Helmerich & Payne
Annual Report 2019

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ai158017465635_2019 Annual Report Cover--PRINT READY w-spine.pdf 1 1/27/20 8:24 PM 20_48280_Merrill Crop.indd 1 20_48280_Merrill Crop.indd 1 1/27/20 8:25 PM 1/27/20 8:25 PM ai158017465635_2019 Annual Report Cover--PRINT READY w-spine.pdf 2 1/27/20 8:24 PM 1 2 3 4 5 20_48280_Merrill Crop.indd 2 20_48280_Merrill Crop.indd 2 1/27/20 8:25 PM 1/27/20 8:25 PM 1. Based on EnergyPoint Research 2018-19 Customer Satisfaction Survey. 2. For fiscal year 2019. 3. Since 1971. 4. Based on December 31, 2019 closing stock price. 5. From January 1, 2010 through December 31, 2019. UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2019 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-4221 HELMERICH & PAYNE, INC. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 73-0679879 (I.R.S. Employer Identification No.) 1437 South Boulder Avenue, Suite 1400, Tulsa, Oklahoma 74119 (Address of principal executive offices) (Zip Code) (918) 742-5531 (Registrant’s telephone number, including area code) N/A (Former name, former address and former fiscal year, if changed since last report) Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading symbol(s) Name of each exchange on which registered Common Stock ($0.10 par value) HP 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 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 Accelerated filer Smaller reporting company Emerging Growth Company If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b 2 of the Exchange Act). Yes No At March 29, 2019, 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 $6.08 billion based on the closing price of such stock on the New York Stock Exchange on such date of $55.56. Number of shares of common stock outstanding at November 6, 2019: 108,446,592 Portions of the Registrant’s 2019 Proxy Statement for the Annual Meeting of Stockholders to be held on March 3, 2020 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 PART I Item 1. Business ................................................................................................................................................................................. Item 1A. Risk Factors ............................................................................................................................................................................ Item 1B. Unresolved Staff Comments ................................................................................................................................................... Item 2. Properties ............................................................................................................................................................................... Item 3. Legal Proceedings .................................................................................................................................................................. Item 4. Mine Safety Disclosures ......................................................................................................................................................... PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities .............. Item 6. Selected Financial Data .......................................................................................................................................................... Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ................................................... Item 7A. Quantitative and Qualitative Disclosures About Market Risk .................................................................................................. Item 8. Financial Statements and Supplementary Data ..................................................................................................................... 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 Page 4 4 14 27 27 27 28 29 29 30 31 44 46 91 91 91 91 91 91 91 91 92 93 93 96 98 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 PART I Item 1. BUSINESS Overview Helmerich & Payne, Inc. ("H&P," 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 primarily on the drilling segment of the oil and gas production value chain. Our global business is composed of four reportable business segments - three contract drilling business segments: U.S. Land, Offshore and International Land and one drilling technology-based business segment: Helmerich & Payne Technologies ("H&P Technologies"). During the fiscal year ended September 30, 2019, our U.S. Land operations were located in Colorado, Louisiana, Ohio, Oklahoma, Montana, New Mexico, North Dakota, Pennsylvania, Texas, Utah, West Virginia and Wyoming. Our Offshore operations were conducted in U.S. federal waters in the Gulf of Mexico. Our International Land operations had rigs located in four international locations during fiscal year 2019: Argentina, Bahrain, Colombia and United Arab Emirates (“U.A.E.”). Our H&P Technologies operations focus on developing, promoting and commercializing technologies designed to improve the efficiency and accuracy of drilling operations, as well as wellbore quality and placement. Our research and development endeavors include both internal development and external acquisition of developing technologies. 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 389,000 leasable square feet, multi tenant industrial warehouse properties containing approximately one million leasable square feet and approximately 210 acres of undeveloped real estate. Drilling Fleet The following map and table sets forth certain information concerning our U.S. land drilling rigs as of September 30, 2019: 2 16 Permian Eagle Ford Woodford Bakken Niobrara Haynesville Marcellus Piceance Utica Other 18 9 9 142 36 50 1 15 1 4 AC (FlexRig3) (1) AC (FlexRig4) (2) AC (FlexRig5) (3) SCR (4) Total Fleet Current Location Total Available Rigs Contracted Total Available (5) Rigs Contracted Total Available Rigs Contracted Total Available Rigs Contracted Total Available Rigs Contracted U.S. Land Fleet TX OK NM ND CO PA LA OH WY UT WV Totals 144 100 22 29 11 — 6 5 1 3 — 2 223 8 28 5 — 2 5 — 2 — 2 152 1 — — 4 10 4 — — — 1 — 20 — — — — 5 — — — — 1 — 6 28 13 1 3 2 2 — 2 2 — 1 54 20 8 1 2 1 — — 1 2 — 1 36 1 — — — — — 1 — — — — 2 — — — — — — — — — — — — 174 35 30 18 12 12 6 3 5 1 3 120 16 29 7 6 2 5 1 4 1 3 299 194 (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. 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. (2) The FlexRig4 model has a small footprint and is designed to be highly mobile. The rig is equipped with a 500,000 lb. or 600,000 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 (5) (“DC”). These two SCR rigs are equipped with 3,000 horsepower drawworks to drill deep conventional wells. In total, seven Domestic FlexRig4's completed their conversions to Domestic FlexRig3's. Two conversions were completed in the fourth quarter of fiscal year 2018, followed by five conversions in the first quarter of fiscal year 2019. In addition, the Domestic FlexRig4’s were downsized by 51 rigs by the end of the third quarter of fiscal year 2019. See Note 5—Property, Plant and Equipment to our Consolidated Financial Statements. We operate a large fleet of super-spec rigs, which are generally considered to include the following rig specifications: AC Drive, minimum of 1,500 horsepower drawworks, minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and multiple-well pad capability. The chart below depicts the states in which our super-spec rigs operate. 5 The following table sets forth certain information concerning our offshore drilling rigs as of September 30, 2019: Offshore Fleet Current Location Louisiana (2) Gulf of Mexico Totals Shallow Water (1) Deep Water (1) Total Fleet Total Available Rigs Contracted Total Available Rigs Contracted Total Available Rigs Contracted 2 3 5 — 3 3 — 3 3 — 3 3 2 6 8 — 6 6 (1) Deep water rigs operate on floating facilities and shallow water rigs operate on fixed facilities. (2) Rigs are idle, stacked on land and not in state waters. The following table sets forth certain information concerning our international land drilling rigs as of September 30, 2019: International Land Fleet AC (FlexRig3) AC (FlexRig4) Other AC SCR Total Fleet Current Location Argentina Colombia Bahrain U.A.E. Totals Total Available 12 Rigs Contracted 12 Total Available (1) 4 Rigs Contracted 4 Total Available — Rigs Contracted — Total Available 4 Rigs Contracted — 2 — 2 16 — — — 12 2 2 — 8 — 2 — 6 1 — — 1 — — — — 2 — — 6 — — — — Total Available 20 7 2 2 31 Rigs Contracted 16 — 2 — 18 (1) At the end of the third quarter of fiscal year 2019, the fleet was downsized by two rigs. See Note 5—Property, Plant and Equipment to our Consolidated Financial Statements. Contract Drilling Services 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 do not operate any legacy mechanical rigs. Revenue from individual customers that are approximately 10% or more of our total consolidated revenues are as follows: (in thousands) EOG Resources, Inc. 2018 2017 $ 258,194 $ 163,582 We did not have any individual customers that represented 10% or more of our total consolidated revenues in fiscal year 2019. 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 2019, 2018, and 2017: U.S. Land Offshore International Land 2019 (2) 2018 2017 2019 2018 2017 2019 (3) 2018 Year Ended September 30, Average active rigs per day 224.1 213.6 156.5 Average utilization (1) 67% 61% 45% 5.9 74% 5.6 70% 6.2 74% 17.6 55% 18.3 49% 2017 13.6 36% (1) A rig is considered to be utilized when it is operating (or otherwise deployed for a customer) or being moved, assembled or dismantled pursuant to a drilling contract. (2) At the end of the third quarter of fiscal year 2019, the fleet was downsized by 51 rigs. See Note 5—Property, Plant and Equipment to our Consolidated Financial Statements. (3) At the end of the third quarter of fiscal year 2019, the fleet was downsized by two rigs. See Note 5—Property, Plant and Equipment to our Consolidated Financial Statements. 6 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, 2019, we had over 20 percent of the total market share in U.S. land drilling and approximately 37 percent of the super-spec market share in U.S. land drilling. As of September 30, 2019, 194 of our 299 marketed rigs were under contract, 128 were under fixed term contracts, and 66 were working well-to-well. Over the past three fiscal years, we have reinvested in our fleet, upgrading 171 rigs to industry- leading super-spec capabilities that are designed to drill the most complex unconventional wells. Our U.S. Land segment contributed approximately 85 percent ($2.4 billion) of our consolidated operating revenues during fiscal year 2019, compared with approximately 83 percent ($2.1 billion) and 80 percent ($1.4 billion) of our consolidated operating revenues during fiscal years 2018 and 2017, respectively. In the United States, we draw our customers primarily from the major oil companies, large independent oil companies and small cap oil companies. Additionally, we have a growing customer base in private equity-backed companies. Offshore Segment Our Offshore Drilling segment has been in operation since 1968 and currently consists of eight rigs 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 jackup 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. As of September 30, 2019, six of the eight offshore rigs were under contract. Our Offshore operations contributed approximately 5 percent ($147.6 million) of our consolidated operating revenues during fiscal year 2019, compared to approximately 6 percent ($142.5 million) and 8 percent ($136.3 million) of our consolidated operating revenues during fiscal years 2018 and 2017, respectively. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 65 percent ($96.0 million) of offshore revenues during fiscal year 2019. 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, 2019, we had 18 land rigs contracted for work in locations outside of the United States. Our International Land operations contributed approximately 8 percent ($211.7 million) of our consolidated operating revenues during fiscal year 2019, compared with approximately 10 percent ($238.4 million) and 12 percent ($213.0 million) of our consolidated operating revenues during fiscal years 2018 and 2017, respectively. Argentina As of September 30, 2019, we had 20 rigs in Argentina. Revenues generated by Argentine drilling operations contributed approximately 6 percent ($165.7 million) of our consolidated operating revenues during fiscal year 2019 compared to approximately 8 percent ($190.0 million) and 9 percent ($157.3 million) of our consolidated operating revenues during fiscal years 2018 and 2017, respectively. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 6 percent of our consolidated operating revenues and approximately 74 percent of our international operating revenues during fiscal year 2019. The Argentine drilling contracts are primarily with large international or national oil companies. As of September 30, 2019, we believe we had over 15 percent of total market share and over 30 percent of the unconventional horizontal drilling market share in Argentina. Colombia As of September 30, 2019, we had seven rigs in Colombia. Revenues generated by Colombian drilling operations contributed approximately 1 percent ($29.8 million) of our consolidated operating revenues in fiscal year 2019, compared to approximately 2 percent ($38.8 million) and 2 percent ($37.6 million) of our consolidated operating revenues during fiscal years 2018 and 2017, 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 2019. The Colombian drilling contracts are primarily with large international or national oil companies. Bahrain As of September 30, 2019, we had two rigs in Bahrain. Revenues generated by Bahrain drilling operations contributed approximately 0.4 percent ($11.5 million) of our consolidated operating revenues in fiscal year 2019, compared to approximately 0.4 percent ($9.5 million) and 0.6 percent ($10.0 million) of our consolidated operating revenues during fiscal years 2018 and 2017, respectively. All of our revenues in Bahrain are from a partner of the local national oil company. 