Interest is capitalized based on the average interest rate on related debt. Capitalized interest for fiscal years 2018, 2017 and 2016 was $0.4 million, $0.3 million and $2.8 million, respectively. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Changes that could prompt such an assessment include a 64 significant decline in revenue or cash margin per day, extended periods of low rig asset group utilization, changes in market demand for a specific asset, obsolescence, completion of specific contracts and/or overall general market conditions. If the review of the long-lived assets indicates that the carrying value of these assets/asset groups is more than the estimated undiscounted future cash flows projected to be realized from the use of the asset and its eventual disposal an impairment charge is made, as required, to adjust the carrying value down to the estimated fair value of the asset. The estimated fair value is determined based upon either an income approach using estimated discounted future cash flows or a market approach. Fair value is estimated, if applicable, considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors. Cash flows are estimated by management considering factors such as prospective market demand, margins, recent changes in rig technology and its effect on each rig’s marketability, any investment required to make a rig operational, suitability of rig size and make up to existing platforms, and competitive dynamics including industry utilization. Long-lived assets that are held for sale are recorded at the lower of carrying value or the fair value less costs to sell. Goodwill and Intangible Assets Goodwill represents the excess of purchase price over the fair value of net assets acquired in a business combination, at the date of acquisition. Goodwill and indefinite-life intangibles are not amortized but are tested for potential impairment at the reporting unit level at a minimum on an annual basis in the fourth fiscal quarter of each fiscal year or when indications of potential impairment exist. If an impairment is determined to exist, an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value is recognized, limited to the total amount of goodwill allocated to that reporting unit. The reporting unit level is defined as an operating segment or one level below an operating segment. Finite-lived intangible assets are amortized using the straight-line method over the period in which these assets contribute to our cash flows, generally estimated to be 15 years and are evaluated for impairment in accordance with our policies for valuation of long-lived assets. Drilling Revenues Contract drilling revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. For certain contracts, mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized on a straight- line basis over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs. Reimbursements for fiscal years 2018, 2017 and 2016 were $274.7 million, $179.9 million and $125.9 million, respectively. For contracts that are terminated by customers prior to the expirations of their fixed terms, contractual provisions customarily require early termination amounts to be paid to us. Revenues from early terminated contracts are recognized when all contractual requirements have been met. Early termination revenue for fiscal years 2018, 2017 and 2016 was approximately $17.1 million, $29.4 million and $219.0 million, respectively. Rent Revenues We enter into leases with tenants in our rental properties consisting primarily of retail and multi-tenant warehouse space. The lease terms of tenants occupying space in the retail centers and warehouse buildings generally range from three to ten years. Minimum rents are recognized on a straight-line basis over the term of the related leases. Overage and percentage rents are based on tenants’ sales volume. Recoveries from tenants for property taxes and operating expenses are recognized in other operating revenues in the Consolidated Statements of Operations. 65 Our rent revenues are as follows: 2018 Year Ended September 30, 2017 (in thousands) 2016 Minimum rents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Overage and percentage rents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,950 $ 1,040 $ 9,735 $ 936 $ 9,196 1,211 At September 30, 2018, minimum future rental income to be received on noncancelable operating leases was as follows: Fiscal Year 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Leasehold improvement allowances are capitalized and amortized over the lease term. $ Amount (in thousands) 7,709 6,314 4,473 2,488 1,725 4,868 27,577 $ At September 30, 2018 and 2017, the cost and accumulated depreciation for real estate properties were as follows: Real estate properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . September 30, 2018 2017 (in thousands) $ $ 69,133 (42,272) 26,861 $ $ 66,005 (42,169) 23,836 Income Taxes Current income tax expense is the amount of income taxes expected to be payable for the current fiscal year. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. We provide for uncertain tax positions when such tax positions do not meet the recognition thresholds or measurement standards prescribed in Accounting Standards Codification (“ASC”) 740, Income Taxes, which is more fully discussed in Note 8—Income Taxes. Amounts for uncertain tax positions are adjusted in periods when new information becomes available or when positions are effectively settled. We recognize accrued interest related to unrecognized tax benefits in interest expense and penalties in other expense in the Consolidated Statements of Operations. Earnings per Common Share Basic earnings per share is computed utilizing the two-class method and is calculated based on the weighted- average number of common shares outstanding during the periods presented. Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options and nonvested restricted stock. We have granted and expect to continue to grant to employees restricted stock grants that contain non-forfeitable rights to dividends. Such grants are considered participating securities under ASC 260, Earnings Per Share. As such, we have included these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method. Stock-Based Compensation Stock-based compensation expense is determined using a fair-value-based measurement method for all awards granted. In computing the impact, the fair value of each option is estimated on the date of grant based on the Black-Scholes options-pricing model utilizing assumptions for a risk free interest rate, volatility, dividend yield and 66 expected remaining term of the awards. The assumptions used in calculating the fair value of stock-based payment awards represent management’s best estimates, but these estimates involve inherent uncertainties and the application of management judgment. Stock-based compensation is recognized on a straight-line basis over the requisite service periods of the stock awards, which is generally the vesting period. Compensation expense related to stock options is recorded as a component of general and administrative expenses in the Consolidated Statements of Operations. Treasury Stock Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to additional paid-in capital using the average-cost method. Comprehensive Income or Loss Other comprehensive income or loss refers to revenues, expenses, gains, and losses that are included in comprehensive income or loss but excluded from net income or loss. We report the components of other comprehensive income or loss, net of tax, by their nature and disclose the tax effect allocated to each component in the Consolidated Statements of Comprehensive Income (Loss). Leases We lease office space and equipment for use in operations. Leases are evaluated at inception or upon any subsequent material modification and, depending on the lease terms, are classified as either capital leases or operating leases as appropriate under ASC 840, Leases. For operating leases that contain built-in pre-determined rent escalations, rent expense is recognized on a straight-line basis over the life of the lease. Leasehold improvements are capitalized and amortized over the lease term. We do not have significant capital leases. 67 Recently Issued Accounting Updates Changes to U.S. GAAP are established by the Financial Accounting Standards Board (“FASB”) in the form of Accounting Standard Updates (“ASUs”) to the FASB ASC. We consider the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs listed below. The following tables provide a brief description of recent accounting pronouncements and our analysis of the effects on our financial statements: Standard Description Recently Adopted Accounting Pronouncements Date of Adoption Effect on the Financial Statements or Other Significant Matters ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share- Based Payment Accounting October 1, 2017 The standard requires that all excess tax benefits and deficiencies previously recorded as additional paid-in capital be prospectively recorded in income tax expense. The adoption of this ASU could cause volatility in the effective tax rate on a quarter by quarter basis due primarily to fluctuations in the Company's stock price and the timing of stock option exercises and vesting of restricted share grants. The standard requires excess tax benefits to be presented as an operating activity on the statement of cash flows rather than as a financing activity. Excess tax benefits and deficiencies are recorded within the provision for income taxes within the Consolidated Statements of Operations on a prospective basis as required by the standard. The standard also requires taxes paid for employee withholdings to be presented as a financing activity on the statement of cash flows. We adopted this ASU during the first quarter of fiscal year 2018. We elected to present changes to the statement of cash flows on a retrospective basis as allowed by the standard in order to maintain comparability between fiscal years. As such, prior period cash flows from operations for the fiscal years ended September 30, 2017 and 2016 have been adjusted to reflect an increase of $4.4 million and $0.9 million, respectively, with a corresponding decrease to cash flows used in financing activities, compared to amounts previously reported. The standard also requires taxes paid for employee withholdings to be presented as a financing activity on the statement of cash flows but this requirement had no impact on our total financing activities as this has been the practice historically. We also elected to account for forfeitures of awards as they occur, instead of estimating a forfeiture amount. On October 1, 2017, we recorded a $0.3 million cumulative-effect adjustment to retained earnings for the differential between the amount of compensation cost previously recorded and the amount that would have been recorded without assuming forfeitures. ASU No. 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory The new guidance requires management to assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Disclosures are required when conditions give rise to substantial doubt. Substantial doubt is deemed to exist when it is probable that the company will be unable to meet its obligations within one year from the financial statement issuance date. This update simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with the lower of cost or net realizable value test. Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. September 30, 2017 We adopted ASU No. 2014-15, as required, on September 30, 2017 with no impact on our consolidated financial statements and disclosures. October 1, 2017 We adopted this ASU during the first quarter of fiscal year 2018. There was no impact on our consolidated financial statements. 68 ASU No. 2017-04, Intangibles— Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment The new guidance eliminates the requirement to calculate the implied fair value of goodwill (i.e., Step 2 of today’s goodwill impairment test) to measure a goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (i.e., measure the charge based on today’s Step 1). Standards that are not yet adopted as of September 30, 2018 June 30, 2017 As permitted, we early adopted this guidance effective June 30, 2017, with no impact on our consolidated financial statements. ASU No. 2018-14, Compensation – Retirement Benefits – Defined Benefit Plans—General (Topic 715-20): Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220) Reclassification of Certain Tax Effects From Accumulated Other Comprehensive Income This ASU amends ASC 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. October 1, 2021 We are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures. October 1, 2020 We are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures. October 1, 2019 We are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of its disclosure framework project, where entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose the range and weighted average used to develop significant unobservable inputs for Level 3 fair value measurements. This ASU relates to the impacts of the tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Reform Act”). The guidance permits the reclassification of certain income tax effects of the Tax Reform Act from Other Comprehensive Income to Retained Earnings. The guidance also requires certain new disclosures. This update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal periods and early adoption is permitted. Entities may adopt the guidance using one of two transition methods; retrospective to each period (or periods) in which the income tax effects of the Tax Reform Act related to the items remaining in Other Comprehensive Income are recognized or at the beginning of the period of adoption. ASU No. 2017-09, Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting Under the new guidance, modification accounting is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. Regardless of whether the change to the terms or conditions of the award requires modification accounting, the existing disclosure requirements and other aspects of U.S. GAAP associated with modification, such as earnings per share, continue to apply. October 1, 2018 We do not expect the new guidance to have a material impact on our consolidated financial statements. 69 ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost The ASU will change how employers that sponsor defined benefit pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Employers will present the other components of the net periodic benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income, if one is presented. October 1, 2018 We do not expect the new guidance to have a material impact on our consolidated financial statements. ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash The ASU requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. October 1, 2018 We will adopt the guidance retrospectively to all periods presented prior to the adoption date (October 1, 2018) by excluding the change in restricted cash balances from cash flows from operating activities. The impact of which will be an increase in the cash flows from operating activities in the fiscal years 2018 and 2017 by $2.7 million and $9.5 million, respectively. October 1, 2018 We do not expect the new guidance to have a material impact on our consolidated financial statements. ASU No. 2016-16, Income Taxes (Topic 740): Intra- Entity Transfers of Assets Other Than Inventory Under current U.S. GAAP, the tax effects of intra-entity asset transfers (intercompany sales) are deferred until the transferred asset is sold to a third party or otherwise recovered through use. This is an exception to the principle in ASC 740, Income Taxes, that generally requires comprehensive recognition of current and deferred income taxes. The new guidance eliminates the exception for all intra-entity sales of assets other than inventory. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller's tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer's jurisdiction would also be recognized at the time of the transfer. The new guidance does not apply to intra-entity transfers of inventory. The income tax consequences from the sale of inventory from one member of a consolidated entity to another will continue to be deferred until the inventory is sold to a third party. ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments The ASU is intended to reduce diversity in practice in presentation and classification of certain cash receipts and cash payments by providing guidance on eight specific cash flow issues. The ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. October 1, 2018 We plan to adopt this standard retrospectively to all periods presented. We are currently assessing the impact this standard will have on our consolidated statements of cash flows. ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326) This ASU introduces a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. The new model will apply to: (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and other financial assets measured at fair value through other comprehensive income/(loss), and (4) beneficial interests in securitized financial assets. This update is effective for annual and interim periods beginning after December 15, 2019. October 1, 2020 We are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures. 70 October 1, 2019 We are currently evaluating the potential impact of adopting this guidance on our consolidated financial statements and disclosures. ASU No. 2016-02, Leases (Topic 842) ASU 2016-02 will require organizations that lease assets — referred to as “lessees” — to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. Under ASU 2016-02, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Lessor accounting remains substantially similar to current U.S. GAAP. In addition, disclosures of leasing activities are to be expanded to include qualitative along with specific quantitative information. For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-02 mandates a modified retrospective transition method with an option to use certain practical expedients. ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606): Revenue from Contracts with Customers The standard requires entities to measure equity investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any changes in fair value in net income. The provisions of ASU 2016-01 are effective for interim and annual periods starting after December 15, 2017. At adoption, a cumulative-effect adjustment to beginning retained earnings will be recorded. October 1, 2018 October 1, 2018 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The update outlines a single comprehensive model for companies to use in accounting for revenue arising from contracts with customers and supersedes the most current revenue recognition guidance, including industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue when promised goods or services are transferred to customers in an amount that reflects the consideration to which the entity expects to be entitled for those goods or services. The update also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. Furthermore, as part of Topic 606, the FASB introduced ASC 340-40 Other Assets and Deferred Costs, which provides guidance on the capitalization of contract related costs that are not within the scope of other authoritative literature. The update will be effective for fiscal reporting periods beginning after December 15, 2017, including interim periods within the reporting period. Companies may use either a full retrospective or a modified retrospective approach to adopt the updates. Subsequent to adoption, changes in the fair value of our available-for-sale investments will be recognized in net income and the effect will be subject to stock market fluctuations. The cumulative catch up impact for the October 1, 2018 implementation will be a reclassification of $44 million, cumulative gains related to our available-for- sale securities, currently recorded in the beginning balance of the accumulated other comprehensive income, to beginning balance of retained earnings at October 1, 2018. We intend to adopt the new guidance using the modified retrospective approach. In preparation for our adoption of the new standard, we have evaluated representative samples of contracts and other forms of agreements with our customers based upon the five-step model specified by the new guidance. We have completed a preliminary assessment of the of the potential impact the implementation of this new guidance will have on our financial statements. Although our preliminary assessment may change based upon completion of our evaluation, the following summarizes the more significant impacts expected from the adoption of the new standard: • • • Certain revenues currently recognized at a point in time, are expected to be recognized over the term of the contract. Certain associated costs to fulfill these contracts that are currently being expensed at a point in time, are expected to be capitalized as a contract fulfillment cost and amortized over the contract term, including expected contract extensions. Enhance our disclosures to provide additional information relating to disaggregated revenue, contract assets and liabilities and remaining performance obligations. 71 Concentration of Credit Risk Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of temporary cash investments, short-term investments and trade receivables. The industry concentration has the potential to impact our overall exposure to market and credit risks, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. We had revenues from individual customers, related to our U.S. Land segment, that constituted 10 percent or more of our total revenues as follows: (In thousands) EOG Resources, Inc. . . . . . . . . . . . . . . . . . . . . . . . . $ 2018 2017 2016 258,194 $ 163,582 $ 124,262 In addition, we have certain customers that make up a significant portion of our Accounts Receivable at September 30, 2018, as indicated in the table below: EOG Resources, Inc. . . . . . . . . . . . . . . . Occidental Oil and Gas Corporation . . . . Percentage of Accounts Receivable 8.8 % 4.7 % We place temporary cash investments in the U.S. with established financial institutions and invest in a diversified portfolio of highly rated, short-term money market instruments. Our trade receivables, primarily with established companies in the oil and gas industry, may impact credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. International sales also present various risks including governmental activities that may limit or disrupt markets and restrict the movement of funds. Most of our international sales, however, are to large international or government-owned national oil companies. We perform credit evaluations of customers and do not typically require collateral in support for trade receivables. We provide an allowance for doubtful accounts, when necessary, to cover estimated credit losses. Such an allowance is based on management’s knowledge of customer accounts. Volatility of Market Our operations can be materially affected by oil and gas prices. Oil and natural gas prices have been historically volatile and difficult to predict with any degree of certainty. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining a customer’s future spending levels. This volatility, along with the difficulty in predicting future prices, can lead many exploration and production companies to base their capital spending on more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices. In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets may cause difficulty for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in a reduction in customer spending and the demand for our services. This reduction in spending could have a material adverse effect on our operations. Self-Insurance We have accrued a liability for estimated workers’ compensation and other casualty claims incurred based upon cash reserves plus an estimate of loss development and incurred but not reported claims. The estimate is based upon historical trends. Insurance recoveries related to such liability are recorded when considered probable. We self-insure a significant portion of expected losses relating to workers’ compensation, general liability and automobile liability. Generally, deductibles range from $1 million to $5 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates are recorded for incurred outstanding liabilities for workers’ compensation, general liability claims and claims that are incurred but not reported. Estimates are based on adjusters’ estimates, historic 72 experience and statistical methods that we believe are reliable. We have also engaged an actuary to perform a review of our domestic casualty losses. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs. International Land Drilling Operations International Land drilling operations may significantly contribute to our revenues and net operating income. There can be no assurance that we will be able to successfully conduct such operations, and a failure to do so may have an adverse effect on our financial position, results of operations, and cash flows. Also, the success of our international land operations will be subject to numerous contingencies, some of which are beyond management’s control. These contingencies include general and regional economic conditions, fluctuations in currency exchange rates, modified exchange controls, changes in international regulatory requirements and international employment issues, risk of expropriation of real and personal property and the burden of complying with foreign laws. Additionally, in the event that extended labor strikes occur or a country experiences significant political, economic or social instability, we could experience shortages in labor and/or material and supplies necessary to operate some of our drilling rigs, thereby potentially causing an adverse material effect on our business, financial condition and results of operations. 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 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 has a history of implementing currency controls which restrict the conversion and repatriation of US dollars. These controls were not in place in Argentina during this past fiscal year. Argentina’s economy is 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 subsidiaries 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. Because of the impact of local laws, our future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. While we believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms acceptable to us. NOTE 3 BUSINESS COMBINATIONS Fiscal Year 2018 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 with our other non-reportable business segments. 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. The grant date fair value of the restricted stock of $13.1 million is being amortized to expense over the three year vesting period. 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. The amount placed in escrow is classified as restricted cash and is included in prepaid expenses and other in the Consolidated Balance Sheet at September 30, 2018. Transaction costs related to the MagVAR Acquisition incurred during the fiscal year ended September 30, 2018 were approximately $1.2 million and are recorded in the Consolidated Statements of Operations within general and administrative expense. We recorded revenue of $11.6 million and a net loss of $3.0 million related to MagVAR during the fiscal year ended September 30, 2018. 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 73 directional drilling performance and wellbore placement. MagVAR technology has been successfully deployed in both onshore and offshore fields in North America, South America, Europe, Africa, Australia and Asia. The MagVAR Acquisition was accounted for as a business combination in accordance with ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. The following table summarizes the purchase price and the fair values of assets acquired and liabilities assumed at the acquisition date (in thousands): Purchase Price Consideration given Cash consideration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 48,485 Allocation of Purchase Price Fair value of assets acquired Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,286 13 28,700 17,791 Total assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 48,790 Fair value of liabilities assumed Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of total assets acquired and liabilities assumed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 305 48,485 Intangible assets acquired consist of developed technology, a trade name and customer relationships. The intangible assets are being amortized under a straight-line method over their estimated useful lives ranging from five to 20 years. The methodologies used in valuing the intangible assets include the multi-period excess earnings method for developed technology, the with and without method for customer relationships and the relief-from-royalty method for the trade name. The excess of the purchase price over the total net identifiable assets has been recorded as goodwill. Factors comprising goodwill include the synergies expected from the expanded service capabilities as well as the value of the assembled workforce. The goodwill is reported within our other non-reportable business segments and was allocated to our MagVAR reporting unit. The goodwill is not subject to amortization, but is evaluated at least annually for impairment in the fourth quarter of each fiscal year, or more frequently if impairment indicators are present. The intangible assets and goodwill are amortized straight-line over 15 years for income tax purposes. The following unaudited pro forma combined financial information is provided for the fiscal year ended September 30, 2018 and 2017, as though the MagVAR Acquisition had been completed as of October 1, 2016. These pro forma combined results of operations have been prepared by adjusting our historical results to include the historical results of MagVAR and reflect pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including application of an appropriate income tax to MagVAR’s pre-tax loss. Additionally, pro forma earnings for the fiscal year ended September 30, 2018 were adjusted to exclude $0.5 million of after-tax transaction costs. The unaudited pro forma combined financial information is provided for illustrative purposes only and is not necessarily indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this pro forma financial information. Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fiscal Year 2017 Acquisitions Pro Forma 2018 2017 (unaudited, in thousands) $ 1,814,215 (126,355) $ $ 2,490,955 480,423 $ 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 74 and is now a wholly-owned subsidiary of the Company. The operations for MOTIVE are included within our other non- reportable business segments. At the effective time of the MOTIVE Merger, MOTIVE shareholders received aggregate cash consideration of $74.3 million, net of customary closing adjustments, and may receive up to an additional $25.0 million in potential earnout payments based on future performance. At closing, $9.4 million of the cash consideration was placed in escrow, with one-half to be released to the seller on each of the twelve and eighteen month anniversaries of the merger completion date. Transaction costs related to the MOTIVE Merger incurred during fiscal year 2017 were $3.2 million and are recorded in the Consolidated Statement of Operations within the general and administrative expense line item. We recorded revenue of $12.9 million and $3.3 million and a net loss of $20.1 million and $2.2 million related to MOTIVE during the fiscal years ended September 30, 2018 and 2017, respectively. 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 increase 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. The MOTIVE Merger was accounted for as a business combination in accordance with ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. The following table summarizes the purchase price and the allocation of the fair values of assets acquired and liabilities assumed and separately identifiable intangible assets at the acquisition date (in thousands): Purchase Price Consideration given Cash consideration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term contingent earnout liability (Other noncurrent liabilities) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total consideration given . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Allocation of Purchase Price Fair value of assets acquired Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ $ 74,275 14,509 88,784 4,425 300 51,000 46,987 Total assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 102,712 Fair value of liabilities assumed Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of total assets acquired and liabilities assumed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ $ 25 13,903 13,928 88,784 Contingent consideration paid during fiscal year 2018 was $10.6 million. The fair value of the contingent consideration of $11.2 million and $14.9 million at September 30, 2018 and 2017, respectively, was calculated using a Monte Carlo simulation, which evaluates numerous potential earnings and pay out scenarios and is considered a Level 3 measurement under the fair value hierarchy. The change in the fair value of the contingent consideration of $6.9 million and $0.4 million during the fiscal year ended September 30, 2018 and 2017, respectively, was recorded in expenses applicable to other revenues in the Consolidated Statement of Operations. The developed technology is an intangible asset that will be amortized on a straight-line basis over an estimated 15-year life. The developed technology intangible asset was valued using an income approach, considering the estimated discounted future cash flows expected to be realized over the life of the asset, which is considered a Level 3 measurement under the fair value hierarchy. Goodwill represents the residual of the purchase price paid and consists largely of the synergies and economies of scale expected from the drilling technology providing more efficient drilling and directional drilling services, the first mover advantage obtained through the acquisition and expected future developments resulting from the assembled workforce. The goodwill is reported within our other non-reportable business segments and was allocated to our MOTIVE reporting unit. The goodwill is not subject to amortization but will be evaluated at least annually for impairment in the fourth quarter of each fiscal year or more frequently if impairment indicators are present. The developed technology and goodwill are not deductible for income tax purposes. An associated deferred tax liability has been recorded in regards to the developed technology. 75 NOTE 4 DISCONTINUED OPERATIONS Current and noncurrent liabilities consist of municipal and income taxes payable and social obligations due within the country in Venezuela. Expenses incurred for in-country obligations are reported as discontinued operations. The activity for the fiscal year ended September 30, 2018 was due to the remeasurement of uncertain tax liabilities as a result of the devaluation of the Venezuela Bolivar. Early in 2018, the Venezuelan government announced that it changed the existing dual-rate foreign currency exchange system by eliminating its heavily subsidized foreign exchange rate, which was 10 Bolivars per U.S. dollar, and relaunched an exchange system known as DICOM. The Venezuela government also established a new currency called the “Sovereign Bolivar,” which was determined by the elimination of five zeros from the old currency. The DICOM floating rate was approximately 62 Bolivars per U.S. dollar at September 30, 2018. The DICOM floating rate might not reflect the barter market exchange rates. NOTE 5 PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment as of September 30, 2018 and 2017 consisted of the following (in thousands): Contract drilling equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . Real estate properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . 4 - 15 years $ 10 - 45 years 2 - 23 years Estimated Useful Lives September 30, 2018 September 30, 2017 8,197,572 66,005 450,031 169,326 8,882,934 (3,881,883) 5,001,051 8,442,081 $ 68,888 471,310 163,968 9,146,247 (4,288,865) 4,857,382 $ $ 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 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 drilling rigs’ asset group is recoverable through estimated undiscounted cash flows with a surplus. 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 an 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, we entered into a sales negotiation with respect to the six conventional rigs, within a separate 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 76 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 within our International Land segment 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). The assets were recorded at fair value based on the sales agreement and as such are classified as Level 2 within the fair value hierarchy. 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. The assets were recorded at fair value based on the auction price and as such are classified as Level 2 of the fair value hierarchy. During fiscal year 2016, we recorded an asset impairment charge in the U.S. Land segment of $6.3 million to reduce the carrying value of rig and rig related equipment classified as held for sale to their estimated fair values, based on expected sales prices. Depreciation Depreciation in the Consolidated Statements of Operations of $583.8 million, $585.5 million and $598.6 million includes abandonments of $27.7 million, $42.6 million and $39.3 million for fiscal years 2018, 2017 and 2016, respectively. During 2018, we have shortened the estimated useful lives of certain components of rigs planned for conversion, with a total net book value of $3.7 million, resulting in an increase in depreciation expense during 2018 of approximately $9.7 million. This will also increase the depreciation expense for the next three months by approximately $0.9 million and will decrease the depreciation expense for fiscal years 2019, 2020, 2021, 2022, and 2023 by $2.3 million, $2.3 million, $2.2 million, $1.3 million, and $0.4 million, respectively, and thereafter by $1.0 million. Gain on Sale of Assets We had a gain on sales of assets of $22.7 million and $20.6 million in fiscal years 2018 and 2017, respectively. These gains were primarily related to drill pipe damaged or lost in drilling operations. NOTE 6 GOODWILL AND INTANGIBLE ASSETS Goodwill All of our goodwill is within our other non-reportable operating segments. The following is a summary of changes in goodwill (in thousands): Balance at September 30, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at September 30, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additions (Note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at September 30, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 4,718 46,987 51,705 17,791 (4,719) 64,777 77 Intangible Assets Intangible assets arising from business acquisitions consisted of the following: (in thousands) Finite-lived intangible asset: Developed technology . . . . . . . . . . . . . . . . . Trade name . . . . . . . . . . . . . . . . . . . . . . . . . Customer relationships . . . . . . . . . . . . . . . . . September 30, 2018 September 30, 2017 Gross Gross Carrying Accumulated Amount Amortization Carrying Accumulated Amount Amortization Net Net $ 70,000 5,700 4,000 $ 79,700 $ $ 5,589 237 667 6,493 $ 64,411 5,463 3,333 $ 73,207 $ 51,000 — — $ 51,000 $ $ 1,134 — — 1,134 $ 49,866 — — $ 49,866 Indefinite-lived intangible asset: Trademark . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ — $ 919 $ — $ 919 Amortization expense was $5.4 million and $1.1 million for fiscal years 2018 and 2017, respectively, and is estimated to be $5.8 million for each of the next four succeeding fiscal years and approximately $5.1 million for fiscal year 2023. Impairments 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 reporting unit, where $4.7 million of goodwill was allocated. We determined that the estimated fair value of this reporting unit was less than its carrying amount and we 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 assets 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. NOTE 7 DEBT We had the following unsecured long-term debt outstanding at rates and maturities shown in the following table: September 30, 2018 Unamortized Debt Issuance September 30, 2017 Unamortized Debt Issuance Face Amount Cost Book Value Face Amount Cost Book Value Unsecured senior notes issued March 19, 2015: Due March 19, 2025 . . . . . . . . . . . . . . . . . . Less long-term debt due within one year . . . . . Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . $ 500,000 $ $ 500,000 $ 500,000 — (in thousands) (6,032) $ 493,968 $ 500,000 $ (6,032) — 493,968 — (6,032) $ 493,968 $ 500,000 $ 500,000 — (7,098) $ 492,902 492,902 (7,098) — — (7,098) $ 492,902 On March 19, 2015, we issued $500 million of 4.65 percent 10-year unsecured senior notes. Interest is payable semi-annually on March 15 and September 15. The debt discount is being amortized to interest expense using the effective interest method. The debt issuance costs are amortized straight-line over the stated life of the obligation, which approximates the effective interest method. On July 13, 2016, we entered into a $300 million unsecured revolving credit facility (the “2016 Credit Facility”) with a maturity date of July 13, 2021. The 2016 Credit Facility had a maximum of $75 million available to use as letters of credit. The majority of any borrowings under the facility would accrue interest at a spread over the London Interbank Offered Rate (“LIBOR”). We also paid a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees were determined according to the Company’s credit rating. The spread over LIBOR ranged from 1.125 percent to 1.75 percent per annum and commitment fees ranged from 0.15 percent to 0.30 percent per 78 annum. Based on our debt to total capitalization on September 30, 2018, the spread over LIBOR and commitment fees would be 1.125 percent and 0.15 percent, respectively. There was a financial covenant in the facility that required us to maintain a total debt to total capitalization ratio of less than 50 percent. The 2016 Credit Facility contained additional terms, conditions, restrictions and covenants that we believe were usual and customary in unsecured debt arrangements for companies of similar size and credit quality including a limitation that priority debt (as defined in the agreement) could not exceed 17.5 percent of the net worth of the Company. As of September 30, 2018, the Company had no borrowings against the line, but there were three letters of credit outstanding in the amount of $39.3 million. Two of these letters of credit in the amount of $29.3 million support self-insured losses under the Company’s high deductible casualty insurance programs and the remaining $10.0 million letter of credit supports an operating line of credit with a bank in Argentina. As a result, at September 30, 2018, we had $260.7 million available to borrow under the 2016 Credit Facility. Subsequent to September 30, 2018, the Company decreased one of the three letters of credit by $1.3 million, which increased availability under the facility to $262.0 million. Subsequent to our fiscal year-end, on November 13, 2018, we entered into a $750 million unsecured revolving credit facility (the “2018 Credit Facility”). In connection with entering into the 2018 Credit Facility, we terminated the 2016 Credit Facility. See Note 19-–Subsequent Events to our Consolidated Financial Statements for more information about the 2018 Credit Facility. At September 30, 2018, we had a $12 million unsecured standalone line of credit, which is purposed for the issuance of bid and performance bonds, as needed, for international land operations. As of September 30, 2018, we do not have any outstanding obligations against this facility. The applicable agreements for all unsecured debt contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2018, we were in compliance with all debt covenants. At September 30, 2018, aggregate maturities of long-term debt are as follows (in thousands): Year ending September 30, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — 500,000 $ 500,000 NOTE 8 INCOME TAXES Impact of Tax Reform On December 22, 2017, the President of the United States signed into law the Tax Reform Act. Among a number of substantial changes to the current U.S. federal income tax rules, the Tax Reform Act decreases the marginal U.S. corporate income tax rate from 35 percent to 21 percent, provides for bonus depreciation that will allow for full expensing of qualified property in the year placed in service, limits the deductibility of certain expenditures, and significantly changes the U.S. taxation of certain foreign operations. By operation of law, we will apply a blended U.S. statutory federal income tax rate of 24.5 percent for fiscal year 2018. As a result of the Tax Reform Act, we were required to revalue deferred tax assets and liabilities from 35 percent to 21 percent. This revaluation has resulted in recognition of a tax benefit of approximately $502.1 million, which is included as a component of income tax expense in continuing operations on the Consolidated Statements of Operations. On December 22, 2017, Staff Accounting Bulletin No. 118 ("SAB 118") was issued to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Reform Act. In accordance with SAB 118, we recorded our best estimate of the impact of the Tax Reform Act in our fiscal year end income tax provision in accordance with our understanding of the Tax Reform Act and guidance available as of the date of this filing. Although we believe we have substantially completed our accounting for certain income tax effects of the Tax Reform Act, to the extent that the Internal Revenue Service or U.S. Treasury issues additional guidance during the SAB 118 measurement period, the Company will promptly evaluate whether any additional adjustments are required. 79 Income Tax Provision and Rate The components of the provision (benefit) for income taxes are as follows: 2018 Year Ended September 30, 2017 (in thousands) 2016 Current: Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 757 $ 6,492 2,340 9,589 (36,260) $ 4,108 (472) (32,624) (86,010) 9,987 (3,742) (79,765) Deferred: Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (508,256) 7,415 14,083 (486,758) Total benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (477,169) $ (14,953) (7,827) (1,331) (24,111) (56,735) $ 58,136 408 1,544 60,088 (19,677) The amounts of domestic and foreign income (loss) before income taxes are as follows: 2018 Year Ended September 30, 2017 (in thousands) 2016 Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 27,436 $ (173,157) $ (11,595) 15,841 $ (184,598) $ (11,441) (49,636) (23,031) (72,667) Effective income tax rates as compared to the U.S. Federal income tax rate are as follows: Year Ended September 30, 2017 2016 2018 U.S. Federal income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of foreign taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State income taxes, net of federal tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . U.S. domestic production activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Remeasurement of deferred tax related to Tax Reform Act . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other impact of foreign operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-deductible meals and entertainment (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity compensation (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Officer's compensation (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent consideration adjustment (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24.5 % 87.8 68.8 — (3,169.4) (43.4) 8.2 (5.3) 1.7 10.7 4.1 (3,012.3)% 35.0 % 1.8 0.6 (2.1) — (2.9) — — — — (1.7) 30.7 % 35.0 % (13.8) 3.2 (10.4) — 14.7 — — — — (1.6) 27.1 % (1) For fiscal years 2017 and 2016, “other” reflects adjustments for non-deductible meals and entertainment, equity compensation, officer’s compensation and contingent consideration. Effective tax rates differ from the U.S. federal statutory rate of 24.5 percent (blended for fiscal year 2018) due to state and foreign income taxes, change of the federal income tax rate from the Tax Reform Act, and the tax effect of non- deductible expenses (primarily related to certain meals and entertainment, officer’s compensation limited pursuant to Section 162(m) of the Code, and adjustments to the contingent consideration related to the MOTIVE Merger). Deferred Taxes Deferred income taxes are provided for the 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 valuation 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. 