7 United Arab Emirates As of September 30, 2019, we had two rigs in the U.A.E. Revenues generated by U.A.E. drilling operations contributed approximately 0.2 percent ($4.7 million) of our consolidated operating revenues in fiscal year 2019, compared to nominal amounts in fiscal year 2018 and 0.5 percent ($8.2 million) of our consolidated operating revenues during fiscal year 2017. H&P Technologies Effective October 1, 2018 and during the fourth quarter of fiscal year 2019, we implemented organizational changes, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. As a result of the reorganization of our operations during the first quarter of fiscal year 2019, we identified a new reportable segment, H&P Technologies. This reportable segment is used to drive development of advanced digital drilling technologies and directional drilling automation solutions, designed to improve safety, reliability, drilling consistency, and well performance economics for our customers. Subsequent to the reorganizations, all of our technology companies are included within the H&P Technologies reportable segment. Combining drilling technology expertise within this new segment creates a holistic solution-based approach that includes products, services and capabilities. This approach provides performance-driven drilling services with greater levels of accuracy, consistency, optimization and a reduction of human error to create higher quality wellbores. This technology addresses our customers' unique challenges, resulting in less tortuosity and reducing positional uncertainty in the directional drilling process. Another key benefit is that many components of our digital technology, including MOTIVE bit guidance and MagVARTM survey correction, can be used on any rig, regardless of the drilling or service provider, allowing our customers to benefit from these technologies on all rigs. During fiscal year 2019, H&P Technologies released AutoSlideSM, which integrates the MOTIVE bit guidance system and several FlexApps to function within the FlexRig operating system and fully automates the control of mud motors while sliding during the vertical, the curve, and the lateral hole sections during horizontal drilling operations. Similar to our approach with FlexApps, H&P Technologies plans to market AutoSlide across the FlexRigTM fleet initially at a price point that improves cost-efficiency for our customers. Subsequently, there are also plans to integrate the software to make this offering compatible with non–H&P rigs for those customers with multi-vendor rig fleets. Currently, our AutoSlide application is commercially available in four regions including the Midland, Bakken, Eagle Ford and MidCon basins and we will be expanding into additional basins in the coming months. The adoption of our FlexApps continues as customers see the value of these technologies as demonstrated by their requests to use them on both H&P and non-H&P rigs. Our preparation to respond to this type of demand includes migrating our FlexApp offerings into our H&P Technologies business segment, which occurred in the fourth quarter of fiscal year 2019 and developing rig-neutral solutions to operate the software on non-H&P rigs. Other Operations Other Operations include additional non-reportable operating segments. Revenues included in “Other” consist primarily of real estate rental income. We 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 also 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. During the third quarter of fiscal year 2019, the Company established an incubator program for new research and development projects, the results of which have been included in "Other" within our segment disclosures. Internal Restructuring During fiscal year 2019, we reorganized 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 reorganization is intended to foster operational efficiency, simplify our organizational structure and provide additional clarity in our internal reporting. It had no impact on our segment reporting. 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 and marked 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 FlexRig3s and our strategy included building them under a multi-year 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 8 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. H&P has a strategic advantage due to 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 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. In 2017, we introduced our first walking rig by reconfiguring our skid designed FlexRig3s. Since then we have reconfigured, converted and upgraded a total of 40 FlexRigs to super-spec walking rigs. H&P also has an important advantage in the super-spec space in that our FlexRig3s and FlexRig5s are ideally suited for super-spec upgrades, and we have more upgradeable rigs than our competitors. As of September 30, 2019, we held approximately 37 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, 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 provide high quality and reliable results for our customers. We currently have two 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 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. Our fabrication and assembly facility is located near Houston, Texas. Additionally, our overhauling, recertification, and repairs facility is located near Tulsa, Oklahoma. 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. 9 The FlexApps that are currently in use include the following: Application Name FlexTorque™ Flex-Oscillator 2.0™ FlexB2D™ FlexDrill 1.0™ FlexGuide™ Description Hardware and software designed to decrease downhole drilling vibration and "slip-stick" during drilling. This helps with drilling efficiency and extends bit and downhole tool life, which is expected to reduce costly nonproductive time. Rig control software that automates drill string rotation during directional "slide" operations, which helps reduce downhole drag and the potential for stuck pipe. It also supports more effective directional drilling. 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. 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. Powered by both MOTIVE Drilling Technologies, Inc. ("MOTIVE") and MagVAR software that utilizes a drill bit guidance system and geomagnetic survey correction, respectively, improving wellbore quality with a scalable, repeatable data driven platform approach and helping to reduce surveying uncertainty, while increasing horizontal well economics and helping to reduce risk. We have historically offered ancillary services, which are now referred to as FlexServices™. These services include trucking, surface equipment, casing running 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. The level of capital spending is correlated to oil and gas prices. Oil and gas prices can be volatile at times depending upon both near and long-term supply and demand factors. 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. As of September 30, 2019, we had 218 rigs under contract, compared to 259 and 218 rigs under contract as of September 30, 2018 and 2017, 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. 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 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 2019, 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. 10 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, 2019, and 2018, our drilling contract backlog, being the expected future dayrate revenue from executed contracts, was $1.2 billion and $1.1 billion, respectively. Approximately 25 percent of the total September 30, 2019 backlog is reasonably expected to be filled in fiscal year 2021 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. The following table sets forth the total backlog by reportable segment as of September 30, 2019 and 2018, and the percentage of the September 30, 2019 backlog reasonably expected to be filled in fiscal year 2021 and thereafter: (in billions) U.S. Land Offshore International Land Total Backlog Revenue September 30, 2019 September 30, 2018 $ $ 1.0 $ — 0.2 1.2 $ 0.9 — 0.2 1.1 Percentage Reasonably Expected to be Filled in Fiscal Year 2021 and Thereafter 21.4% — 47.5 We do not have material long-term contracts related to our H&P Technologies segment. 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 services 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 Our core values reflect who we are and the way our employees interact with one another, our customers, partners and shareholders. Our first core value of Actively C.A.R.E. means that we treat one another with respect. We care about each other, and from a safety perspective, our employees are committed to Controlling and Removing Exposures for themselves and others. Our core value of Service Attitude means that we do our part and more for those around us. We consider the needs of others and provide solutions to meet their needs. Our third core value, Innovative Spirit means that we constantly work to improve and are willing to try new approaches. We make decisions with the long–term view in mind. Finally, our core value of teamwork means that we listen to one another and work toward a common goal. We collaborate to achieve results and focus on success for our customers and shareholders. As of September 30, 2019, we had 7,767 employees within the United States (17 of whom were part time employees) and 743 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 working 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 stacked rigs, offshore platform rigs, and “named wind storm” risk in the Gulf of Mexico. 11 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 canceled, 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 generally 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 2020, as these regulations are generally imposed on exploration and production companies instead of contract drilling services 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 two 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 • • • • • 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. 12 Education and Training We strive to create a culture and work environment that enables us to attract, train, promote, and retain a diverse group of talented employees who together can help us gain a competitive advantage. We are dedicated to the continual training and development of our employees, especially of those in field operations, to ensure we can develop future managers and leaders from within our organization. Our organizational development team has responsibility for talent management as well ongoing training and development, including development and succession plans, mentoring and change management initiatives, and diversity and inclusion programs. Our training starts right at the beginning with good on–boarding procedures that focus on safety, responsibility, ethical conduct and inclusive teamwork. In addition to on–boarding training, we provide extensive ongoing training and career development focused on: • compliance with our Code of Business Conduct and Ethics (the "Code") and laws applicable to our business including: the importance of creating an inclusive environment that encourages the best out of all employees and avoids illegal discrimination the importance of individual responsibility in meeting our Code's requirements and taking action when needed, including reporting • • • • the Foreign Corrupt Practices Act, trade controls and anti–boycott training for appropriate employees (the H&P FCPA Policy, which prohibits facilitation payments, can be found on our website) skills and competencies directly related to employees' positions commitment to an incident–free work environment responsibility for personal safety and the safety of fellow employees, others on location and the environment Our Educational Assistance Plan offers reimbursement of tuition fees for any employee pursuing an undergraduate degree and, in some cases, post–graduate degrees. 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 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, our H&P Technologies segment is investing in digital technology safety solutions for the purpose of controlling and removing exposures on FlexRigs. 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 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 operational 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. 13 Environmental Management H&P does not itself lease properties used for the operations of our 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 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 foster a culture of trust and transparency and frequently remind our employees that they are encouraged to ask questions and report concerns. To empower every employee to promote responsible behavior, we have implemented an independent and anonymous reporting mechanism for employees to voice concerns pertaining to our Code, policies or compliance with law without fear of retaliation. Our Ethics Hotline, administered by a third–party, provides a convenient and confidential channel for employees and non-employees to report any suspected compliance concerns or complaints. 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. 14 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. 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. In the event that we are successful in developing new technologies for use in our business, there is no guarantee of future demand for those technologies. Customers may be reluctant or unwilling to adopt our new technologies. We may also have difficulty negotiating satisfactory terms for our technology services or may be unable to secure prices sufficient to obtain expected returns on our investment in the research and development of new technologies. Oil and natural gas prices and production levels, as well as market expectations regarding such 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 oil producing nations, such as Russia, 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 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. 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. Global economic conditions have a significant impact on oil and natural gas prices and any stagnation or deterioration in global economic conditions could result in less demand for our services. Demand for energy and petrochemicals is highly sensitive to changing 15 economic conditions; as a result, indications that economic growth is slowing may cause our customers to reduce their planned spending on exploration and development drilling. Adverse global economic conditions may cause our customers, vendors and/or suppliers to lose access to the financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations. Furthermore, challenging economic conditions may result in certain of our customers experiencing bankruptcy or otherwise becoming unable to pay vendors, including us. In the past, global economic conditions, and expectations for future global economic conditions, have sometimes experienced significant deterioration in a relatively short period of time and there can be no assurance that global economic conditions or expectations for future global economic conditions 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 services business is highly competitive, and a surplus of available drilling rigs may adversely affect our rig utilization and profit margins. The contract drilling services business is highly competitive. Competition in contract drilling services 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 reached 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 even as oil and natural gas prices, and drilling activity, rebound. In the event of a surplus 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 pricing, rig utilization and profit margins in the future, which could have a material adverse effect on our business, financial condition and results of operations. As of September 30, 2019, there were 120 of our available rigs not under contract. 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 disruptive trends in the drilling industry. 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. Although we take measures to ensure that we develop and use advanced oil and natural gas drilling technology, changes in technology or improvements by competitors 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 16 • 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 and technology 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 or other event resulting in significant environmental or property damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local authorities. Such an accident or other event 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, loss of customers and an inability to obtain insurance. 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 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 lease 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. Additionally, certain states, including Texas, New Mexico, Wyoming, and Louisiana, have enacted statutes generally referred to as "oilfield anti-indemnity acts," which expressly limit certain indemnity agreements contained in or related to indemnification in contracts, and could expose the Company to financial loss. Furthermore, other states may enact similar oilfield anti-indemnity acts. 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 working 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 stacked rigs, 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. 17 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 2020, 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 or adopted 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 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 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 at the federal, state or local levels. 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. For example, several U.S. states and cities have committed to advance the objectives of the Paris Agreement at the state or local level despite the pending federal withdrawal. 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. Our operations, especially our H&P Technologies segment, depend on effective and secure information technology systems. Threats to information technology systems, including as a result of cyber-attacks and cyber incidents, 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 18 intellectual property or theft of our FlexRig and other sensitive or proprietary technology, 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 and damage our information technology systems, negatively impact our ability to compete, enable the theft or misappropriation of funds, cause the loss, corruption or misappropriation of proprietary or confidential information, expose us to litigation 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 are being utilized to mitigate exposure to such risk, there can be no assurance that the actions and controls that we implement, or which we cause third party service providers to implement, will be sufficient to protect our systems, information or other property. 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. 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. Several political and regulatory authorities, governmental bodies, and environmental groups devote resources to campaigns aimed at eradicating hydraulic fracking. 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. 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 November 2018 and August 2019, we completed the acquisitions of Angus Jamieson Consulting and DrillScan Energy SAS, respectively. We also completed the acquisition of Magnetic Variation Services, LLC in December 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. 19 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, 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 to goodwill is the excess of the purchase price over the net identifiable assets acquired. At September 30, 2019, we had goodwill of $82.8 million and other intangible assets, net of $86.7 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 an asset impairment charge of $5.6 million related to the TerraVici reporting unit, 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 year 2018 did not result in an impairment charge. Beginning October 1, 2018, the goodwill associated with our technology reporting units were combined into one reporting unit, H&P Technologies. Our goodwill impairment analysis performed in the fourth quarter of fiscal year 2019 did not result in an impairment charge. 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 customers or supplying vendors becomes involved in a dispute over infringement of intellectual property rights relating to equipment or technology 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 supplying 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. 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. 20 Our business is subject to complex and evolving laws and regulations regarding privacy and data protection. The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs. For example, the EU has adopted EU General Data Protection Regulation 2016/679 (Regulation (EU) 2016/679 of the European Parliament and of the Council of 27 April 2016), which imposes severe penalties of up to the greater of 4% of worldwide turnover or 20 million Euro. Any failure, or perceived failure, by us to comply with applicable data protection laws could result in heightened risk of litigation, including private rights of action, and proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of cyber incidents or attacks, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result. 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, economic sanctions 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 25 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 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. 21 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 2019, we received approximately 45 percent of our consolidated operating revenues from our ten largest contract drilling services customers and approximately 20 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 services revenue may continue to decline and may not be ultimately realized as fixed term contracts may, in certain instances, be terminated without an early termination payment. Fixed term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. Even if an early termination payment is owed to us, a customer may be unable or may refuse to pay the early termination payment. We also may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, such as depressed market conditions. As of September 30, 2019, our contract drilling services backlog was approximately $1.2 billion for future revenues under firm commitments. Our contract drilling services 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 services expense includes fixed costs that may not decline in proportion to decreases in rig utilization and dayrates. Our contract drilling services 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 services 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. 22 Shortages of drilling equipment and supplies could adversely affect our operations. The contract drilling services 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 our customers, either due to contractual obligations or market constraints in the contract drilling services 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. In November 2019, six of our rigs operating in Argentina were impacted by a worker strike. The duration of the November strike was approximately twenty-four hours, however, if such strike recurs, it could have a material adverse effect on our business, financial condition and results of operations. During the year ended September 30, 2019, approximately 7.6 percent of our consolidated revenue was generated from our international operations, of which approximately 6 percent was from our Argentine operations. We currently have 16 rigs operating in Argentina. 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 oil and gas prices remain low for a prolonged period of time, decline further or if market conditions deteriorate or if we restructured our drilling fleet. For example, in fiscal years 2019 and 2018, we recognized impairment charges of $224.3 million and $17.5 million, respectively, related to tangible assets and equipment. If we experience future negative changes in our business climate such that we determine that one or more of our asset groups are impaired, we will be required to record additional impairment charges with respect to such asset groups. 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 “IRC”), 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, 2019, 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; 23 however, based on the amount of such net operating losses subject to the limitation, we do not expect 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 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. Tax legislation enacted during 2017 (the "Tax Reform Act"), among other things, (i) permanently reduced the U.S. corporate income tax rate, (ii) repealed the corporate alternative minimum tax, (iii) eliminated the deduction for certain domestic production activities, (iv) imposed new limitations on the utilization of net operating losses, (v) imposed new limitations on the deductibility of interest expense, (vi) imposed a type of minimum tax designed to reduce the benefits derived from intercompany transactions and payments that result in base erosion, and (vii) provided 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, as well as the regulations related to and interpretive guidance of such provisions released by the Treasury Department and the Internal Revenue Service. In the future, the Treasury Department and the Internal Revenue Service are expected to release additional regulations and interpretive guidance regarding 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, industry conditions 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. There have also been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities as well as to pressure lenders and other financial services companies to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves. 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, 2019, we had marketable securities with a total fair value of approximately $16.3 million, consisting of Schlumberger, Ltd. The total fair value of the portfolio of securities, consisting of Schlumberger, Ltd. and Ensco plc, now Valaris plc, was $82.5 million at September 30, 2018. In September 2019, we sold our remaining 1.6 million shares in Valaris, previously known as Ensco Rowan plc, for total proceeds of approximately $12.0 million. We adopted ASU No. 2016-01 on October 1, 2018, and as a result, we recognize our marketable equity securities that have readily determinable fair values at fair value, with changes in such values reflected in net income. Previously, we recognized changes in fair value of equity securities in other comprehensive income in the Consolidated Statements of Comprehensive 24 Income (Loss). There is no longer a requirement to consider whether the decline in fair value is other-than-temporary. At November 6, 2019, the fair value of the portfolio increased to approximately $16.5 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, including controls which were implemented in September 2019 and are presently in effect. As a result of these currency controls, our ability to remit funds from our Argentine subsidiary to its U.S. parent has been limited. Furthermore, the Argentine government has also instituted price controls on crude oil, diesel and gasoline prices and instituted an exchange rate freeze in connection with those prices. 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 2019, we experienced aggregate foreign currency losses of $8.0 million in Argentina. Our aggregate foreign currency losses across all of our operations for fiscal years 2019 and 2018 were $8.2 million and $4.0 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 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 2019, approximately 7.6 percent of our consolidated operating revenues were generated from the international contract drilling services business and approximately 91.6 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. 