80 The components of our net deferred tax liabilities are as follows: September 30, 2018 2017 (in thousands) Deferred tax liabilities: Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 904,734 10,464 12,787 927,985 $ 1,386,512 24,940 21,609 1,433,061 Deferred tax assets: Pension reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Self-insurance reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net operating loss, foreign tax credit, and other federal tax credit carryforwards . . . . . . . . . . . . . . . . Financial accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,477 13,100 55,889 45,708 4,888 123,062 (48,213) 74,849 853,136 7,614 19,461 62,478 62,971 6,003 158,527 (58,155) 100,372 $ 1,332,689 $ The change in our net deferred tax assets and liabilities is impacted by foreign currency remeasurement. As of September 30, 2018, we had federal, state and foreign tax net operating loss carryforwards of $50.8 million, $31.2 million and $83.7 million, respectively, and foreign tax credit carryforwards of approximately $24.9 million (of which $20.1 million is reflected as a deferred tax asset in our Consolidated Financial Statements prior to consideration of our valuation allowance) which will expire in fiscal years 2019 through 2038. The valuation allowance is primarily attributable to foreign and certain state net operating loss carryforwards of $22.8 million and $0.5 million, respectively, and foreign tax credit carryforwards of $20.1 million, equity compensation of $2.3 million, and foreign minimum tax credit carryforwards of $2.5 million which more likely than not will not be utilized. Unrecognized Tax Benefits We recognize accrued interest related to unrecognized tax benefits in interest expense, and penalties in other expense in the Consolidated Statements of Operations. As of September 30, 2018 and 2017, we had accrued interest and penalties of $2.2 million and $2.8 million, respectively. A reconciliation of the change in our gross unrecognized tax benefits for the fiscal years ended September 30, 2018 and 2017 is as follows: September 30, 2018 2017 Unrecognized tax benefits at October 1, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross increases - tax positions in prior periods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross decreases - tax positions in prior periods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross decreases - current period effect of tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gross increases - current period effect of tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expiration of statute of limitations for assessments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unrecognized tax benefits at September 30, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ $ (in thousands) 4,773 3 — (280) 10,537 (128) 14,905 $ 9,551 — (1) (170) 300 (4,907) 4,773 As of September 30, 2018 and 2017, our liability for unrecognized tax benefits includes $14.3 million and $3.7 million, respectively, of unrecognized tax benefits related to discontinued operations that, if recognized, would not affect the effective tax rate. The remaining unrecognized tax benefits would affect the effective tax rate if recognized. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in our Consolidated Balance Sheets. For the next 12 months, we cannot predict with certainty whether we will achieve ultimate resolution of any uncertain tax position associated with our U.S. and international land operations that could result in increases or decreases of our unrecognized tax benefits. However, we do not expect the increases or decreases to have a material effect on our results of operations or financial position. 81 Tax Returns We file a consolidated U.S. federal income tax return, as well as income tax returns in various states and foreign jurisdictions. The tax years that remain open to examination by U.S. federal and state jurisdictions include fiscal years 2014 through 2017, with exception of certain state jurisdictions currently under audit. The tax years remaining open to examination by foreign jurisdictions include 2003 through 2017. NOTE 9 SHAREHOLDERS’ EQUITY The Company has authorization from the Board of Directors for the repurchase of up to four million common shares in any calendar year. The repurchases may be made using our cash and cash equivalents or other available sources. We had no purchases of common shares during the fiscal years ended September 30, 2018, 2017 and 2016. Accumulated Other Comprehensive Income (Loss) Components of accumulated other comprehensive income (loss) were as follows: Pre-tax amounts: Unrealized appreciation on securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Unrealized actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ After-tax amounts: Unrealized appreciation on securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Unrealized actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2018 September 30, 2017 (in thousands) 2016 44,023 $ (21,693) 22,330 $ 31,700 $ (28,873) 2,827 $ 33,051 (34,112) (1,061) 29,071 $ (12,521) 16,550 $ 20,070 $ (17,770) 2,300 $ 20,899 (21,103) (204) The following is a summary of the changes in accumulated other comprehensive income (loss), net of tax, by component for the fiscal year ended September 30, 2018: Unrealized Appreciation on Available-for-sale Securities Defined Benefit Pension Plan Total Balance at September 30, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Other comprehensive income before reclassifications . . . . . . . . . . . . . . . . . . . . . . . Amounts reclassified from accumulated other comprehensive income . . . . . . . . . . Net current-period other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at September 30, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (in thousands) 20,070 $ 9,001 — 9,001 29,071 $ (17,770) $ 2,300 9,001 5,249 14,250 (12,521) $ 16,550 — 5,249 5,249 82 The following provides detail about accumulated other comprehensive income (loss) components which were reclassified to the Consolidated Statements of Operations during the fiscal years ended September 30, 2018, 2017 and 2016: Details About Accumulated Other Comprehensive Income (Loss) Components Other-than-temporary impairment of available-for-sale securities . . . . . . . . . . . . . . . . . . . . . $ Amount Reclassified from Accumulated Other Comprehensive Income (Loss) 2018 2017 2016 (in thousands) Affected Line Item in the Consolidated Statements of Operations — $ — — — $ — — 1,509 Loss on investment securities Income tax provision (583) 926 Net of tax Amortization of net actuarial loss on defined benefit pension plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Total reclassifications for the period . . . . . . . . . . . . . . $ NOTE 10 STOCK-BASED COMPENSATION 7,180 $ (1,931) 5,249 5,249 $ 5,238 $ (3,968) Selling, general and administrative (1,905) 3,333 3,333 $ (1,599) 1,443 (2,525) Net of tax Income tax provision On March 2, 2016, the Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan (the “2016 Plan”) was approved by our stockholders. The 2016 Plan, among other things, authorizes the Human Resources Committee of the Board to grant non-qualified stock options and restricted stock awards to selected employees and to non-employee Directors. Restricted stock may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than market price of the underlying stock on the date of grant. Stock options expire 10 years after the grant date. Awards outstanding in the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan and the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan (collectively the “2010 Plan”) remain subject to the terms and conditions of those plans. During the fiscal year ended September 30, 2018, there were 693,873 non-qualified stock options and 411,977 shares of restricted stock awards granted under the 2016 Plan. An additional 213,904 of restricted stock grants were awarded outside of the 2016 Plan. A summary of compensation cost for stock-based payment arrangements recognized in general and administrative expense in fiscal years 2018, 2017 and 2016 is as follows: Compensation expense Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Stock Options 2018 September 30, 2017 (in thousands) 2016 7,913 $ 7,439 $ 23,774 31,687 $ 18,744 26,183 $ 8,290 16,093 24,383 Vesting requirements for stock options are determined by the Human Resources Committee of our Board of Directors. Options currently outstanding began vesting one year after the grant date with 25 percent of the options vesting for four consecutive years. We use the Black-Scholes formula to estimate the fair value of stock options granted to employees. The fair value of the options is amortized to compensation expense on a straight-line basis over the requisite service periods of the stock awards, which are generally the vesting periods. 83 The weighted-average fair value calculations for options granted within the fiscal period are based on the following weighted-average assumptions set forth in the table below. Options that were granted in prior periods are based on assumptions prevailing at the date of grant. Risk-free interest rate (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected stock volatility (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividend yield (3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected term (in years) (4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 % 36.1 % 4.7 % 6.0 2.0 % 38.9 % 3.7 % 5.5 1.8 % 37.6 % 4.6 % 5.5 2018 2017 2016 (1) The risk-free interest rate is based on U.S. Treasury securities for the expected term of the option. (2) Expected volatilities are based on the daily closing price of our stock based upon historical experience over a period which approximates the expected term of the option. (3) The dividend yield is based on our current dividend yield. (4) The expected term of the options granted represents the period of time that they are expect to be outstanding. We estimate term of option granted based on historical experience with grants and exercise. Based on these calculations, the weighted-average fair value per option granted to acquire a share of common stock was $13.17, $20.48 and $13.12 per share for fiscal years 2018, 2017 and 2016, respectively. The following summary reflects the stock option activity for our common stock and related information for fiscal years 2018, 2017 and 2016 (shares in thousands): 2018 2017 2016 Weighted-Average Weighted-Average Weighted-Average Shares Exercise Price Shares Exercise Price Shares Exercise Price Outstanding at October 1, . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . Forfeited/Expired . . . . . . . . . . . . . . . . . Outstanding on September 30, . . . . . . Exercisable on September 30, . . . . . . Shares available to grant . . . . . . . . . . . 3,278 $ 694 (375) (98) 3,499 $ 2,193 $ 5,140 56.41 59.03 36.88 70.77 58.62 56.31 3,312 $ 396 (415) (15) 3,278 $ 2,167 $ 5,624 51.74 76.61 38.04 68.32 56.41 50.87 2,776 $ 876 (220) (120) 3,312 $ 2,225 $ 6,600 48.51 58.25 31.52 61.80 51.74 46.66 The following table summarizes information about stock options at September 30, 2018 (shares in thousands): Outstanding Stock Options Weighted-Average Weighted-Average Exercisable Stock Options Weighted-Average Range of Exercise Prices $0.00 to $21.07 . . . . . . . . . . . . . . . . . . . . . . . . $21.07 to $59.76 . . . . . . . . . . . . . . . . . . . . . . . $59.76 to $68.83 . . . . . . . . . . . . . . . . . . . . . . . $68.83 to $81.31 . . . . . . . . . . . . . . . . . . . . . . . Options Remaining Life Exercise Price Options Exercise Price 180 2,417 358 544 3,499 0.2 $ 5.9 6.3 7.1 21.07 55.16 68.66 79.79 180 $ 1,418 275 320 2,193 21.07 53.03 68.83 79.86 At September 30, 2018, the weighted-average remaining life of exercisable stock options was 4.36 years and the aggregate intrinsic value was $30.9 million with a weighted-average exercise price of $56.31 per share. The number of options vested or expected to vest at September 30, 2018 was 1,306,087 with an aggregate intrinsic value of $10.6 million and a weighted-average exercise price of $62.49 per share. As of September 30, 2018, the unrecognized compensation cost related to the stock options was $7.3 million. That cost is expected to be recognized over a weighted-average period of 2.3 years. The total intrinsic value of options exercised during fiscal years 2018, 2017 and 2016 was $9.9 million, $13.1 million and $6.3 million, respectively. The grant date fair value of shares vested during fiscal years 2018, 2017 and 2016 was $8.8 million, $6.7 million and $9.6 million, respectively. 84 Restricted Stock Restricted stock awards consist of our common stock and are time-vested over three to six years. We recognize compensation expense on a straight-line basis over the vesting period. The fair value of restricted stock awards is determined based on the closing price of our shares on the grant date. As of September 30, 2018, there was $34.4 million of total unrecognized compensation cost related to unvested restricted stock awards. That cost is expected to be recognized over a weighted-average period of 2.4 years. A summary of the status of our restricted stock awards as of September 30, 2018, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2018, 2017 and 2016, is as follows (shares in thousands): 2018 2017 2016 Outstanding at October 1, . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . Vested (1) . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . Outstanding on September 30, . . . . . . Shares Weighted-Average Weighted-Average Grant Date Fair Value per Share Shares 70.76 59.53 70.60 66.73 63.74 648 $ 292 (271) (10) 659 $ Grant Date Fair Value per Share Shares 64.24 78.69 63.81 68.09 70.76 668 $ 294 (256) (58) 648 $ Weighted-Average Grant Date Fair Value per Share 67.03 58.25 64.75 63.65 64.24 659 $ 626 (258) (26) 1,001 $ (1) The number of restricted stock awards vested includes shares that we withheld on behalf of our employees to satisfy the statutory tax withholding requirements. NOTE 11 EARNINGS (LOSSES) PER COMMON SHARE The following table sets forth the computation of basic and diluted earnings per share: 2018 September 30, 2017 (in thousands) 2016 Numerator: Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 493,010 $ (127,863) $ (52,990) (3,838) Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (56,828) Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (349) (128,212) (10,338) 482,672 Adjustment for basic earnings per share Earnings allocated to unvested shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,346) (1,811) (1,858) Numerator for basic earnings per share: From continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . From discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 488,664 (10,338) 478,326 (129,674) (349) (130,023) (54,848) (3,838) (58,686) Adjustment for diluted earnings per share: Effect of reallocating undistributed earnings of unvested shareholders . . . . . . . . . . . . . . . 7 — — Numerator for diluted earnings per share: From continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . From discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 488,671 (10,338) (54,848) (3,838) $ 478,333 $ (130,023) $ (58,686) (129,674) (349) Denominator: Denominator for basic earnings per share - weighted-average shares. . . . . . . . . . . . . . . . Effect of dilutive shares from stock options and restricted stock . . . . . . . . . . . . . . . . . . . . . Denominator for diluted earnings per share - adjusted weighted-average shares . . . . . . . 108,851 536 109,387 108,500 — 108,500 107,996 — 107,996 Basic earnings per common share: Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.49 $ (0.10) 4.39 $ (1.20) $ — (1.20) $ Diluted earnings per common share: Income (loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.47 $ (0.10) 4.37 $ (1.20) $ — (1.20) $ (0.50) (0.04) (0.54) (0.50) (0.04) (0.54) We had a net loss for fiscal years 2017 and 2016. Accordingly, our diluted earnings per share calculation for those years were equivalent to our basic earnings per share calculation since diluted earnings per share excluded any 85 assumed exercise of equity awards. These were excluded because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable period. The following shares attributable to outstanding equity awards were excluded from the calculation of diluted earnings per share because their inclusion would have been anti-dilutive: Shares excluded from calculation of diluted earnings per share . . . . . . . . . . . . . . . . . . . . Weighted-average price per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2018 2017 (in thousands, except per share amounts) 1,788 63.73 1,559 68.28 1,008 74.38 2016 $ $ NOTE 12 FAIR VALUE MEASUREMENT OF FINANCIAL INSTRUMENTS We have certain assets and liabilities that are required to be measured and disclosed at fair value. Fair value is defined as the exchange price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date. We use the fair value hierarchy established in ASC 820-10 to measure fair value to prioritize the inputs: • • • Level 1 — Quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity can access at the measurement date. Level 2 — Observable inputs, other than quoted prices included in Level 1, such as quoted prices for similar assets or liabilities in active markets; quoted prices for similar assets and liabilities in markets that are not active; or other inputs that are observable or can be corroborated by observable market data. Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes pricing models, discounted cash flow methodologies and similar techniques that use significant unobservable inputs. The assets held in a Non-Qualified Supplemental Savings Plan are carried at fair value and totaled $16.2 million and $13.9 million at September 30, 2018 and 2017, respectively. The assets are comprised of mutual funds that are measured using Level 1 inputs. Short-term investments include securities classified as trading securities. Both realized and unrealized gains and losses on trading securities are included in other income (expense) in the Consolidated Statements of Operations. The securities are recorded at fair value. Our non-financial assets, such as intangible assets, goodwill and property, plant and equipment, are recorded at fair value when acquired in a business combination or when an impairment charge is recognized. If measured at fair value in the Consolidated Balance Sheets, these would generally be classified within Level 2 or 3 of the fair value hierarchy. Refer to Note 3—Business Combinations, Note 5—Property, Plant and Equipment and Note 6—Goodwill and Intangible Assets for details on these fair value measurements. The majority of cash equivalents are invested in highly-liquid money-market mutual funds invested primarily in direct or indirect obligations of the U.S. Government. The carrying amount of cash and cash equivalents approximates fair value due to the short maturity of those investments. The carrying value of other current assets, accrued liabilities and other liabilities approximated fair value at September 30, 2018 and 2017. 86 The following table summarizes our assets measured at fair value presented in our Consolidated Balance Sheet as of September 30, 2018: Recurring fair value measurements: Short-term investments: Fair Value (Level 1) (Level 2) (Level 3) (in thousands) Certificates of deposit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Corporate and municipal debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . U.S. government and federal agency securities . . . . . . . . . . . . . . . . . . . . . . . . Total short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets measured at fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 450,142 $ 431,124 $ 19,018 $ — $ — 22,443 22,443 284,355 82,496 39,830 2,000 17,518 22,443 41,461 284,355 82,496 39,830 2,000 17,518 — 19,018 — — — — 1,500 $ 1,500 $ — — — — — — — — — Liabilities: Contingent earnout liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 11,160 $ — $ — $ 11,160 At September 30, 2018, our financial instruments measured at fair value utilizing Level 1 inputs include cash equivalents, U.S. Agency issued debt securities, equity securities with active markets, and money market funds that are classified as restricted assets. The current portion of restricted amounts are included in prepaid expenses and other, and the noncurrent portion is included in other assets. For these items, quoted current market prices are readily available. At September 30, 2018, assets measured at fair value using Level 2 inputs include certificates of deposit, municipal bonds and corporate bonds measured using broker quotations that utilize observable market inputs. Our financial instruments measured using Level 3 inputs consist of potential earnout payments associated with the acquisition of MOTIVE in fiscal year 2017. The valuation techniques used for determining the fair value of the potential earnout payments use a Monte Carlo simulation which evaluates numerous potential earnings and pay out scenarios. The following table presents a reconciliation of changes in fair value of our financial assets and liabilities classified as Level 3 fair value measurements in the fair value hierarchy for the indicated periods: 2018 2017 (in thousands) Net liabilities at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 14,879 $ — Total gains or losses: Included in earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Settlements (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net liabilities at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,906 (10,625) 11,160 $ 14,879 — 14,879 $ (1) Settlements represent earnout payments that have been earned or paid during the period. The following information presents the supplemental fair value information about long-term fixed-rate debt at September 30, 2018 and September 30, 2017. Carrying value of long-term fixed-rate debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of long-term fixed-rate debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 494.0 509.3 $ $ 492.9 529.0 The fair value for the $500 million fixed-rate debt was based on broker quotes at September 30, 2018. The notes are classified within Level 2 of the fair value hierarchy as they are not actively traded in markets. On an ongoing basis we evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment September 30, 2018 2017 (in millions) 87 charge is recorded and a new cost basis established. We review several factors to determine whether a loss is other- than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. When securities are sold, the cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold. The estimated fair value of our available-for-sale securities, reflected on our Consolidated Balance Sheets as Investments, is based on Level 1 inputs. The following is a summary of available-for-sale securities, which excludes assets held in a Non-Qualified Supplemental Savings Plan: Gross Gross Estimated Unrealized Unrealized Gains Fair Losses Value Cost (in thousands) Equity Securities: September 30, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 38,473 $ 44,023 $ September 30, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 38,473 $ 31,700 $ — $ 82,496 — $ 70,173 NOTE 13 EMPLOYEE BENEFIT PLANS We maintain a domestic noncontributory defined benefit pension plan covering certain U.S. employees who meet certain age and service requirements. In July 2003, we revised the Helmerich & Payne, Inc. Employee Retirement Plan (“Pension Plan”) to close the Pension Plan to new participants effective October 1, 2003, and reduce benefit accruals for current participants through September 30, 2006, at which time benefit accruals were discontinued and the Pension Plan was frozen. The following table provides a reconciliation of the changes in the pension benefit obligations and fair value of Pension Plan assets over the two-year period ended September 30, 2017 and a statement of the funded status as of September 30, 2018 and 2017: Accumulated Benefit Obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in projected benefit obligations Projected benefit obligation at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Actuarial (gain) loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Projected benefit obligation at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in plan assets Fair value of plan assets at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Employer contribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of plan assets at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Funded status of the plan at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2018 2017 (in thousands) $ 106,205 $ 109,976 $ 109,976 4,077 (2,143) (5,705) $ 106,205 $ 109,731 4,053 3,633 (7,441) $ 109,976 $ $ $ 92,816 7,754 32 (5,705) 94,897 (11,308) $ $ $ 90,748 9,470 39 (7,441) 92,816 (17,160) The amounts recognized in the Consolidated Balance Sheets at September 30, 2018 and 2017 are as follows (in thousands): Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Noncurrent liabilities-other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net amount recognized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (11,250) $ (11,308) (58) $ (45) (17,115) $ (17,160) The amounts recognized in Accumulated Other Comprehensive Income (Loss) at September 30, 2018 and 2017, and not yet reflected in net periodic benefit cost, are as follows (in thousands): Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (21,693) $ (28,873) 88 The amount recognized in Accumulated Other Comprehensive Income (Loss) and not yet reflected in periodic benefit cost expected to be amortized in next year’s periodic benefit cost is a net actuarial loss of $1.2 million. The weighted average assumptions used for the pension calculations were as follows: September 30, 2018 2017 2016 Discount rate for net periodic benefit costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Discount rate for year-end obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.79 % 3.64 % 4.27 % 4.27 % 3.79 % 3.64 % 6.06 % 6.17 % 5.89 % The mortality table issued by the Society of Actuaries in October 2018 was used for the September 30, 2018 pension calculation. The new mortality information reflects improved life expectancies and projected mortality improvements. We did not make any contributions to the Pension Plan in fiscal year 2018. In fiscal year 2019, we do not expect minimum contributions required by law to be needed. However, we may make contributions in fiscal year 2019 if needed to fund unexpected distributions in lieu of liquidating pension assets. Components of the net periodic pension expense (benefit) were as follows: Year Ended September 30, 2018 2017 (in thousands) 2016 Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Recognized net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Settlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net pension expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (5,555) 1,926 913 1,361 $ (5,130) 2,891 1,640 3,454 $ 4,266 (5,616) 2,083 4,964 5,697 4,077 $ 4,053 $ We record settlement expense when benefit payments exceed the total annual service and interest costs. The following table reflects the expected benefits to be paid from the Pension Plan in each of the next five fiscal years, and in the aggregate for the five years thereafter (in thousands). 2019 2020 Year Ended September 30, 2022 2021 2023 2024 – 2028 Total $ 18,075 $ 7,433 $ 5,684 $ 6,351 $ 6,665 $ 31,813 $ 76,021 Included in the Pension Plan is an unfunded supplemental executive retirement plan. Investment Strategy and Asset Allocation Our investment policy and strategies are established with a long-term view in mind. The investment strategy is intended to help pay the cost of the Pension Plan while providing adequate security to meet the benefits promised under the Pension Plan. We maintain a diversified asset mix to minimize the risk of a material loss to the portfolio value that might occur from devaluation of any single investment. In determining the appropriate asset mix, our financial strength and ability to fund potential shortfalls are considered. Pension Plan assets are invested in portfolios of diversified public- market equity securities and fixed income securities. The Pension Plan does not directly hold securities of the Company. The expected long-term rate of return on Pension Plan assets is based on historical and projected rates of return for current and planned asset classes in the Pension Plan’s investment portfolio after analyzing historical experience and future expectations of the return and volatility of various asset classes. 89 The target allocation for 2019 and the asset allocation for the Pension Plan at the end of fiscal years 2018 and 2017, by asset category, follows: Asset Category U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fixed income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Real estate and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Target Allocation 2019 Percentage of Plan Assets at September 30, 2017 2018 45 % 20 35 — 100 % 52 % 15 33 — 100 % 50 % 16 34 — 100 % Plan Assets The fair value of Pension Plan assets at September 30, 2018 and 2017, summarized by level within the fair value hierarchy described in Note 12—Fair Value Measurement of Financial Instruments, are as follows: Short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Mutual funds: 2,745 $ (in thousands) 2,745 $ — $ — Fair Value as of September 30, 2018 Total Level 1 Level 2 Level 3 Domestic stock funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bond funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balanced funds. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International stock funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total mutual funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Domestic common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 94,897 $ 92,320 $ 18,361 17,918 17,977 14,548 68,804 23,232 116 18,361 17,918 17,977 14,548 68,804 20,771 — — — — — — 2,461 — 2,461 $ — — — — — — 116 116 Fair Value as of September 30, 2017 Total Level 1 Level 2 Level 3 Short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Mutual funds: 3,488 $ (in thousands) 3,488 $ — $ Domestic stock funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bond funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balanced funds. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . International stock funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total mutual funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Domestic common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 92,816 $ 92,719 $ 18,377 18,357 18,222 14,583 69,539 19,692 97 18,377 18,357 18,222 14,583 69,539 19,692 — — — — — — — — — $ — — — — — — — 97 97 The Pension Plan’s financial assets utilizing Level 1 inputs are valued based on quoted prices in active markets for identical securities. The Pension Plan’s Level 2 financial assets include foreign common stock. The Pension Plan’s assets utilizing Level 3 inputs consist of oil and gas properties. The fair value of oil and gas properties is determined by Wells Fargo Bank, N.A., based upon actual revenue received for the previous twelve-month period and experience with similar assets. 90 The following table sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the fiscal years ended September 30, 2018 and 2017: Oil and Gas Properties Year Ended September 30, 2018 2017 (in thousands) Balance, beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unrealized gains (losses) relating to property still held at the reporting date . . . . . . . . . . . . . . . . . . . . . . . . . Balance, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 97 19 116 $ $ 177 (80) 97 Defined Contribution Plan Substantially all employees on the U.S. payroll may elect to participate in our 401(k)/Thrift Plan by contributing a portion of their earnings. We contribute an amount equal to 100 percent of the first five percent of the participant’s compensation subject to certain limitations. The annual expense incurred for this defined contribution plan was $26.6 million, $16.6 million and $21.6 million in fiscal years 2018, 2017 and 2016, respectively. During fiscal year 2016, we determined that employee workforce reductions which started during 2015 and continued into 2016 due to reduced drilling activity resulted in a partial plan termination of the 401(k)/Thrift Plan. Partial plan terminations result in affected participants becoming fully vested in Company contributions and actual earnings thereon at the termination date. As a result of the partial plan termination status, we accrued additional employer contributions totaling $6.3 million in general and administrative expense in fiscal year 2016. NOTE 14 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in our reserve for bad debt for fiscal years 2018, 2017 and 2016: Reserve for bad debt: Balance at October 1, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Provision for (recovery of) bad debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Write-off) recovery of bad debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at September 30, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5,721 $ 2,193 (1,697) 6,217 $ 2,696 $ 2,016 1,009 5,721 $ 6,181 (2,013) (1,472) 2,696 2018 2017 (in thousands) 2016 91 Accounts receivable, prepaid expenses and other current assets, accrued liabilities and long-term liabilities at September 30, 2018 and 2017 consist of the following: September 30, 2018 2017 (in thousands) Accounts receivable, net of reserve: Trade receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total accounts receivable, net of reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 530,859 34,343 $ 565,202 $ 398,348 78,726 $ 477,074 Prepaid expenses and other current assets: Restricted cash. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred mobilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid value added tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid maintenance and rent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid multi-flex rig fabrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities: Accrued operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payroll and employee benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Taxes payable, other than income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Self-insurance liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred mobilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Escrow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Litigation and claims . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Noncurrent liabilities — Other: Pension and other non-qualified retirement plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Self-insurance liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contingent earnout liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred mobilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Uncertain tax positions including interest and penalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total noncurrent liabilities — other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 39,830 6,484 6,149 1,931 8,526 1,327 2,151 66,398 $ 37,528 80,915 50,683 15,887 20,527 9,662 7,375 11,258 1,749 8,920 $ 244,504 $ $ 35,051 39,380 11,160 2,738 2,870 2,407 93,606 $ $ 32,439 6,458 4,060 3,870 5,940 — 2,356 55,123 $ 36,949 54,941 35,638 22,159 25,893 9,828 8,011 4,690 1,779 8,869 $ 208,757 $ 37,989 29,037 14,879 7,689 3,562 8,253 $ 101,409 NOTE 15 COMMITMENTS AND CONTINGENCIES Purchase Commitments Equipment, parts and supplies are ordered in advance to promote efficient construction and capital improvement progress. At September 30, 2018, we had purchase commitments for equipment, parts and supplies of approximately $110.4 million. Guarantee Arrangements In the normal course of our business, we enter into agreements with financial institutions to provide letters of credit and surety bonds in connection with certain commitments entered into by us. We are contingently liable to these financial institutions in respect of such letters of credit and bonds and have agreed to indemnify the financial institutions for any payments made by them in respect of such letters of credit and bonds. None of these balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements. Lease Obligations At September 30, 2018, we were leasing our corporate office headquarters near downtown Tulsa, Oklahoma. We also lease other office space and equipment for use in operations. 92 Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of a year at September 30, 2018 are as follows: Fiscal Year 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amount (in thousands) 9,113 $ 6,670 4,357 3,985 3,721 5,095 32,941 $ Total rent expense was $13.7 million, $14.0 million and $13.5 million for fiscal years 2018, 2017 and 2016, respectively. The future minimum lease payments for our Tulsa corporate office is a material portion of the amounts shown in the table above. This lease agreement commenced on May 30, 2003 and has subsequently been amended, most recently on August 25, 2017. The agreement will expire on January 31, 2025; however, we have two five-year renewal options. Contingencies We are party to legal proceedings and regulatory actions from time to time, including a number of cases which are currently pending. We maintain insurance against certain business risks subject to certain deductibles. With the exception of the matters discussed below, none of these legal actions are expected to have a material adverse effect on our financial condition, cash flows or results of operations. During the ordinary course of our business, contingencies arise resulting from an existing condition, situation, or set of circumstances involving an uncertainty as to the realization of a possible gain contingency. We account for gain contingencies in accordance with the provisions of ASC 450, Contingencies, and, therefore, we do not record gain contingencies and recognize income until realized. The property and equipment of our Venezuelan subsidiary was seized by the Venezuelan government on June 30, 2010. Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. (“HPIDC”) and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. (“PDVSA”) and PDVSA Petroleo, S.A. (“Petroleo”). Our subsidiaries seek damages for the taking of their Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No contingent gains were recognized in our Consolidated Financial Statements during the fiscal years ended September 30, 2018, 2017 and 2016. NOTE 16 BUSINESS SEGMENTS AND GEOGRAPHIC INFORMATION Description of the Business We are a global contract drilling company based in Tulsa, Oklahoma with operations in all major U.S. onshore basins as well as South America and the Middle East. Our contract drilling operations consist mainly of contracting Company-owned drilling equipment primarily to large oil and gas exploration companies. We are the recognized industry leader in drilling as well as technological innovation. At September 30, 2018, our contract drilling business includes the following reportable operating segments: • U.S. Land • Offshore • International Land 93 Each reportable operating segment is a strategic business unit that is managed separately and consolidated revenues and expenses reflect the elimination of all material intercompany transactions. Other includes additional non- reportable operating segments. Revenues included in “other” consist of revenue from our drilling technology services as well as rental income. Segment Performance We evaluate segment performance based on income or loss from continuing operations (segment operating income) before income taxes which includes: • Revenues from external and internal customers • Direct operating costs • Depreciation and • Allocated general and administrative costs but excludes acquisition related costs, corporate costs for other depreciation, income from asset sales and other corporate income and expense. General and administrative costs are allocated to the segments based primarily on specific identification and, to the extent that such identification is not practical, on other methods which we believe to be a reasonable reflection of the utilization of services provided. September 30, 2018 (in thousands) External Sales . . . . . . . . . . . . . . . . . . . . . . . $ 2,068,195 $ 142,500 $ Intersegment . . . . . . . . . . . . . . . . . . . . . . . . Total Sales . . . . . . . . . . . . . . . . . . . . . . . . U.S. Land Offshore 1,189 2,069,384 — 142,500 Segment Operating Income (Loss) . . . . . . . Depreciation and Amortization . . . . . . . . . . . Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . Additions to Long-Lived Assets . . . . . . . . . . 150,698 505,112 5,012,378 441,624 26,124 10,392 105,439 4,326 (in thousands) External Sales . . . . . . . . . . . . . . . . . . . . . . . $ 1,439,523 $ 136,263 $ Intersegment . . . . . . . . . . . . . . . . . . . . . . . . Total Sales . . . . . . . . . . . . . . . . . . . . . . . . U.S. Land Offshore — 1,439,523 — 136,263 Segment Operating Income (Loss) . . . . . . . Depreciation and Amortization . . . . . . . . . . . Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . Additions to Long-Lived Assets . . . . . . . . . . (94,880) 499,486 4,967,074 394,508 24,201 11,764 99,533 2,847 International Land 238,356 $ Other Eliminations Total — 238,356 (683) 46,826 362,033 4,424 38,217 $ 1,026 $ 39,243 - $ 2,487,268 - 2,487,268 (2,215) (2,215) (27,790) 21,472 735,017 18,456 — — — — 148,349 583,802 6,214,867 468,830 September 30, 2017 International Land 212,972 $ Other Eliminations Total — 212,972 (7,224) 53,622 413,392 3,400 15,983 $ 862 16,845 — $ 1,804,741 — 1,804,741 (862) (862) (9,449) 20,671 959,986 7,351 — — — — (87,352) 585,543 6,439,985 408,106 (in thousands) External Sales . . . . . . . . . . . . . . . . . . . . . . . $ 1,242,462 $ 138,601 $ Intersegment . . . . . . . . . . . . . . . . . . . . . . . . Total Sales . . . . . . . . . . . . . . . . . . . . . . . . U.S. Land Offshore — 1,242,462 — 138,601 International Land 229,894 $ — 229,894 Other Eliminations Total 13,275 $ 855 14,130 — $ 1,624,232 — 1,624,232 (855) (855) September 30, 2016 Segment Operating Income (Loss) . . . . . . . Depreciation and Amortization . . . . . . . . . . . Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . Additions to Long-Lived Assets . . . . . . . . . . 74,118 508,237 5,005,299 209,156 15,659 12,495 105,152 9,694 (14,086) 57,102 487,181 2,364 (7,491) 20,753 1,234,323 20,076 — — — — 68,200 598,587 6,831,955 241,290 94 The following table reconciles segment operating income (loss) to income from continuing operations before income taxes as reported on the Consolidated Statements of Operations: 2018 Year Ended September 30, 2017 (in thousands) 2016 Segment operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 148,349 $ Income from asset sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition related costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corporate selling, general and administrative costs and corporate depreciation . . . . . . . . . . Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,660 (8,153) (131,254) 31,602 (87,352) $ 20,627 — (105,816) (172,541) 68,200 9,896 — (104,062) (25,966) Other income (expense) Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gain (loss) on investment securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total unallocated amounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income (loss) from continuing operations before income taxes . . . . . . . . . . . . . . . . . . . . . . . $ 8,017 (24,265) 1 486 (15,761) 15,841 $ (184,598) $ 5,915 (19,747) — 1,775 (12,057) 3,166 (22,913) (25,989) (965) (46,701) (72,667) The following table presents revenues from external customers and long-lived assets by country based on the location of service provided: 2018 Year Ended September 30, 2017 (in thousands) 2016 Operating revenues United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,247,400 $ 1,591,769 $ 1,386,786 159,427 Argentina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,488 Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,948 Ecuador . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52,583 Other Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,487,268 $ 1,804,741 $ 1,624,232 190,038 38,793 — 11,037 157,257 37,554 6 18,155 Property, plant and equipment, net United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,591,913 $ 4,686,235 $ 4,804,328 183,286 Argentina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91,815 Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 438 Ecuador . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64,866 Other Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,857,382 $ 5,001,051 $ 5,144,733 133,617 74,042 10,781 47,029 155,978 81,798 22,298 54,742 NOTE 17 GUARANTOR AND NON-GUARANTOR FINANCIAL INFORMATION In March 2015, Helmerich & Payne International Drilling Co. (“the issuer”), a 100 percent owned subsidiary of Helmerich & Payne, Inc. (“parent”, “the guarantor”), issued senior unsecured notes with an aggregate principal amount of $500.0 million. The notes are fully and unconditionally guaranteed by the parent. No subsidiaries of the parent currently guarantee the notes, subject to certain provisions that if any subsidiary guarantees certain other debt of the issuer or parent, then such subsidiary will provide a guarantee of the obligation under the notes. In connection with the notes, we are providing the following condensed consolidating financial information in accordance with the Securities and Exchange Commission disclosure requirements, so that separate financial statements of the issuer are not required to be filed. Each entity in the consolidating financial information follows the same accounting policies as described in the consolidated financial statements. Condensed consolidating financial information for the issuer, Helmerich & Payne International Drilling Co., and parent, guarantor, Helmerich & Payne, Inc. is shown in the tables below. 95 CONDENSED CONSOLIDATING BALANCE SHEETS September 30, 2018 Helmerich & Payne (In thousands) (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total Assets Current assets: Cash and cash equivalents . . . . . . . . . . . $ Short-term investments . . Accounts receivable, net of allowance . . . . . . . . . . Inventories of materials and supplies . . . . . . . . . . Prepaid expenses and other . . . . . . . . . . . . . . . . Total current assets . . . Investments . . . . . . . . . . . . Property, plant and equipment, net . . . . . . . . . . Intercompany receivables . Goodwill . . . . . . . . . . . . . . . Intangible assets, net . . . . Other assets . . . . . . . . . . . Investment in subsidiaries . — $ — 273,214 $ 41,461 11,141 $ — — $ — 284,355 41,461 (29) — 20,783 20,754 16,200 46,859 161,532 — — 268 5,981,197 499,644 65,859 (272) 565,202 127,154 30,980 — 158,134 10,649 952,122 35,539 143,519 (573) (845) 66,398 1,115,550 82,496 — — 98,696 4,515,077 2,024,652 — — 907 172,513 295,446 294,206 64,777 73,207 4,080 — — (2,480,390) — — — (6,153,710) 4,857,382 — 64,777 73,207 5,255 — Total assets . . . . . . . . . . . . $ 6,226,810 $ 7,747,767 $ 875,235 $ (8,634,945) $ 6,214,867 Liabilities and Shareholders' Equity Current liabilities: Accounts payable . . . . . . $ Accrued liabilities . . . . . . Total current liabilities . . Noncurrent liabilities: Long-term debt . . . . . . . . Deferred income taxes . . Intercompany payables . . Other . . . . . . . . . . . . . . . . Noncurrent liabilities - discontinued operations . Total noncurrent liabilities . . . . . . . . . . . . Shareholders’ equity: Common stock . . . . . . . . Additional paid-in capital . Retained earnings . . . . . . Accumulated other comprehensive income . Treasury stock, at cost . . Total shareholders’ equity . . . . . . . . . . . . . . Total liabilities and shareholders’ equity . . . . . . $ 83,819 $ 43,449 127,268 43,626 $ 5,483 $ 164,542 208,168 37,093 42,576 (264) $ (580) (844) 132,664 244,504 377,168 — (7,112) 1,701,694 22,225 — 493,968 834,714 178,759 48,836 — 25,534 599,837 22,545 — — (2,480,290) — 493,968 853,136 — 93,606 — 14,254 — 14,254 1,716,807 1,556,277 662,170 (2,480,290) 1,454,964 11,201 500,393 4,027,779 16,550 (173,188) 100 52,437 5,910,955 19,830 — — 1,040 169,449 (100) (53,477) (6,080,404) 11,201 500,393 4,027,779 — — (19,830) — 16,550 (173,188) 4,382,735 5,983,322 170,489 (6,153,811) 4,382,735 6,226,810 $ 7,747,767 $ 875,235 $ (8,634,945) $ 6,214,867 96 (In thousands) (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total September 30, 2017 Helmerich & Payne Assets Current assets: Cash and cash equivalents . . . . . . . . . . . $ Short-term investments . . Accounts receivable, net of allowance . . . . . . . . . . Inventories of materials and supplies . . . . . . . . . . Prepaid expenses and other . . . . . . . . . . . . . . . . Total current assets . . . Investments . . . . . . . . . . . . Property, plant and equipment, net . . . . . . . . . . Intercompany receivables . Goodwill . . . . . . . . . . . . . . . Intangible assets, net . . . . Other assets . . . . . . . . . . . Investment in subsidiaries . Total assets . . . . . . . . . . . . $ Liabilities and Shareholders' Equity Current liabilities: Accounts payable . . . . . . $ Accrued liabilities . . . . . . Total current liabilities . . Noncurrent liabilities: Long-term debt . . . . . . . . Deferred income taxes . . Intercompany payables . . Other . . . . . . . . . . . . . . . . Noncurrent liabilities - discontinued operations . Total noncurrent liabilities . . . . . . . . . . . . Shareholders’ equity: Common stock . . . . . . . . Additional paid-in capital . Retained earnings . . . . . . Accumulated other comprehensive income . . Treasury stock, at cost . . Total shareholders’ equity . . . . . . . . . . . . . . Total liabilities and shareholders’ equity . . . . . . $ — $ — 507,504 $ 44,491 13,871 $ — — $ — 521,375 44,491 766 — 12,200 12,966 13,853 49,851 90,885 — — 4,955 5,470,050 5,642,560 $ 411,599 64,714 102,470 34,734 (5) — 477,074 137,204 6,383 1,072,447 36,982 150,301 (442) (447) 55,123 1,235,267 70,173 — — 84,026 4,609,144 1,746,662 — — 3,839 183,382 7,685,647 $ 342,056 248,540 51,705 50,785 8,360 — 5,001,051 — 51,705 50,785 17,154 — 851,747 $ (7,739,966) $ 6,439,988 — (2,086,087) — — — (5,653,432) 82,947 $ 26,698 109,645 48,092 $ 4,589 $ — $ 148,491 196,583 34,015 38,604 (447) (447) 135,628 208,757 344,385 — (11,201) 1,354,068 25,457 — 492,902 1,286,381 210,823 43,471 — 57,509 521,096 32,481 — — (2,085,987) — 492,902 1,332,689 — 101,409 — 4,012 — 4,012 1,368,324 2,033,577 615,098 (2,085,987) 1,931,012 11,196 487,248 3,855,686 2,300 (191,839) 100 52,437 5,396,212 6,738 — — 1,039 197,006 (100) (53,476) (5,593,218) 11,196 487,248 3,855,686 — — (6,738) — 2,300 (191,839) 4,164,591 5,455,487 198,045 (5,653,532) 4,164,591 5,642,560 $ 7,685,647 $ 851,747 $ (7,739,966) $ 6,439,988 97 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS Year Ended September 30, 2018 Helmerich & Payne (In thousands) (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total Operating revenue . . . . . . . $ Operating costs and other . — $ 14,276 2,210,695 $ 2,120,465 276,660 $ 321,863 (87) $ 2,487,268 2,455,666 (938) Operating income (loss) from continuing operations . . . . . . . . . . . . . Other income (expense), net . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . Equity in net income (loss) of subsidiaries . . . . . . . . . . Income (loss) from continuing operations before income taxes . . . . . Income tax (benefit) provision . . . . . . . . . . . . . . Income (loss) from continuing operations . . . . . Income from discontinued operations before income taxes . . . . . . . . . . . . . . . . . Income tax provision . . . . . Loss from discontinued operations . . . . . . . . . . . . . (14,276) 90,230 (45,203) 851 31,602 526 (499) 498,055 7,363 (20,426) (11,039) 1,466 (3,340) (851) — 8,504 (24,265) — (487,016) — 483,806 66,128 (47,077) (487,016) 15,841 1,134 482,672 — — — (448,613) (29,690) — (477,169) 514,741 (17,387) (487,016) 493,010 — — — 23,389 33,727 (10,338) — — — 23,389 33,727 (10,338) Net income (loss) . . . . . . . . $ 482,672 $ 514,741 $ (27,725) $ (487,016) $ 482,672 98 (In thousands) (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total Operating revenue . . . . . . . $ Operating costs and other . — $ 16,566 1,575,787 $ 1,707,473 229,021 $ 254,125 (67) $ 1,804,741 1,977,282 (882) Year Ended September 30, 2017 Helmerich & Payne Operating income (loss) from continuing operations . . . . . . . . . . . . . Other income (expense), net . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . Equity in net income (loss) of subsidiaries . . . . . . . . . . Income (loss) from continuing operations before income taxes . . . . . Income tax benefit . . . . . . . Income (loss) from continuing operations . . . . . Income from discontinued operations before income taxes . . . . . . . . . . . . . . . . . Income tax provision . . . . . Loss from discontinued operations . . . . . . . . . . . . . (16,566) (131,686) (25,104) 815 (172,541) (240) (398) (116,212) (133,416) (5,204) (128,212) — — — 7,342 (20,136) (8,012) 1,403 787 (815) — 7,690 (19,747) — 124,224 — (152,492) (22,914) 124,224 (184,598) (38,600) (12,931) — (56,735) (113,892) (9,983) 124,224 (127,863) — — — 3,285 3,634 (349) — — — 3,285 3,634 (349) Net income (loss) . . . . . . . . $ (128,212) $ (113,892) $ (10,332) $ 124,224 $ (128,212) 99 (In thousands) (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total Operating revenue . . . . . . . $ Operating costs and other . — $ 13,145 1,373,511 $ 1,358,269 250,791 $ 280,107 (70) $ 1,624,232 1,650,198 (1,323) Year Ended September 30, 2016 Helmerich & Payne Operating income (loss) from continuing operations . . . . . . . . . . . . . Other expense, net . . . . . . Interest expense . . . . . . . . Equity in net income (loss) of subsidiaries . . . . . . . . . . Loss from continuing operations before income taxes . . . . . . . . . . . . . . . . . Income tax (benefit) provision . . . . . . . . . . . . . . Income (loss) from continuing operations . . . . . Income from discontinued operations before income taxes . . . . . . . . . . . . . . . . . Income tax provision . . . . . Loss from discontinued operations . . . . . . . . . . . . . (13,145) (194) (375) (47,166) 15,242 (29,316) 1,253 (25,966) (22,243) (20,256) (14,472) (98) (2,282) (1,253) — (23,788) (22,913) — 61,638 — (60,880) (41,729) (31,696) 61,638 (72,667) (4,052) (56,828) — — — 5,127 (20,752) — (19,677) (46,856) (10,944) 61,638 (52,990) — — — 2,360 6,198 (3,838) — — — 2,360 6,198 (3,838) Net income (loss) . . . . . . . . $ (56,828) $ (46,856) $ (14,782) $ 61,638 $ (56,828) 100 CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In thousands) (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total Year Ended September 30, 2018 Helmerich & Payne Net income (loss) . . . . . . . . $ Other comprehensive income, net of income taxes: Unrealized appreciation on securities, net . . . . . . . Minimum pension liability adjustments, net . . . . . . . Other comprehensive income . . . . . . . . . . . . . . Comprehensive income (loss) . . . . . . . . . . . . . . . . . $ 482,672 $ 514,741 $ (27,725) $ (487,016) $ 482,672 — 1,137 1,137 9,001 4,112 13,113 — — — — — — 9,001 5,249 14,250 483,809 $ 527,854 $ (27,725) $ (487,016) $ 496,922 (In thousands) (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total Year Ended September 30, 2017 Helmerich & Payne Net loss . . . . . . . . . . . . . . . $ Other comprehensive income, net of income taxes: Unrealized depreciation on securities, net . . . . . . . Minimum pension liability adjustments, net . . . . . . . Other comprehensive income . . . . . . . . . . . . . . Comprehensive loss . . . . . $ (128,212) $ (113,892) $ (10,332) $ 124,224 $ (128,212) — 860 (829) 2,473 — — — — (829) 3,333 860 (127,352) $ 1,644 (112,248) $ — (10,332) $ — 124,224 $ 2,504 (125,708) (In thousands) Helmerich & Payne, Inc. (Guarantor) International Drilling Co. Non-Guarantor Total (Issuer) Subsidiaries Eliminations Consolidated Year Ended September 30, 2016 Helmerich & Payne Net loss . . . . . . . . . . . . . . . $ Other comprehensive loss, net of income taxes: Unrealized appreciation on securities, net . . . . . . . Reclassification of realized losses in net income, net . . . . . . . . . . . Minimum pension liability adjustments, net . . . . . . . Other comprehensive income (loss) . . . . . . . . . . Comprehensive loss . . . . . $ (56,828) $ (46,856) $ (14,782) $ 61,638 $ (56,828) — — (63) 2,772 926 (2,462) — — — — 2,772 — — 926 (2,525) (63) (56,891) $ 1,236 (45,620) $ — (14,782) $ — 61,638 $ 1,173 (55,655) 101 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (In thousands) Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Net cash provided by operating activities . . . . . $ 759 $ 539,476 $ 4,296 $ — $ 544,531 Year Ended September 30, 2018 Helmerich & Payne Cash flows from investing activities: Capital expenditures . . . . . . . . . . . . . . . . . . . Purchase of short-term investments . . . . . . . Payment for acquisition of business, net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sale of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . Intercompany transfers . . . . . . . . . . . . . . . . . Proceeds from asset sales . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . Cash flows from financing activities: Intercompany transfers . . . . . . . . . . . . . . . . . Dividends paid . . . . . . . . . . . . . . . . . . . . . . . Payments for employee taxes on net settlement of equity awards . . . . . . . . . . . . . Proceeds from stock option exercises . . . . . . Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, end of period . . . . $ (12,723) — (47,886) — 60,609 — — 308,430 (308,430) (7,114) 6,355 (443,743) (71,049) (10,118) — — — (466,584) (71,049) — — — (47,886) 68,776 (60,609) 41,289 (465,336) (308,430) — — — — — 3,092 (7,026) — — — — 68,776 — 44,381 (472,362) — — — — — — — — (308,430) — — (7,114) 6,355 — (309,189) (759) (308,430) — (234,290) (2,730) — (237,020) — — $ 507,504 273,214 $ 13,871 11,141 $ 521,375 — — $ 284,355 102 (In thousands) Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Net cash (used in) provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (4,686) $ 354,711 $ 11,606 $ — $ 361,631 Year Ended September 30, 2017, as adjusted Helmerich & Payne Cash flows from investing activities: Capital expenditures . . . . . . . . . . . . . . . . . Purchase of short-term investments . . . . . Payment for acquisition of business, net cash acquired . . . . . . . . . . . . . . . . . . . . . . Proceeds from sale of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . Intercompany transfers . . . . . . . . . . . . . . . Proceeds from asset sales . . . . . . . . . . . . Net cash used in investing activities . . . . Cash flows from financing activities: Intercompany transfers . . . . . . . . . . . . . . . Dividends paid . . . . . . . . . . . . . . . . . . . . . Payments for employee taxes on net settlement of equity awards . . . . . . . . . . . Proceeds from stock option exercises . . . . Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, end of period . . $ (4,264) — (70,416) — 74,680 — — 305,515 (305,515) (6,599) 11,285 (387,392) (69,866) (5,911) — — — (397,567) (69,866) — — — (70,416) 69,449 (74,680) 22,724 (439,765) (305,515) — — — — — 688 (5,223) — — — — — — — — — — — — — 69,449 — 23,412 (444,988) — (305,515) (6,599) 11,285 — (300,829) 4,686 (305,515) — (390,569) 6,383 — (384,186) — — $ 898,073 507,504 $ 7,488 13,871 $ — — $ 905,561 521,375 103 (In thousands) Helmerich & Payne, Inc. International Drilling Co. Non-Guarantor Total (Guarantor) (Issuer) Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,863 $ 777,756 $ (26,088) $ — $ 754,531 September 30, 2016, as adjusted Helmerich & Payne Cash flows from investing activities: Capital expenditures . . . . . . . . . . . . . . . . . Purchase of short-term investments . . . . . Proceeds from sale of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . Intercompany transfers . . . . . . . . . . . . . . . Proceeds from asset sales . . . . . . . . . . . . Net cash provided by (used in) investing activities . . . . . . . . . . . . . . . . . Cash flows from financing activities: Payments on long-term debt . . . . . . . . . . . Debt issuance costs . . . . . . . . . . . . . . . . . Intercompany transfers . . . . . . . . . . . . . . . Dividends paid . . . . . . . . . . . . . . . . . . . . . Payments from employee taxes on net settlement of equity awards . . . . . . . . . . . Proceeds from stock option exercises . . . . Net cash used in financing activities . . . . Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, end of period . . $ (16,119) — — 16,119 9 (235,078) (57,276) 58,381 (16,119) 19,237 (5,972) — — — 2,599 — — — — — (257,169) (57,276) 58,381 — 21,845 9 (230,855) (3,373) — (234,219) — — 300,152 (300,152) (5,646) 2,774 (2,872) (40,000) (1,111) (300,152) — — — (341,263) — — — — — — — — — — — — — — (40,000) (1,111) — (300,152) (5,646) 2,774 (344,135) — 205,638 (29,461) — 176,177 — — $ 692,435 898,073 $ 36,949 7,488 $ — — $ 729,384 905,561 104 NOTE 18 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts) 2018 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . $ Operating income (loss) . . . . . . . . . . . . . . . . . . . . . Income (loss) from continuing operations . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per common share: First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) 564,087 $ 3,520 500,642 500,106 577,484 $ (1,253) (1,633) (11,879) 648,872 $ 6,217 (8,174) (8,008) 696,825 $ 2,487,268 31,602 493,010 482,672 23,118 2,175 2,453 Income (loss) from continuing operations . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . Diluted earnings per common share: Income (loss) from continuing operations . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . 4.57 4.57 4.55 4.55 (0.03) (0.12) (0.03) (0.12) (0.08) (0.08) (0.08) (0.08) 0.02 0.02 0.02 0.02 4.49 4.39 4.47 4.37 (1) The sum of earnings per share for the four quarters may not equal the total earnings per share for the fiscal year due to changes in the average number of common shares outstanding. In the first quarter of fiscal year 2018, net income includes a tax benefit of approximately $502.1 million, or $4.59 per share on a diluted basis, an after-tax gain from the sale of assets of $4.2 million, or $0.04 per share on a diluted basis. In the second quarter of fiscal year 2018, net loss includes an after-tax gain from the sale of assets of $3.8 million, or $0.04 per share on a diluted basis. In the third quarter of fiscal year 2018, net loss includes an after-tax gain from the sale of assets of $3.1 million, or $0.02 per share on a diluted basis. In the fourth quarter of fiscal year 2018, net loss includes an after-tax gain from the sale of assets of $5.5 million, or $0.05 per share on a diluted basis and an after-tax loss from asset impairments of approximately $17.2 million, or $0.16 per share on a diluted basis. 2017 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . $ Operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss from continuing operations . . . . . . . . . . . . . . . Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per common share: First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) 368,590 $ (49,164) (34,554) (35,063) 405,283 $ (65,672) (48,473) (48,818) 498,564 $ (28,028) (23,125) (21,799) 532,304 $ 1,804,741 (172,541) (29,677) (127,863) (21,711) (128,212) (22,532) Loss from continuing operations . . . . . . . . . . . . . . Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted earnings per common share: Loss from continuing operations . . . . . . . . . . . . . . Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.33) (0.33) (0.33) (0.33) (0.45) (0.45) (0.45) (0.45) (0.22) (0.21) (0.22) (0.21) (0.20) (0.21) (0.20) (0.21) (1.20) (1.20) (1.20) (1.20) (1) The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding. In the first quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $0.6 million, or $0.01 per share on a diluted basis. In the second quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $10.1 million, or $0.09 per share on a diluted basis. In the third quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $1.3 million, or $0.01 per share on a diluted basis. In the fourth quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $2.3 million, or $0.02 per share on a diluted basis. NOTE 19 SUBSEQUENT EVENTS On November 13, 2018, we entered into the 2018 Credit Facility, which will mature on November 13, 2023. The 2018 Credit Facility has $750 million in aggregate availability with a maximum of $75 million available for use as letters of credit. The 2018 Credit Facility also permits aggregate commitments under the facility to be increased by $300 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The 2018 Credit Facility is currently guaranteed by our wholly-owned direct subsidiary, HPIDC, which guarantee is subject to release following certain events set forth in the 2018 Credit Facility. The borrowings under the 2018 Credit Facility accrue interest at a spread over either the London Interbank Offered Rate (LIBOR) or the Base Rate. We also pay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined based on the debt rating for senior unsecured debt of the Company or HPIDC as determined by Moody’s and S&P. The spread over LIBOR ranges from 0.875 percent to 1.500 percent per annum and commitment fees range from 0.075 percent to 0.200 percent per annum. Based on the unsecured debt rating of HPIDC on September 30, 2018, the 105 spread over LIBOR would have been 1.125 percent and commitment fees would have been 0.125 percent. There is a financial covenant in the 2018 Credit Facility that requires us to maintain a total debt to total capitalization ratio of less than 50 percent. The 2018 Credit Facility contains additional terms, conditions, restrictions and covenants that we believe are usual and customary in unsecured debt arrangements for companies of similar size and credit quality, including a limitation that priority debt (as defined in the credit agreement) may not exceed 17.5 percent of the net worth of the Company. As of the closing, there were no borrowings, but there were three letters of credit outstanding in the amount of $38.0 million, and we had $712.0 million available to borrow under the 2018 Credit Facility. In connection with entering into the 2018 Credit Facility, we terminated our $300 million unsecured credit facility under the credit agreement dated as of July 13, 2016 by and among HPIDC, as borrower, the Company, as guarantor, Wells Fargo, National Association, as administrative agent, and the lenders party thereto. 