25 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 all or substantially all of our 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 or equal to 50 percent and certain priority debt (as 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. Changes in the method of determining the London Interbank Offered Rate, or the replacement of the London Interbank Offered Rate with an alternative reference rate, may adversely affect interest expense related to outstanding debt. Amounts drawn under our current debt agreements, including the 2018 Credit Facility, may bear interest at rates based on the London Interbank Offered Rate (“LIBOR”). On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The 2018 Credit Facility provides for a mechanism to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase- out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows. 26 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. The market price of our common stock may be highly volatile, and investors may not be able to resell shares at or above the price paid. The trading price of our common stock may be volatile. Securities markets worldwide experience significant price and volume fluctuations. This market volatility, as well as other general economic, market or political conditions, could reduce the market price of our common stock in spite of our operating performance. The following factors, in addition to other factors described in this “Risk Factors” section and elsewhere in this Form 10-K, may have a significant impact on the market price of our common stock: • • • • • changes in customer needs, expectations or trends and our ability to maintain relationships with key customers; our ability to implement our business strategy; changes in our capital structure, including the issuance of additional debt; public announcements (including the timing of these announcements) regarding our business, financial performance and prospects or new products or services, product enhancements, technological advances or strategic actions, such as acquisitions, restructurings or significant contracts, by our competitors or us; trading activity in our stock, including portfolio transactions in our stock by us, our executive officers and directors, and significant stockholders or trading activity that results from the ordinary course rebalancing of stock indices in which we may be included, such as the S&P 500 Index; short-interest in our common stock, which could be significant from time to time; our inclusion in, or removal from, any stock indices; investor perception of us and the industry and markets in which we operate; changes in earnings estimates or buy/sell recommendations by securities analysts; • • • • • whether or not we meet earnings estimates of securities analysts who follow us; • • regulatory or legal developments in the United States and foreign countries where we operate; and general financial, domestic, international, economic, and market conditions, including overall fluctuations in the U.S. equity markets. Item 1B. UNRESOLVED STAFF COMMENTS We have received no written comments regarding our periodic or current reports from the staff of the SEC that were issued 180 days or more preceding the end of fiscal year 2019 and that remain unresolved. Item 2. PROPERTIES Contract Drilling Services 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 We own or lease office and yard space to support our ongoing operations, including field and district offices in the United States and internationally. In addition, we have a fabrication and assembly facility near Houston, Texas as well as 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. 27 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. 28 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 6, 2019, there were 410 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 $65.61 $50.02 $74.33 $62.64 $73.60 $61.85 $69.08 $58.82 $72.94 $58.05 $64.51 $44.95 $48.05 $48.40 $52.15 $36.36 $0.70 $0.70 $0.70 $0.70 $0.71 $0.71 $0.71 $0.71 1Q 18 2Q 18 3Q 18 4Q 18 1Q 19 2Q 19 3Q 19 4Q 19 Stock price low Stock price high Dividend Issuer Purchases of Equity Securities The table below sets forth the information with respect to our repurchases of common shares during the three-month period ended September 30, 2019 (in thousands except per share amounts): Period July 1 - July 31 August 1 - August 31 September 1 - September 30 Total Total Number of Shares Purchased (1) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs — 1,000 $ — 1,000 — 42.78 — — — — — — — — (1) The Company has an evergreen authorization from the Board of Directors for the repurchase of up to four million common shares in any fiscal year. The repurchases may be made using our cash and cash equivalents or other available sources. Shares of stock repurchased pursuant to such authorization are held as treasury shares. Following the repurchase in August 2019 disclosed in the table, the Company could repurchase up to three million common shares through the year ended September 30, 2019. 29 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 Base Period INDEXED RETURNS Years Ending Sep 2014 Sep 2015 Sep 2016 Sep 2017 Sep 2018 Sep 2019 100.00 100.00 100.00 100.00 51.00 74.00 62.00 82.00 55.00 100.00 114.00 135.00 157.00 164.00 55.00 61.00 60.00 65.00 56.00 58.00 57.00 61.00 30.00 31.00 Comparison of Cumulative Five Year Total Return $250 $200 $150 $100 $50 $0 Sep 14 Sep 15 Sep 16 Sep 17 Sep 18 Sep 19 Helmerich & Payne, Inc. S&P 500 Index Dow Jones U.S. Select Oil Equipment & Services Index Philadelphia Stock Exchange Oil Service Sector 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 marketable securities 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. 30 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 (in thousands except per share amounts) Statements of Operations Selected Data Operating revenues Depreciation and amortization Selling, general and administrative Income (loss) from continuing operations Loss from discontinued operations Net income (loss) 2019 2018 (1) 2017 (1) 2016 (1) 2015 (1) $ 2,798,490 $ 2,487,268 $ 1,804,741 $ 1,624,332 $ 3,161,702 562,803 194,416 (32,510) (1,146) (33,656) 583,802 199,257 493,010 (10,338) 482,672 585,543 147,548 (127,863) (349) (128,212) 598,587 140,486 (52,990) (3,838) (56,828) 608,039 132,802 420,474 (47) 420,427 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 Cash dividends declared per common share Balance Sheet Data $ $ $ $ $ (0.33) (0.01) (0.34) (0.33) (0.01) (0.34) 2.84 $ $ $ $ $ 4.49 (0.10) 4.39 4.47 (0.10) 4.37 2.82 $ $ $ $ $ (1.20) — (1.20) (1.20) — (1.20) 2.80 $ $ $ $ $ (0.50) $ (0.04) (0.54) $ (0.50) $ (0.04) (0.54) $ 3.88 — 3.88 3.85 — 3.85 2.78 $ 2.75 Property, plant and equipment, net $ 4,502,084 $ 4,857,382 $ 5,001,051 $ 5,144,733 $ 5,563,170 Total assets (2) Long term debt, net Debt to capital ratio (3) Net working capital (4) $ 5,839,515 $ 6,214,867 $ 6,439,988 $ 6,832,019 $ 7,147,242 $ $ 479,356 10.8% 303,945 $ $ 493,968 10.1% 412,566 $ $ 492,902 10.6% 325,016 $ $ 491,847 $ 492,443 9.7% 9.1% 292,857 $ 316,070 (1) Adjusted for ASU No. 2017-07, adopted in fiscal year 2019. Refer to Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties for further details. (2) 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. (3) 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. (4) Net working capital is calculated as current assets, excluding cash and short-term investments, less current liabilities, excluding short–term debt or the current portion of long–term debt. 31 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, 2019, our drilling rig fleet included a total of 338 drilling rigs. Our contract drilling services segments consist of the U.S. Land segment with 299 rigs, the Offshore segment with 8 offshore platform rigs and the International Land segment with 31 rigs as of September 30, 2019. At the close of fiscal year 2019, we had 218 contracted rigs, of which 137 were under a fixed term contract and 81 were working well-to-well, compared to 259 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 in early fiscal 2019, 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 early 2009 and continues to evolve as E&Ps drill longer lateral wells with tighter well spacing. During this time, we designed, built and delivered new technology AC drive rigs (FlexRigs) to the market, substantially growing our fleet. The pace of progress of unconventional drilling over the years has been cyclical and volatile, dictated by crude oil and natural gas price fluctuations, which at times have proven to be dramatic. 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 industry’s 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, minimum of 1,500 horsepower drawworks, minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and multiple-well pad capability. Beginning in early calendar 2018, we saw the demand for super-spec rigs increase and we benefited 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. Heading into calendar year 2019, many customers established their respective budgets based on crude oil price expectations of between $50 and $55 per barrel, which in hindsight proved reasonable given the average crude oil price of approximately $57 per barrel through September 30, 2019. However, exiting calendar year 2018, industry activity levels were too high relative to recently established 2019 E&P capital budgets. Consequently, during the first six months of calendar year 2019, the industry experienced a gradual decline in activity, with the rig count falling by approximately 115 rigs (11%). Despite this decline, many of our customers had spent more than 50% of their planned capital expenditures through midyear. This resulted in a more rapid decline in activity with the rig count falling roughly 110 rigs (11%) in the subsequent, shorter three-month period. As a result, E&P spending for the remaining six months of 2019 became more austere due to our customers' emphasis on disciplined capital spending. Activity for the remainder of calendar year 2019 currently appears subdued and could be further negatively impacted by seasonal holidays and weather, as well as the conditions in the general economy. Given current crude oil price levels in the mid-$50 per barrel range, we anticipate our customers will set their 2020 capital budgets on that basis of between $50 and $55 per barrel, but that basis could change depending upon where crude oil prices move over the next several months, the time during which most customers will set their capital budgets. We expect our customers to remain capital disciplined, which will ultimately impact their level of spending during 2020. 32 During fiscal year 2019, we upgraded 21 FlexRigs and converted 5 FlexRigs to super-spec capacity, bringing our total super-spec FlexRig fleet to 233 rigs. At September 30, 2019, we had 55 idle super-spec FlexRigs, and we do not anticipate upgrading additional FlexRigs to super-spec capacity. Some customers may have a requirement or a preference for walking multiple-well pad capability, and we would convert certain idle super-spec skidding rigs to walking for multi-year term contracts. The lack of a sizable commitment to super-spec upgrades in fiscal year 2020 is the main driver of the decrease in our capital expenditure budget, which is initially set at between $275 million and $300 million for fiscal year 2020, down from $458.4 million in fiscal year 2019. In our H&P Technologies segment, we expect further market penetration of our digital technology offerings as customers continue to appreciate the economic benefits of deploying these technologies in their well programs. We continue to see the expansion for more pronounced industry adoption in a measured pace, though realizing the inherent challenges in adopting new and disruptive technologies in a flat oil price environment. Similar to our other segments, H&P Technologies shares the same underlying drivers in terms of crude oil prices and E&Ps' capital expenditures, but is ultimately tied to rig count activity, both the Company's and the industry's. In our International Land Drilling segment, we believe that our market leading position in the Neuquén basin of Argentina provides opportunities for us to either deploy additional AC rigs from the United States or upgrade rigs in country to super-spec. However, a recent political regime change in the country may impact the current contracting environment and possibly delay such opportunities further into calendar year 2020 or beyond. We continue to believe that our international land operations are a potential area of growth over the next several years, including for idle U.S. AC rigs, but acknowledge that such growth may be more sporadic than what we have experienced in the U.S. market. To that end, we have recently signed letters of intent in the U.A.E to put two FlexRigs back to work starting in fiscal year 2020. Additionally, we have also recently signed two letters of intent to put two more rigs back to work, one in Bahrain and one in Colombia. As of September 30, 2019, our Offshore Drilling operations have reported relatively stable utilization and cash flows. We expect a relatively similar operating environment during fiscal year 2020. Recent Developments Liquidity In December 2018, we settled an offer to exchange (the “Exchange Offer”) any and all outstanding 4.65 percent unsecured senior notes due 2025 (the “HPIDC 2025 Notes”) issued by Helmerich & Payne International Drilling Co., our wholly- owned direct subsidiary (“HPIDC”), for (i) up to $500.0 million aggregate principal amount of new 4.65 percent unsecured senior notes due 2025 of the Company (the “Company 2025 Notes”), with registration rights, and (ii) cash. Concurrently with the Exchange Offer, we solicited consents to adopt certain proposed amendments to the indenture governing the HPIDC 2025 Notes. The HPIDC 2025 Notes tendered had a principal amount of $487.1 million which represents 97.42 percent of the HPIDC 2025 Notes outstanding prior to the Exchange Offer. See “—Liquidity and Capital Resources” below. In March 2019, we settled a registered exchange offer (the “Registered Exchange Offer”) to exchange the Company 2025 Notes for new SEC-registered notes that are substantially identical to the terms of the Company 2025 Notes, except that the offer and issuance of the new notes have been registered under the Securities Act and certain transfer restrictions, registration rights and additional interest provisions relating to the Company 2025 Notes do not apply to the new notes. Approximately 99.99% of the Company 2025 Notes were exchanged in the Registered Exchange Offer. In September 2019, we redeemed the remaining approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes for approximately $14.6 million, including accrued interest and a prepayment premium (the “HPIDC 2025 Notes Redemption”). Simultaneously with the HPIDC 2025 Notes Redemption, HPIDC was released as a guarantor under the Company 2025 Notes and the 2018 Credit Facility (as defined herein). As a result of such release, H&P is the only obligor under the Company 2025 Notes and the 2018 Credit Facility. On November 13, 2019, we entered into the first amendment to our 2018 Credit Facility by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “2018 Credit Facility Amendment”). Amongst other things, the 2018 Credit Facility Amendment (i) extended the maturity date of the 2018 Credit Facility by one year to November 13, 2024, (ii) deleted certain negative covenants and (iii) refreshed the number of permissible extensions of the maturity date that require only the consent of extending lenders. Business Segments Effective October 1, 2018 and during the fourth quarter of fiscal year 2019, we implemented organizational changes, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. As a result of the reorganization of our operations during the first quarter of fiscal year 2019, we identified a new reportable segment, H&P Technologies. This reportable segment is used to drive development of advanced digital drilling technologies and directional drilling automation solutions, designed to improve safety, reliability, drilling consistency, and well performance economics for our customers. Subsequent to the reorganizations, all of our technology companies are included within the H&P Technologies 33 reportable segment. Combining drilling technology expertise within this new segment creates a holistic solution-based approach that includes products, services and capabilities. This approach provides performance-driven drilling services with greater levels of accuracy, consistency, optimization and a reduction of human error to create higher quality wellbores. This technology addresses our customers' unique challenges, resulting in less tortuosity and reducing positional uncertainty in the directional drilling process. Another key benefit is that many components of our digital technology, including MOTIVE bit guidance and MagVARTM survey correction, can be used on any rig, regardless of the drilling or service provider, allowing our customers to benefit from these technologies on all rigs. During fiscal year 2019, H&P Technologies released AutoSlideSM, which integrates the MOTIVE bit guidance system and several FlexApps to function within the FlexRig operating system and fully automates the control of mud motors while sliding during the vertical, the curve, and the lateral hole sections during horizontal drilling operations. Similar to our approach with FlexApps, H&P Technologies plans to market AutoSlide across the FlexRigTM fleet initially at a price point that improves cost-efficiency for our customers. Subsequently, there are also plans to integrate the software to make this offering compatible with non–H&P rigs for those customers with multi-vendor rig fleets. Currently, our AutoSlide application is commercially available in four regions including the Midland, Bakken, Eagle Ford and MidCon basins and we will be expanding into additional basins in the coming months. The adoption of our FlexApps continues as customers see the value of these technologies as demonstrated by their requests to use them on both H&P and non-H&P rigs. Our preparation to respond to this type of demand includes migrating our FlexApp offerings into our H&P Technologies business segment, which occurred in the fourth quarter of fiscal year 2019 and developing rig-neutral solutions to operate the software on non-H&P rigs. During the third quarter of fiscal year 2019, the Company established an incubator program for new research and development projects, the results of which have been included in "Other" within our segment disclosures. Business Combinations In November 2018, we announced our acquisition of Angus Jamieson Consulting (“AJC”), a software-based training and consultancy company based in Inverness, Scotland. AJC is recognized as an industry leader in wellbore positioning and provides software and in-depth training for clients. The skills and talents of AJC will accelerate capabilities to deliver future, value-driven automation in H&P Technologies. In August 2019, we completed an acquisition of an unaffiliated company, DrillScan Energy SAS and its subsidiaries ("DrillScan"), a leading provider of proprietary drilling engineering software, well engineering services and training for the oil and gas industry. DrillScan brings a team of highly respected industry experts who will contribute to research, development and innovation efforts to advance H&P’s digital technology portfolio. DrillScan will maintain its headquarters in France and its other international locations. DrillScan will operate as part of the H&P Technologies reportable segment. Impairments During the third quarter of fiscal year 2019, the Company's management performed a detailed assessment, considering a number of approaches, to maximize the utilization and enhance the margins of the domestic and international FlexRig4 asset groups. In June 2019, this assessment concluded that marketing a smaller fleet of these two asset groups would provide the best economic outcome. As such, the decision was made to downsize the number of domestic and international FlexRig4 drilling rigs, to be marketed to our customers, from 71 rigs to 20 domestic rigs and from 10 rigs to 8 international rigs and utilize the major interchangeable components of the decommissioned drilling rigs within these asset groups as capital spares for all of our remaining rig fleet. This has reduced the aggregate net book values of the FlexRig4 asset groups as of June 30, 2019 from $317.8 million to $107.5 million for domestic rigs and from $55.7 million to $47.8 million for international rigs. Following the downsizing process, we performed a detailed study to optimize the quantities of capital spares and drilling support equipment required to support the future operations of our rig fleet going forward. These decisions and analysis resulted in a write down of excess capital spares and drilling support equipment, which had an aggregate net book value of $235.3 million, to their estimated proceeds to ultimately be received on sale or disposal based on our historical experience with sales and disposals of similar assets, resulting in an impairment of $224.3 million ($195.0 million, net of tax, or $1.78 per diluted share), which was recorded in our Consolidated Statement of Operations for the year ended September 30, 2019. Of the $224.3 million total impairment charge recorded, $216.9 million ($188.6 million, net of tax, or $1.72 per diluted share) and $7.4 million ($6.4 million, net of tax, or $0.06 per diluted share) was recorded in our U.S. Land and International Land segment, respectively, during the year ended September 30, 2019. The significant assumptions in the valuation are classified as Level 2 inputs by Accounting Standards Codification ("ASC") Topic 820, Fair Value Measurement. Due to the downsizing of our domestic and international FlexRig4 asset groups, at June 30, 2019, we performed impairment testing on these two asset groups. We concluded that the net book values of the asset groups are 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, operating dayrates, operating costs, rig reactivation costs, drilling rig utilization, estimated remaining useful life, and net proceeds received upon future sale/disposition. The assumptions are consistent with the Company's internal forecasts for future years. Although we believe the assumptions used in our analysis are reasonable and appropriate and the probability-weighted average of expected future undiscounted net cash flows exceed the net book value for each of the domestic and international FlexRig4 asset groups as of June 30, 2019, different assumptions and estimates could materially impact the analysis and our resulting conclusion. 34 Results of Operations for the Fiscal Years Ended September 30, 2019 and 2018 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 loss for fiscal year 2019 was $32.5 million ($0.33 loss per share), compared with net income of $493.0 million ($4.49 earnings per share) for fiscal year 2018. Net loss in fiscal year 2019 and net income in fiscal year 2018 include after-tax income from early termination revenue associated with drilling contracts terminated prior to the expiration of their fixed term of $7.1 million ($0.07 per diluted share) and $12.6 million ($0.12 per diluted share), respectively. Net loss in fiscal year 2019 and net income in fiscal year 2018 include after tax gains from the sale of assets of $30.6 million ($0.28 per diluted share) and $16.7 million ($0.15 per diluted share), respectively. Additionally, net loss in fiscal year 2019 and net income in fiscal year 2018 include after-tax income from a tax benefit of $18.7 million ($0.17 per diluted share) and a tax benefit of $477.2 million ($4.36 per diluted share), respectively. Revenue Consolidated operating revenues were $2.8 billion in fiscal year 2019 and $2.5 billion in fiscal year 2018, including early termination revenue of $11.3 million and $17.1 million in each respective fiscal year. Excluding early termination revenue, operating revenue increased $317.1 million in fiscal year 2019 compared to fiscal year 2018. The number of revenue days in our U.S. Land segment increased by approximately 4.9 percent. Our activity was primarily driven by the fluctuation in oil prices as the second half of fiscal year 2018 experienced oil prices in the $62 to $77 per barrel range followed by a peak during the first quarter of fiscal year 2019 with prices reaching $71 per barrel. This period of increased pricing was followed by nine months of decreasing oil prices ranging from $51 to $64 per barrel. 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 year ended September 30, 2019, and mainly driven by the downsizing of our fleet of FlexRig4 drilling rigs, we wrote down excess capital spares and drilling support equipment, which had an aggregate net book value of $235.3 million, and as a result, an impairment charge of $224.3 million ($195.0 million, net of tax, or $1.78 per diluted share) was recorded in our Consolidated Statement of Operations. 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, were sold to a third party to be recycled. As a result, we recorded a non-cash impairment charge of $9.2 million ($7.0 million, net of tax, or $0.06 per diluted share). 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 ($4.2 million, net of tax, or $0.04 per diluted share). Furthermore, during the fourth quarter of fiscal year 2018, we recorded goodwill and intangible assets impairment losses of $5.6 million ($4.1 million, net of tax, or $0.04 per diluted share) 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. Interest and Dividend Income Interest and dividend income was $9.5 million and $8.0 million in fiscal years 2019 and 2018, respectively. The increase in interest and dividend income in fiscal year 2019 was primarily due to higher earnings on available cash equivalents and short-term investments. Direct Operating Expenses Direct operating expenses in fiscal year 2019 were $1.8 billion, compared with $1.7 billion in fiscal year 2018. The increase in fiscal year 2019 from fiscal year 2018 was primarily attributable to a higher level of activity in fiscal year 2019. Selling, General and Administrative Expense Selling, general and administrative expenses totaled $194.4 million in fiscal year 2019 and $199.3 million in fiscal year 2018. The $4.9 million decrease is primarily due to lower variable compensation and professional services expenses. Depreciation and Amortization Depreciation and amortization expense was $562.8 million in fiscal year 2019 and $583.8 million in fiscal year 2018. Depreciation and amortization includes amortization of intangible assets of $5.8 million and $5.4 million in fiscal years 2019 and 2018, respectively, and abandonments of equipment of $11.4 million and $27.7 million in fiscal years 2019 and 2018, respectively. In fiscal year 2019, depreciation expense also includes $4.7 million of accelerated depreciation for components on rigs that are planned for conversion in fiscal year 2020. 35 Interest Interest expense, net of amounts capitalized, totaled $25.2 million in fiscal year 2019 and $24.3 million in fiscal year 2018. Of the total $25.2 million interest expense incurred in fiscal year 2019, $1.7 million related to the prepayment premium paid for the HPIDC 2025 Notes Redemption in September 2019. Interest expense is primarily attributable to fixed rate debt outstanding. Income Taxes We had an income tax benefit of $18.7 million in fiscal year 2019 compared to an income tax benefit of $477.2 million in fiscal year 2018. The effective income tax rate was 36.5 percent in fiscal year 2019 compared to (3,012.3) percent in fiscal year 2018. The effective rates differ from the U.S. federal statutory rate (21.0 percent for fiscal year 2019 and 24.5 percent for fiscal year 2018) due to non-deductible permanent items, state and foreign income taxes, and adjustments to the deferred state income tax rate. In addition, 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 during 2017. 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 values of the net deferred tax assets are 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 2019 and 2018, we incurred $27.5 million and $18.2 million, respectively, of research and development expenses. The increase in expense is primarily related to new initiatives that are conducted through H&P Technologies. We anticipate research and development expenses to continue during fiscal year 2020. 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 2019 and 2018 is primarily a result of the impact of exchange rate fluctuations on remaining in country assets and liabilities. U.S. Land Operations Segment (in thousands, except operating statistics) 2019 2018 (2) % Change Operating revenues Direct operating expenses Selling, general and administrative expense Research and development Depreciation Asset impairment charge 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 the end of period Rig utilization $ 2,366,201 $ 2,063,362 1,514,641 1,346,192 44,141 653 496,770 216,908 58,157 262 504,805 5,695 93,088 $ 148,251 81,805 25,433 15,024 10,409 $ $ 299 67% 77,980 23,349 14,152 9,197 350 61% $ $ $ 14.7% 12.5 (24.1) 149.2 (1.6) 3,708.7 (37.2) 4.9 8.9 6.2 13.2 (14.6) 9.8 (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out of pocket” expenses of $285,614 and $242,617 for fiscal years 2019 and 2018, respectively. (2) Fiscal year 2018 has been restated due to the migration of FlexApps from our U.S. Land segment to our H&P Technologies segment. Operating Income In fiscal year 2019, the U.S. Land segment had operating income of $93.1 million compared to operating income of $148.3 million in fiscal year 2018. Included in U.S. land revenues for fiscal years 2019 and 2018 is approximately $6.4 million and $17.1 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). 