106 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. Item 9A. CONTROLS AND PROCEDURES a) Evaluation of Disclosure Controls and Procedures. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of the end of the period covered by this report have been designed and are effective at the reasonable assurance level so that the information required to be disclosed by us in our periodic SEC filings, is recorded, processed, summarized and reported within the time periods specific in the SEC’s rules, regulations, and forms and is communicated to management. We believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. b) Management’s Report on Internal Control over Financial Reporting. A copy of our Management’s Report on Internal Control over Financial Reporting is included in Item 8 of this Form 10-K. c) Attestation Report of the Independent Registered Public Accounting Firm. A copy of the report of Ernst & Young LLP, our independent registered public accounting firm, is included in Item 8 of this Form 10-K. d) Changes in Internal Control Over Financial Reporting. None. *** Item 9B. OTHER INFORMATION None. 107 Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE PART III The information required by this item is incorporated herein by reference to the material under the captions “Proposal 1—Election of Directors,” “Corporate Governance,” “Executive Officers of the Company” in Part I and “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019, to be filed with the SEC not later than 120 days after September 30, 2018. We have adopted a Code of Ethics for Principal Executive Officer and Senior Financial Officers. The text of this code is located on our website under “Corporate Governance.” Our Internet address is www.hpinc.com. We intend to disclose any amendments to or waivers from this code on our website. Item 11. EXECUTIVE COMPENSATION The information required by this item regarding executive compensation, as well as director compensation and compensation committee interlocks and insider participation is incorporated herein by reference to the material beginning with the caption “Executive Compensation Discussion and Analysis” and ending with the caption “Potential Payments Upon Change-in-Control”, as well as under the captions “Director Compensation in Fiscal 2018” and “Corporate Governance—Compensation Committee Interlocks and Insider Participation” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019, to be filed with the SEC not later than 120 days after September 30, 2018. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required by this item is incorporated herein by reference to the material under the captions “Summary of All Existing Equity Compensation Plans,” “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Management” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019, to be filed with the SEC not later than 120 days after September 30, 2018. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this item is incorporated herein by reference to the material under the captions “Corporate Governance—Transactions With Related Persons, Promoters and Certain Control Persons” and “Corporate Governance—Director Independence” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019, to be filed with the SEC not later than 120 days after September 30, 2018. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information required by this item is incorporated herein by reference to the material under the caption “Proposal 2—Ratification of Appointment of Independent Auditors—Audit Fees” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019, to be filed with the SEC not later than 120 days after September 30, 2018. 108 Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES PART IV 1. Financial Statements: Our consolidated financial statements, together with the notes thereto and the report of Ernst & Young LLP dated November 16, 2018, are listed below and included in Item 8—“Financial Statements and Supplementary Data” of this Form 10-K. Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Balance Sheets at September 30, 2018 and 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Operations for the Years Ended September 30, 2018, 2017 and 2016 . . . . . . . . . . . . Consolidated Statements of Comprehensive Income (Loss) for the Years Ended September 30, 2018, 2017 Page 56 58 59 and 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2018, 2017 and 2016 . . . . Consolidated Statements of Cash Flows for the Years Ended September 30, 2018, 2017 and 2016 . . . . . . . . . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 61 62 63 2. Financial Statement Schedules: All schedules are omitted because they are not applicable or required or because the required information is contained in the financial statements or included in the notes thereto. 3. Exhibits. The following documents are included as exhibits to this Form 10-K. Exhibits incorporated by reference are duly noted as such. 2.1 Agreement and Plan of Merger dated May 22, 2017, by and among Helmerich & Payne, Inc., MOTIVE Drilling Technologies, Inc., Spring Merger Sub, Inc., and Shareholder Representative Services LLC (incorporated herein by reference to Exhibit 2.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, SEC File No. 001-04221). 3.1 Amended and Restated Certificate of Incorporation of Helmerich & Payne, Inc. (incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on March 14, 2012, SEC File No. 001-04221). 3.2 Amended and Restated By-laws of Helmerich & Payne, Inc. (incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on December 5, 2017, SEC File No. 001-04221). 4.1 Indenture, dated March 19, 2015, by and among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, including the form of 4.65% Senior Notes due 2025 (incorporated herein by reference to Exhibit 4.1 of the Company’s Form 8-K filed on March 19, 2015, SEC File No. 001-04221). 4.2 First Supplemental Indenture, dated March 19, 2015, by and between Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association is incorporated herein by reference to Exhibit 4.2 of the Company’s Form 8-K filed on March 19, 2015, SEC File No. 001-04221. 10.1 Credit Agreement, dated July 13, 2016, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc., the lenders from time to time party thereto and Wells Fargo Bank, National Association (incorporated herein reference to Exhibit 10.1 of the Company’s Form 8-K filed on July 13, 2016, SEC File No. 001-04221. 10.2 Credit Agreement, dated November 13, 2018, among Helmerich & Payne, Inc., the lenders from time to time party thereto and Wells Fargo Bank, National Association. *10.3 Change of Control Agreement applicable to Chief Executive Officer of Helmerich & Payne, Inc., dated June 1, 2016 (incorporated herein by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-04221). 109 *10.4 Change of Control Agreement applicable to certain other officers (other than CEO) and employees of Helmerich & Payne, Inc., dated June 1, 2016 (incorporated herein by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-04221). 10.5 Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan (incorporated herein by reference to Appendix “A” of the Company’s Proxy Statement on Schedule 14A filed on January 26, 2006, SEC File No. 001-04221). *10.6 2012-1 Amendment to Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, SEC File No. 001-04221). *10.7 Form of Agreements for Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement (incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K filed on December 7, 2009, SEC File No. 001-04221). *10.8 Form of Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executives: (i) Nonqualified Stock Option Agreement, (ii) Incentive Stock Option Agreement, and (iii) Restricted Stock Award Agreement (incorporated herein by reference to Exhibit 10.3 of the Company’s Form 8-K filed on December 7, 2009, SEC File No. 001-04221). *10.9 Form of Amendment to Nonqualified Stock Option Award Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to certain executive officers (incorporated herein by reference to Exhibit 10.4 of the Company’s Form 8-K filed on December 7, 2009, SEC File No. 001-04221). *10.10 Form of Amendment to Nonqualified Stock Option Award Agreements and Amendment to Restricted Stock Award Agreements for the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan applicable to participants other than certain executive officers (incorporated herein by reference to Exhibit 10.5 of the Company’s Form 8-K filed on December 7, 2009, SEC File No. 001-04221). *10.11 Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan (incorporated herein by reference to Appendix “A” of the Company’s Proxy Statement on Schedule 14A filed on January 26, 2011, SEC File No. 001-04221). *10.12 Form of Nonqualified Stock Option Agreement for Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to certain executives (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on March 14, 2012, SEC File No. 001-04221). *10.13 Form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to participants other than certain executives (incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K filed on March 14, 2012, SEC File No. 001-04221). *10.14 Form of Restricted Stock Award Agreement for Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to certain executives (incorporated herein by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2013, SEC File No. 001-04221). *10.15 Form of Restricted Stock Award Agreement for the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to participants other than certain executives (incorporated herein by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2013, SEC File No. 001- 04221). *10.16 Form of Agreements for the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to Directors: (i) Director Nonqualified Stock Option Agreement and (ii) Director Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 of the Company’s Form 8-K filed on March 14, 2012, SEC File No. 001-04221). *10.17 Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan (incorporated herein by reference to Appendix “A” of the Company’s Proxy Statement on Schedule 14A filed on January 19, 2016, SEC File No. 001-04221). 110 *10.18 Form of Agreements for Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Agreement and (ii) Restricted Stock Award Agreement (incorporated herein by reference to Exhibit 10.26 of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2016, SEC File No. 001-04221). *10.19 Form of Agreements for Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan applicable to participants other than certain executives: (i) Nonqualified Stock Option Agreement and (ii) Restricted Stock Award Agreement (incorporated herein by reference to Exhibit 10.27 of the Company’s Annual Report on Form 10-K for fiscal year ended September 30, 2016, SEC File No. 001-04221). *10.20 Form of Agreements for Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan applicable to Directors: (i) Director Nonqualified Stock Option Agreement and (ii) Director Restricted Stock Award Agreement (incorporated herein by reference to Exhibit 10.28 of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2016, SEC File No. 001-04221). *10.21 Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. (incorporated herein by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2008, SEC File No. 001-04221). *10.22 Supplemental Savings Plan for Salaried Employees of Helmerich & Payne, Inc. (incorporated herein by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2008, SEC File No. 001-04221). *10.23 Helmerich & Payne, Inc. Director Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2008, SEC File No. 001-04221). 21 List of Subsidiaries of the Company. 23.1 Consent of Independent Registered Public Accounting Firm. 31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32. Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 101 Financial statements from this Form 10-K formatted in XBRL: (i) the Consolidated Statements of Operations, (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Shareholders’ Equity, (v) the Consolidated Statements of Cash Flows and (vi) the Notes to Consolidated Financial Statements. * Management or Compensatory Plan or Arrangement. Item 16. FORM 10-K SUMMARY None. 111 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized: SIGNATURES HELMERICH & PAYNE, INC. By: /s/ John W. Lindsay John W. Lindsay, President and Chief Executive Officer Date: November 16, 2018 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated: Signature Title Date /s/ John W. Lindsay John W. Lindsay Director, President and Chief Executive Officer (Principal Executive Officer) November 16, 2018 Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) November 16, 2018 Director and Chairman of the Board November 16, 2018 /s/ Mark W. Smith Mark W. Smith /s/ Hans Helmerich Hans Helmerich /s/ Delany Bellinger Delany Bellinger /s/ Kevin G. Cramton Kevin G. Cramton /s/ Randy A. Foutch Randy A. Foutch /s/ Paula Marshall Paula Marshall /s/ Jose R. Mas Jose R. Mas /s/ Thomas A. Petrie Thomas A. Petrie Director Director Director Director Director Director /s/ Donald F. Robillard, Jr. Donald F. Robillard, Jr. Director /s/ Edward B. Rust, Jr. Edward B. Rust, Jr. /s/ John D. Zeglis John D. Zeglis Director Director 112 November 16, 2018 November 16, 2018 November 16, 2018 November 16, 2018 November 16, 2018 November 16, 2018 November 16, 2018 November 16, 2018 November 16, 2018 Directors Officers 20DEC201817520975 John W. Lindsay President and Chief Executive Officer Helmerich & Payne shareholders are invited to attend our annual Stockholders’ Meeting meeting which will be held on March 5, 2019. Stock Exchange Listing New York Stock Exchange Symbol: HP Stock Transfer Agent and Registrar Computershare Trust Company, N.A. Investor Services P.O. Box 43078 Providence, RI 02940-3078 Telephone: (800) 884-4225 (781) 575-4706 Independent Registered Public Accounting Firm Ernst & Young LLP Tulsa, Oklahoma Direct Inquiries To: David T. Wilson Investor Relations Director Helmerich & Payne, Inc. 1437 South Boulder Avenue Tulsa, Oklahoma 74119 Telephone: (918) 742-5531 Website: http://www.hpinc.com Hans Helmerich Chairman of the Board Tulsa, Oklahoma Kevin G. Cramton*(***) Operating Partner HCI Equity Partners Washington, D.C. Mark W. Smith Vice President and Chief Financial Officer Robert L. Stauder Senior Vice President and Chief Engineer Randy A. Foutch**(***) Chairman and Chief Executive Officer Helmerich & Payne International Laredo Petroleum, Inc. Tulsa, Oklahoma Drilling Co. (subsidiary) John W. Lindsay President and Chief Executive Officer Helmerich & Payne International Tulsa, Oklahoma Drilling Co. (subsidiary) Wade W. Clark Vice President U.S. Land Delaney Bellinger*(***) Vice President and Chief Information Vice President U.S. Land Officer, Retired Huntsman Corporation Woodlands, Texas Helmerich & Payne International Drilling Co. (subsidiary) Michael P. Lennox John R. Bell Vice President, International and Offshore Operations Helmerich & Payne International Drilling Co. (subsidiary) Cara M. Hair Vice President, Corporate Services and Chief Legal Officer Nicholas R. Timmons Assistant Corporate Secretary Jos´e R. Mas**(***) Chief Executive Officer MasTec, Inc. Coral Gables, Florida Thomas A. Petrie**(***) Chairman Petrie Partners, LLC Denver, Colorado Donald F. Robillard, Jr.*(***) Chief Financial Officer, Retired Hunt Consolidated, Inc. Dallas, Texas Edward B. Rust, Jr.*(***) Chairman and Chief Executive Officer, Retired State Farm Mutual Automobile Insurance Company Bloomington, Illinois John D. Zeglis*(***) Chairman and Chief Executive Officer, Retired AT&T Wireless Services, Inc. Basking Ridge, New Jersey Member, Audit Committee * ** Member, Human Resources Committee *** Member, Nominating and Corporate Governance Committee 11JAN201920142730 HELMERICH & PAYNE, INC. 1437 SOUTH BOULDER AVENUE TULSA, OKLAHOMA 74119 WWW.HPINC.COM ANNUAL REPORT FOR 2018 

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