36 Revenue Excluding early termination revenue of $78 and $219 per day for fiscal years 2019 and 2018, respectively, average revenue per day for fiscal year 2019 increased by $2,225 to $25,355 from $23,130 in fiscal year 2018. Our activity increased year-over-year due to increased customer demand, resulting in a 4.9 percent increase in revenue days when comparing fiscal year 2019 to fiscal year 2018. Direct Operating Expenses Average expense per day, excluding costs associated with a settled lawsuit of $336 per day for fiscal year 2019, increased $536 to $14,688 in fiscal year 2019 compared to fiscal year 2018. The increase is primarily due to higher pass-through costs, including higher wages for field personnel in some regions and higher rig recommissioning expense during fiscal year 2019. These factors were partially offset by a decrease in average daily expenses for idle rig expenses. Asset Impairment Charge During the fiscal year ended September 30, 2019, and mainly driven by the downsizing of our fleet of FlexRig4 drilling rigs, we wrote down excess capital spares and drilling support equipment and as a result, an impairment charge of $216.9 million ($188.6 million, net of tax, or $1.72 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2019. Depreciation Depreciation includes charges for abandoned equipment of $10.6 million and $26.3 million in fiscal years 2019 and 2018, respectively. In fiscal year 2019, depreciation expense also includes $4.7 million of accelerated depreciation for components on rigs that are scheduled for conversion in fiscal year 2020. As the drilling markets continued to recover during fiscal year 2017, we began abandoning older rig components as we upgrade rigs to meet customer demands for additional capabilities. This trend continued in fiscal years 2018 and 2019, although it has abated to some extent in fiscal year 2019 as our rig upgrade cadence has slowed. Utilization Rig utilization increased to 67 percent in fiscal year 2019 from 61 percent in fiscal year 2018. The total number of available rigs was 299 at September 30, 2019 compared to 350 at September 30, 2018. During the third quarter of fiscal year 2019, domestic FlexRig4’s were downsized by 51 rigs. At September 30, 2019, 194 out of 299 existing rigs in the U.S. Land segment were generating revenue. Of the 194 rigs generating revenue, 128 were under fixed term contracts, and 66 were working well-to-well. At November 6, 2019, the number of existing rigs under fixed term contracts in the segment was 129 and the number of rigs working in the well-to-well market was 63. Offshore Operations Segment (in thousands, except operating statistics) Operating revenues Direct operating expenses Selling, general and administrative expense Depreciation Segment operating income Operating Statistics Revenue days (1): Average rig revenue per day Average rig expense per day Average rig margin per day Number of rigs at the end of period Rig utilization $ $ $ $ 2019 147,635 114,306 3,725 10,010 19,594 2,163 37,478 28,663 8,815 8 74% $ $ $ $ 2018 142,500 101,477 4,507 10,392 26,124 2,036 35,331 26,009 9,322 8 70% % Change 3.6% 12.6 (17.4) (3.7) (25.0) 6.2 6.1 10.2 (5.4) — 5.7 (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out of pocket” expenses of $26,433 and $20,279 for fiscal years 2019 and 2018, 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 2019, the Offshore segment had operating income of $19.6 million compared to operating income of $26.1 million in fiscal year 2018. This decrease is primarily attributable to a rate reduction that took place during the fourth quarter of fiscal year 2018 as a long-term contract expired. These negative effects were partially offset by activity and cash flow from an additional rig that commenced operations during the third quarter of fiscal year 2018. Revenue Average rig revenue per day increased 6.1 percent to $37,478 in fiscal year 2019 compared to fiscal year 2018. This was primarily due to rigs returning from a standby rate to a full operating rate during fiscal year 2019. Direct Operating Expenses Average rig expense per day increased 10.2 percent in fiscal year 2019 compared to fiscal year 2018. This increase was primarily attributable to the factors mentioned above. Utilization At September 30, 2019 and 2018, six of our eight platform rigs were contracted. Utilization increased year- over-year as a previously idle rig returned to work in April 2018. 37 International Land Operations Segment (in thousands, except operating statistics) Operating revenues Direct operating expenses Selling, general and administrative expense Depreciation Asset impairment charge Segment operating income (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 the end of period Rig utilization 2019 2018 % Change $ 211,731 $ 238,356 (11.2)% 157,856 177,938 5,624 35,466 7,419 5,366 6,426 31,269 21,626 9,643 31 55% $ $ $ $ $ $ 3,658 46,826 10,617 (11.3) 53.7 (24.3) (30.1) (683) (885.7) 6,696 33,830 24,211 9,619 32 49% (4.0) (7.6) (10.7) 0.2 (3.1) 12.2 (1) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out of pocket” expenses of $10,797 and $11,828 for fiscal years 2019 and 2018, respectively. Also excluded are the effects of currency revaluation income and expense. Operating Income (Loss) The International Land segment had operating income of $5.4 million for fiscal year 2019 compared to operating loss of $0.7 million for fiscal year 2018. The increase was primarily driven by lower depreciation and impairment expense in 2019. Revenue Our activity has decreased primarily in response to lower commodity prices. We experienced a 4.0 percent decrease in revenue days when comparing fiscal year 2019 to fiscal year 2018. The average number of active rigs was 17.6 during fiscal year 2019 compared to 18.2 during fiscal year 2018. Direct Operating Expenses Direct operating expenses decreased in fiscal year 2019 to $157.9 million from $177.9 million in fiscal year 2018, the average rig expense per day decreased by $2,585, 10.7 percent, as compared to the fiscal year 2018 average rig expense. This decrease was primarily attributable to the devaluation of the Argentine peso, which decreased our average daily expenses as a result of being translated from local currency to the U.S. dollar. Included in direct operating expenses are foreign currency transaction losses of $8.2 million and $4.0 million for fiscal years 2019 and 2018, respectively. Asset Impairment Charge During the fiscal year ended September 30, 2019, and mainly driven by the downsizing of our fleet of FlexRig4 drilling rigs, we wrote down excess capital spares and drilling support equipment and as a result, an impairment charge of $7.4 million ($6.4 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, 2019. 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, were sold to a third party to be recycled. Certain components of these rigs with an $8.5 million net book value, that were not subject to the sale agreement, were 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 49 percent in fiscal year 2018 to 55 percent in fiscal year 2019 and was primarily driven by fewer available rig days as a result of the downsizing of six rigs in Ecuador in the fourth fiscal quarter of 2018 and two International FlexRig4 rigs in the third fiscal quarter of 2019. H&P Technologies Operations Segment (in thousands) Operating revenues Direct operating expenses Research and development Selling, general and administrative expense Depreciation and amortization Asset impairment charge Segment operating loss 2019 2018 % Change $ 59,990 $ 17,935 24,511 22,038 7,696 — 30,239 23,511 17,905 15,588 7,153 5,636 $ (12,190) $ (39,554) 98.4% (23.7) 36.9 41.4 7.6 (100.0) (69.2) 38 Operating Loss H&P Technologies had an operating loss of $12.2 million during fiscal year 2019 compared to an operating loss of $39.6 million during fiscal year 2018. The change was primarily driven by additional revenue growth during 2019 and the commercialization of our FlexApp offerings during fiscal year 2018. Additionally, during the fourth quarter of 2019, we migrated our FlexApp offerings into our H&P Technologies segment. The activity of our FlexApps was previously included in our U.S. Land segment. Prior period information has been restated to reflect the transfer of FlexApps revenues and related costs from U.S. Land segment to H&P Technologies segment. This was partially offset by additional research and development initiatives during fiscal year 2019. Other Operations Results of our other operations, excluding corporate selling, general and administrative costs and corporate depreciation, are as follows: (in thousands) Operating revenues Direct operating expenses Selling, general and administrative expense Research and development Depreciation and amortization Operating income 2019 2018 (1) % Change $ 12,933 $ 5,382 350 2,303 1,523 3,375 $ $ 12,811 5,053 389 — 1,486 5,883 1.0% 6.5 (10.0) — 2.5 (42.6) (1) Prior period information has been restated to reflect the change in reportable segments. Operating Income Operating income from other operations declined due to higher research and development expense. During fiscal year 2019, other operations had operating income of $3.4 million compared to operating income of $5.9 million during fiscal year 2018. Results of Operations for the Fiscal Years Ended September 30, 2018 and 2017 The results of operations for the fiscal years ended September 30, 2018 and 2017 are included in Part 2, Item 7 — "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our 2018 Annual Report on Form 10-K. 39 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 2019 and 2018. 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, 2019, we had $347.9 million of cash and cash equivalents on hand and $53.0 million of short-term investments. Our cash flows for the fiscal years ended September 30, 2019, 2018 and 2017 are presented below: (in thousands) Net cash provided (used) by: Operating activities Investing activities Financing activities Increase (decrease) in cash and cash equivalents Operating Activities Year Ended September 30, 2019 2018 2017 As adjusted $ $ 855,751 $ 557,852 $ 371,199 (422,636) (376,329) (472,362) (319,814) (444,988) (300,829) 56,786 $ (234,324) $ (374,618) Net working capital excluding cash and short-term investments decreased $108.7 million to $303.9 million as of September 30, 2019 from $412.6 million as of September 30, 2018 due to lower activity coupled with ongoing efforts to improve our cash conversion cycle. Net cash provided from operating activities was $855.8 million in fiscal year 2019 compared to $557.9 million in fiscal year 2018. The $297.9 increase in cash provided by operating activities is primarily due to the decrease in net working capital. In fiscal year 2017, net cash provided from operating activities was $371.2 million. The $186.7 increase in cash provided by operating activities between fiscal years 2018 and 2017 was primarily due to higher activity and average daily margins in fiscal year 2018. Investing Activities Capital Expenditures Our investing activities are primarily related to capital expenditures for our fleet. Our capital expenditures were $458.4 million in 2019, $466.6 million in fiscal year 2018 and $397.6 million in fiscal year 2017. Our fiscal year 2020 capital spending is currently estimated to be between $275 million and $300 million. This estimate includes normal capital maintenance requirements, information technology spending and a limited number of upgrades primarily related to augmenting the capabilities of our existing rig fleet. Acquisition of Business During fiscal years 2019 and 2018, we paid $16.2 million and $47.9 million, respectively, net of cash acquired, for the acquisition of drilling technology companies. Sale of Assets Our proceeds from asset sales totaled $50.8 million in fiscal year 2019, $44.4 million in fiscal year 2018 and $23.4 million in fiscal year 2017. 40 Stock Portfolio Held We manage marketable securities consisting of common shares of Schlumberger, Ltd. that, at the close of fiscal year 2019, had a fair value of $16.0 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. In September 2019, we sold our remaining 1.6 million shares in Valaris, previously known as Ensco Rowan plc, for total proceeds of approximately $12.0 million. Our marketable securities held as of September 30, 2019 are presented below: (in thousands, except for share amounts) Number of Shares Cost Basis Market Value Schlumberger, Ltd. Financing Activities 467,500 3,713 15,974 The increase of $56.5 million in net cash used by financing activities in fiscal year 2019 from fiscal year 2018 was primarily due to payments made for the early extinguishment of long-term debt and the repurchase of shares. Dividends We paid dividends of $2.84, $2.82, and $2.80 per share during fiscal years 2019, 2018 and 2017, respectively. Total dividends paid were $313.4 million, $308.4 million and $305.5 million in fiscal years 2019, 2018 and 2017, respectively. Adjusting for stock splits accordingly, we have increased the effective annual dividend per share every fiscal year for the past 47 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 November 13, 2018, we entered into a credit agreement by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, providing for an unsecured revolving credit facility (the “2018 Credit Facility”), which was originally set to mature on November 13, 2023. Pursuant to the 2018 Credit Facility Amendment entered into on November 13, 2019, among other things, the maturity date was extended by one year to November 13, 2024. 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 was originally guaranteed by HPIDC, but such guarantee was released simultaneously with the redemption of the HPIDC 2025 Notes and the release of HPIDC as a guarantor under the Company 2025 Notes. 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 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, as determined by Moody’s and Standard & Poor's ("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 the Company on September 30, 2019, the spread over LIBOR would have been 1.125 percent had borrowings been outstanding under the facility and commitment fees are 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 or equal to 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 September 30, 2019, there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. See Note 7—Debt to our Consolidated Financial Statements for more information about the 2018 Credit Facility. In connection with entering into the 2018 Credit Facility, we terminated our $300.0 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 Bank, National Association, as administrative agent, and the lenders party thereto. As of September 30, 2019, we had two outstanding letters of credit with banks under bilateral line of credit agreements, in the amounts of $25.5 million and $2.1 million, respectively. Subsequent to our fiscal year end, in October 2019, the balance of the $25.5 million outstanding letter of credit was reduced to $24.8 million. As of September 30, 2019, we also had a $20.0 million unsecured standalone line of credit facility, for the purpose of obtaining the issuance of bid and performance bonds, as well as other miscellaneous international needs. $11.5 million was outstanding under the $20.0 million facility as of September 30, 2019. 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, 2019, we were in compliance with all debt covenants, and we anticipate that we will continue to be in compliance during the next quarter of fiscal year 2020. Repurchase and Retirement of Common Shares We have an evergreen authorization to purchase up to four million common shares per fiscal year. During fiscal 2019, we purchased one million common shares at an aggregate cost of $42.8 million, which are held as treasury shares. We had no purchases of common shares during the fiscal years ended September 30, 2018 and 2017. 41 Future Cash Requirements Our operating cash requirements, scheduled debt repayments, interest payments, any declared dividends, and estimated capital expenditures for fiscal year 2020 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 10.8 percent at September 30, 2019 compared to 10.1 percent at September 30, 2018. 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”. Material Commitments Our contractual obligations as of September 30, 2019 are summarized in the table below: (in thousands) Long-term debt Interest (1) Operating leases (2) Purchase obligations (2) Payments due by year Total 2020 2021 2022 2023 2024 Thereafter $ 487,148 $ — $ — $ — $ — $ — $ 487,148 124,586 85,761 13,666 22,652 27,396 13,666 22,652 13,969 — 22,652 11,343 — 22,652 10,556 — 22,652 10,124 — 11,326 12,373 — Total contractual obligations $ 711,161 $ 63,714 $ 36,621 $ 33,995 $ 33,208 $ 32,776 $ 510,847 Interest on fixed rate debt was estimated based on principal maturities. See Note 7—Debt to our Consolidated Financial Statements. (1) (2) See Note 16—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 2019 and 2018, we did not make any contributions to the pension plan. Contributions may be made in fiscal year 2020 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond fiscal year 2020 are difficult to estimate due to multiple variables involved. At September 30, 2019, we had $17.9 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. 42 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, change in technology 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 or asset groups is more than the estimated undiscounted future cash flows, an impairment charge 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, a market approach considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors, a cost approach utilizing reproduction costs new as adjusted for the asset age and condition, and/or a combination of multiple approaches. 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 for impairment annually in the fourth fiscal quarter or more frequently if events or changes in circumstances indicate it is more likely than not that the carrying amount of the reporting unit holding such goodwill may exceed its fair value. 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. 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 apply 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 commonly used within the insurance industry that we believe are reliable. We also engage a third-party 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. 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 working 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 stacked rigs, 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 services 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 as the drilling service is provided. 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. 43 Income Taxes Deferred income taxes are accounted for under the liability method, which takes into account the differences between the basis of the assets and liabilities for financial reporting purposes and amounts recognized for income tax purposes. Our net deferred tax liability balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions. Included in our net deferred tax liability balance are deferred tax assets that are assessed for realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates. In addition, we operate in several countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions we believe have a greater than 50 percent likelihood of being sustained. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments. 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. 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 contracts are 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. At September 30, 2019, 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 $57,094. 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. 44 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, 2019, and our outstanding debt consisted of $487.1 million in a senior unsecured note, which has a fixed rate of 4.65 percent. The fair value of the fixed-rate debt was estimated to be $526.4 million and $509.3 million for fiscal years 2019 and 2018, respectively. Equity Price Risk On September 30, 2019, we had marketable securities with a total fair value of $16.3 million. The total fair value of our marketable securities was $82.5 million at September 30, 2018. A hypothetical 10 percent decrease in the market price for our marketable securities as of September 30, 2019 would decrease the fair value of our marketable securities by $1.6 million. In September 2019, we sold our remaining 1.6 million shares in Valaris, previously known as Ensco Rowan plc, for total proceeds of approximately $12.0 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. At November 6, 2019, the total fair value of our securities increased to approximately $16.5 million. 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. 45 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: Consolidated Balance Sheets at September 30, 2019 and 2018 Consolidated Statements of Operations for the Years Ended September 30, 2019, 2018 and 2017 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended September 30, 2019, 2018 and 2017 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2019, 2018 and 2017 Consolidated Statements of Cash Flows for the Years Ended September 30, 2019, 2018 and 2017 Notes to Consolidated Financial Statements Page 47 48 51 52 53 54 55 56 46 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) (ii) (iii) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; 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 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, 2019. 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, 2019. 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, 2019, 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 15, 2019 November 15, 2019 47 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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2019, 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, 2019, 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 15, 2019 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 included 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 included 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. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Description of the Matter Self-Insurance Accruals The Company's self-insurance liability for workers’ compensation and other casualty claims was $74.2 million at September 30, 2019. As described in Note 2 to the consolidated financial statements, this liability is based on a third-party actuarial analysis, which includes an estimate for incurred but not reported ("IBNR") claims. The actuarial analysis considers a variety of factors, including third-party adjusters’ estimates, historic experience, and statistical methods commonly used within the insurance industry. Auditing the Company's reserve for self-insured risks for worker’s compensation and other casualty claims is complex and required us to use our actuarial specialists due to the significant measurement uncertainty associated with the estimate, management’s application of significant judgment, and the use of various actuarial methods. 48 How We Addressed the Matter in Our Audit We evaluated the design and tested the operating effectiveness of the Company’s controls over the workers’ compensation and other casualty claims accrual process. For example, we tested controls over management’s determination of the appropriateness of the significant assumptions used in the calculation and the completeness and accuracy of the data underlying the reserve. Description of the Matter How We Addressed the Matter in Our Audit To evaluate the self-insurance liability for worker’s compensation and other casualty claims, we performed audit procedures that included, among others, testing the completeness and accuracy of the underlying claims data provided to management’s actuary and obtaining legal confirmation letters to evaluate the reserves recorded on significant litigated matters. Furthermore, we involved our actuarial specialists to assist in our evaluation of the methodologies applied by management’s actuary in establishing the actuarially determined reserve. We compared the Company’s assumptions to ranges of assumptions independently developed by our actuarial specialists. Impairment of Long-Lived Assets As more fully described in Note 5 to the consolidated financial statements, the Company recognized a $224.3 million charge in 2019 following the decommissioning of certain drilling rigs within the Domestic and International FlexRig4 asset groups. Also during 2019, the Company evaluated the Domestic and International FlexRig4 asset groups for recoverability, ultimately determining the net book values were recoverable through undiscounted future cash flows. As a result, no impairment of these asset groups was recognized; however, different assumptions and estimates could materially impact management's analysis and resulting conclusion. Auditing the Company's impairment analysis involved a high degree of subjectivity as the determination of undiscounted cash flows was based on assumptions about future market and economic conditions. Significant assumptions used in the Company’s undiscounted cash flow estimate included drilling rig utilization, period of operation and net proceeds received upon future sale/disposition. We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's process to estimate the undiscounted cash flows of the asset groups that were tested for recoverability. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions underlying the undiscounted cash flows. Our testing of the Company’s undiscounted cash flows included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. For example, we compared the projected drilling rig utilization assumption to current and forecasted industry and market information and any ongoing bid and contracting activity and compared the estimated net proceeds received upon future sale/disposition to industry ranges, market quotes and the Company’s historical experience. We also compared the projected period of operation to peer averages, the Company’s historical experience and market activity. Furthermore, we searched for and evaluated information that corroborates or contradicts the Company’s assumptions, performed retrospective reviews of projected cash flows to historical actuals, and performed a sensitivity analysis to evaluate the change in the projected cash flows that would result from changes in the underlying assumptions. We have served as the Company’s auditor since 1994. Tulsa, Oklahoma November 15, 2019 /s/Ernst & Young LLP 49 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, 2019, 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, 2019, 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 of the Company as of September 30, 2019 and 2018, 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, 2019, and the related notes and our report dated November 15, 2019 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 15, 2019 /s/ Ernst & Young LLP 50 HELMERICH & PAYNE, INC. Consolidated Balance Sheets (in thousands except share data and per share amounts) Assets Current Assets: Cash and cash equivalents Short-term investments Accounts receivable, net of allowance of $9,927 and $6,217, respectively Inventories of materials and supplies, net Prepaid expenses and other Total current assets Investments Property, plant and equipment, net Other Noncurrent Assets: Goodwill Intangible assets, net Other assets Total other noncurrent assets Total assets Liabilities and Shareholders’ Equity Current Liabilities: Accounts payable Accrued liabilities Total current liabilities Noncurrent Liabilities: Long-term debt, net Deferred income taxes Other Noncurrent liabilities - discontinued operations Total noncurrent liabilities Commitments and Contingencies (Note 16) Shareholders' Equity: Common stock, $.10 par value, 160,000,000 shares authorized, 112,080,262 and 112,008,961 shares issued as of September 30, 2019 and 2018, respectively, and 108,437,904 and 108,993,718 shares outstanding as of September 30, 2019 and 2018, respectively Preferred stock, no par value, 1,000,000 shares authorized, no shares issued Additional paid-in capital Retained earnings Accumulated other comprehensive income (loss) Treasury stock, at cost, 3,642,358 shares and 3,015,243 shares as of September 30, 2019 and 2018, respectively Total shareholders’ equity Total liabilities and shareholders' equity September 30, 2019 2018 $ 347,943 $ 284,355 52,960 495,602 149,653 68,928 41,461 565,202 158,134 66,398 1,115,086 1,115,550 31,991 98,696 4,502,084 4,857,382 82,786 86,716 20,852 64,777 73,207 5,255 190,354 143,239 $ 5,839,515 $ 6,214,867 $ 123,146 $ 287,092 410,238 479,356 806,611 115,746 15,341 132,664 244,504 377,168 493,968 853,136 93,606 14,254 1,417,054 1,454,964 11,208 — 510,305 3,714,307 (28,635) 11,201 — 500,393 4,027,779 16,550 (194,962) (173,188) 4,012,223 4,382,735 $ 5,839,515 $ 6,214,867 The accompanying notes are an integral part of these consolidated financial statements. 51 (in thousands, except per share amounts) Operating revenues Contract drilling services Other Operating costs and expenses HELMERICH & PAYNE, INC. Consolidated Statements of Operations Year Ended September 30, 2019 2018 2017 As adjusted (Note 2) $ 2,785,557 $ 2,474,458 $ 1,792,476 12,933 12,810 12,265 2,798,490 2,487,268 1,804,741 Contract drilling services operating expenses, excluding depreciation and amortization 1,803,204 1,647,557 1,244,735 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) Interest and dividend income Interest expense Gain (loss) on investment securities Other 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 Net income (loss) Basic earnings (loss) per common share: Income (loss) from continuing operations Loss from discontinued operations Net income (loss) Diluted earnings (loss) per common share: Income (loss) from continuing operations Loss from discontinued operations Net income (loss) Weighted average shares outstanding: Basic Diluted $ $ $ $ $ $ $ 5,382 562,803 27,467 194,416 224,327 5,053 583,802 18,167 199,257 23,128 4,582 585,543 12,047 147,548 — (39,691) (22,660) (20,627) 2,777,908 2,454,304 1,973,828 20,582 32,964 (169,087) 9,468 (25,188) (54,488) (1,596) (71,804) (51,222) (18,712) (32,510) 32,848 33,994 (1,146) 8,017 (24,265) 1 (876) (17,123) 15,841 (477,169) 493,010 23,389 33,727 (10,338) (33,656) $ 482,672 $ $ 4.49 (0.10) $ 4.39 $ 4.47 $ (0.10) $ 4.37 $ (0.33) $ (0.01) $ (0.34) $ (0.33) $ (0.01) $ (0.34) $ 5,915 (19,747) — (1,679) (15,511) (184,598) (56,735) (127,863) 3,285 3,634 (349) (128,212) (1.20) — (1.20) (1.20) — (1.20) 109,216 109,216 108,851 109,387 108,500 108,500 The accompanying notes are an integral part of these consolidated financial statements. 52 HELMERICH & PAYNE, INC. Consolidated Statements of Comprehensive Income (Loss) (in thousands) Net income (loss) Other comprehensive income (loss), net of income taxes: September 30, 2019 2018 2017 $ (33,656) $ 482,672 $ (128,212) Unrealized appreciation (depreciation) on securities, net of income taxes of $3.3 million at September 30, 2018 and ($0.5) million at September 30, 2017 — 9,001 (829) Minimum pension liability adjustments, net of income taxes of ($3.5) million at September 30, 2019, $1.9 million at September 30, 2018 and $1.9 million at September 30, 2017 Other comprehensive income (loss) Comprehensive income (loss) (11,875) (11,875) 5,249 14,250 3,333 2,504 $ (45,531) $ 496,922 $ (125,708) The accompanying notes are an integral part of these consolidated financial statements. 53 HELMERICH & PAYNE, INC. Consolidated Statements of Shareholders’ Equity (in thousands, except per share amounts) Shares Amount Common Stock Additional Paid-In Capital Retained Earnings Balance at September 30, 2016 111,400 $ 11,140 $ 448,452 $ 4,289,807 Accumulated Other Comprehensive Income (Loss) $ (204) Treasury Stock Shares Amount Total 3,322 $ (188,270) $ 4,560,925 Comprehensive income (loss): Net loss Other comprehensive income Dividends declared ($2.80 per share) Exercise of employee stock options, net of shares withheld for employee taxes Tax benefit of stock-based awards Vesting of restricted stock awards, net of shares withheld for employee taxes Stock-based compensation — — — 415 — 142 — — — — 42 — 14 — — — — (128,212) — (305,909) 15,738 4,414 (7,539) 26,183 — — — — — 2,504 — — — — — — — — 88 — — — — (128,212) 2,504 (305,909) (5,246) 10,534 — 4,414 (57) — 1,677 — (5,848) 26,183 Balance at September 30, 2017 111,957 11,196 487,248 3,855,686 2,300 3,353 (191,839) 4,164,591 Comprehensive income: Net income Other comprehensive income Dividends declared ($2.82 per share) Exercise of employee stock options, net of shares withheld for employee taxes Vesting of restricted stock awards, net of shares withheld for employee taxes Stock-based compensation Adoption of ASU 2016-09 — — — 1 51 — — — — — — 5 — — — — — 482,672 — (310,024) (7,557) (11,857) 31,687 872 — — — (555) — 14,250 — — — — — — — — — — — 482,672 14,250 (310,024) (202) 10,992 3,435 (136) 7,659 — — — — (4,193) 31,687 317 Balance at September 30, 2018 112,009 11,201 500,393 4,027,779 16,550 3,015 (173,188) 4,382,735 Comprehensive loss: Net loss Other comprehensive loss Dividends declared ($2.84 per share) Exercise of employee stock options, net of shares withheld for employee taxes Vesting of restricted stock awards, net of shares withheld for employee taxes Stock-based compensation Share repurchases Cumulative effect adjustment for adoption of ASU No. 2014-09 (Note 10) Cumulative effect adjustment for adoption of ASU No. 2016-01 (Note 2) Reclassification of stranded tax effect for adoption of ASU No. 2018-02 (Note 2) — — — — 71 — — — — — — — — — 7 — — — — — — — — (33,656) — (313,088) — — — — (38) (7,153) (17,227) 34,292 — — — — — (11,875) — — — — — — — — — — — — (33,656) (11,875) (313,088) (151) 8,474 1,321 (222) 12,531 — — (4,689) 34,292 1,000 (42,779) (42,779) — — — — — — (38) — — 29,071 (29,071) 4,239 (4,239) Balance at September 30, 2019 112,080 $ 11,208 $ 510,305 $ 3,714,307 $ (28,635) 3,642 $ (194,962) $ 4,012,223 The accompanying notes are an integral part of these consolidated financial statements. 54 HELMERICH & PAYNE, INC. Consolidated Statements of Cash Flows (in thousands) Cash flows from operating activities: Net income (loss) Adjustment for loss from discontinued operations Income (loss) from continuing operations Adjustments to reconcile net income to net cash provided by operating activities: 2019 Year Ended September 30, 2018 2017 As adjusted (Note 2) $ (33,656) $ 1,146 (32,510) $ 482,672 10,338 493,010 (128,212) 349 (127,863) Depreciation and amortization Asset impairment charge Amortization of debt discount and debt issuance costs Provision for bad debt Stock-based compensation Pension settlement charge Loss (gain) on investment securities Gain on sale of assets Deferred income tax benefit Other Change in assets and liabilities increasing (decreasing) cash: Accounts receivable Inventories of materials and supplies Prepaid expenses and other Other noncurrent assets Accounts payable Accrued liabilities Deferred income tax liability Other noncurrent liabilities Net cash provided by operating activities from continuing operations Net cash used in operating activities from discontinued operations Net cash provided by operating activities 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 sale of marketable securities Proceeds from asset sales Net cash used in investing activities Cash flows from financing activities: Dividends paid Debt issuance costs Proceeds from stock option exercises Payments for employee taxes on net settlement of equity awards Payment of contingent consideration from acquisition of business Payments for early extinguishment of long term debt Share repurchase Net cash used in financing activities Net increase (decrease) in cash and cash equivalents and restricted cash Cash and cash equivalents and restricted cash, beginning of period Cash and cash equivalents and restricted cash, end of period Supplemental disclosure of cash flow information: Cash paid during the period: Interest paid Income tax paid (refund), net Changes in accounts payable and accrued liabilities related to purchases of property, plant and equipment 562,803 224,327 1,732 2,321 34,292 1,953 54,488 (39,691) (44,554) (5,248) 70,323 1,821 (176) (10,430) (9,147) 40,887 371 2,251 855,813 (62) 855,751 (458,402) (97,652) (16,163) 86,765 11,999 50,817 (422,636) (313,421) (3,912) 3,053 (6,418) — (12,852) (42,779) (376,329) 56,786 326,185 382,971 26,739 16,218 17,771 $ $ $ $ 583,802 23,128 1,067 2,193 31,687 913 (1) (22,660) (486,758) 6,710 (85,202) (22,427) (3,827) 5,568 (4,461) 43,798 2,268 (10,787) 558,021 (169) 557,852 (466,584) (71,049) (47,886) 68,776 — 44,381 (472,362) (308,430) — 6,355 (7,114) (10,625) — — (319,814) (234,324) 560,509 326,185 $ 585,543 — 1,055 2,016 26,183 1,640 — (20,627) (24,111) 543 (97,114) (10,607) 29,452 11,550 39,412 (36,120) 3,472 (13,075) 371,349 (150) 371,199 (397,567) (69,866) (70,416) 69,449 — 23,412 (444,988) (305,515) — 11,285 (6,599) — — — (300,829) (374,618) 935,127 560,509 20,502 $ (38,400) $ 22,936 (23,463) (2,245) $ (10,539) $ $ $ $ The accompanying notes are an integral part of these consolidated financial statements. 55 NOTE 1 NATURE OF OPERATIONS HELMERICH & PAYNE, INC. Notes to Consolidated Financial Statements Helmerich & Payne, Inc. (“H&P,” 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 solutions and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. Effective October 1, 2018 and during the fourth quarter of fiscal year 2019, we implemented organizational changes, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. Effective October 1, 2018, certain operations previously reported in “Other” within our segment disclosures are now managed and presented within the new H&P Technologies reportable segment. As a result, beginning with the reporting of first quarter 2019, our operations are organized into the following reportable segments: U.S. Land, Offshore, International Land and H&P Technologies. Additionally, during the fourth quarter of fiscal year 2019, we migrated our FlexApp offerings into our H&P Technologies business segment. The activity of our FlexApps was previously included in our U.S. Land segment. Certain other corporate activities, our real estate operations and our incubator program for new research and development projects are included in "Other". All segment disclosures have been restated for these segment changes. Refer to Note 17—Business Segments and Geographic Information for further details on H&P Technologies, our new reportable segment. Our U.S. Land operations are primarily located in Colorado, Louisiana, Ohio, Oklahoma, Montana, New Mexico, North Dakota, Pennsylvania, Texas, Utah, West Virginia and Wyoming. Additionally, Offshore operations are conducted in the Gulf of Mexico and our International Land operations have rigs primarily located in four international locations: Argentina, Bahrain, Colombia and United Arab Emirates (“U.A.E.”). 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 $8.2 million, $4.0 million and $7.1 million in fiscal years 2019, 2018 and 2017, 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. 56 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 $35.0 million and $41.8 million at September 30, 2019 and 2018, respectively. Of the total at September 30, 2019 and 2018, $3.0 million and $11.3 million, respectively, is related to the acquisition of drilling technology companies described in Note 3—Business Combinations, $2.0 million as of both fiscal year ends is from the initial capitalization of the captive insurance company, and $30.0 million and $28.5 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 "—Recently Issued Accounting Updates" below for changes to the presentation of restricted cash effective October 1, 2018 as a result of adopting Accounting Standards Update (“ASU”) No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. The restricted cash and cash equivalents are reflected in the Consolidated Balance Sheets as follows: (in thousands) Cash Restricted Cash Prepaid expenses and other Other assets Total cash, cash equivalents, and restricted cash Inventories of Materials and Supplies September 30, 2019 2018 2017 $ 347,943 $ 284,355 $ 521,375 31,291 3,737 39,830 2,000 32,439 6,695 $ 382,971 $ 326,185 $ 560,509 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 and labor. 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. The reserves for excess and obsolete inventory were $11.5 million and $9.9 million for fiscal years 2019 and 2018, respectively. Investments We maintain investments in equity securities of certain publicly traded companies. We recognize our marketable equity securities that have readily determinable fair values at fair value, with changes in such values reflected in net income. We adopted ASU No. 2016-01 on October 1, 2018, and as a result, we recognize our marketable equity securities that have readily determinable fair values at fair value, with changes in such values reflected in net income. Previously, we recognized changes in fair value of equity securities in other comprehensive income in the Consolidated Statements of Comprehensive Income (Loss). There is no longer a requirement to consider whether the decline in fair value is other-than-temporary. 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 salvage 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. We had no capitalized interest for fiscal year 2019 and $0.4 million and $0.3 million of capitalized interest for 2018 and 2017, respectively. 57 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 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, restructuring of our drilling fleet, 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, a market approach considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors, a cost approach utilizing reproduction costs new as adjusted for the asset age and condition, and/or a combination of multiple approaches. 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 is not amortized but is 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 it is more likely than not that the carrying value may exceed fair value. 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 5 to 20 years and are evaluated for impairment in accordance with our policies for valuation of long-lived assets. Drilling Revenues Contract drilling services 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 on a straight-line basis as the drilling service is provided. 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 2019, 2018 and 2017 were $322.8 million, $274.7 million and $179.9 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 2019, 2018 and 2017 was approximately $11.3 million, $17.1 million and $29.4 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. Our rent revenues are as follows: (in thousands) Minimum rents Overage and percentage rents Year Ended September 30, 2019 2018 2017 $ 10,168 $ 9,950 $ 932 1,040 9,735 936 58 At September 30, 2019, minimum future rental income to be received on noncancelable operating leases was as follows (in thousands): Fiscal Year 2020 2021 2022 2023 2024 Thereafter Total $ Amount 8,204 6,239 3,983 2,858 2,142 5,990 $ 29,416 Leasehold improvement allowances are capitalized and amortized over the lease term. At September 30, 2019 and 2018, the cost and accumulated depreciation for real estate properties were as follows: (in thousands) Real estate properties Accumulated depreciation Income Taxes September 30, 2019 2018 $ $ 72,507 $ (43,570) 28,937 $ 69,133 (42,272) 26,861 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. Stock-Based Compensation Stock-based compensation expense is determined using a fair-value-based measurement method for all awards granted. During the fiscal year ended September 30, 2019, there were no new non-qualified stock options granted, as we have, prospectively and for fiscal year 2019, replaced stock options with performance share units as a component of our executives’ long-term equity incentive compensation. We have also eliminated stock options as an element of our director compensation program. The Board has determined to award stock-based compensation to directors solely in the form of restricted stock. The fair value of each option granted in prior years was 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 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. The grant date fair value of performance share units is determined through use of the Monte Carlo simulation method. The Monte Carlo simulation method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined peer group of companies’ (the "Peer Group") stock, risk free rate of return, dividend yields and cross-correlations between the Company and our Peer Group. 59 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 is recorded as a component of contract drilling services operating expenses and selling, general and administrative expenses in the Consolidated Statements of Operations. See Note 11—Stock- based Compensation for additional discussion on stock-based compensation. 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. The stock to be offered pursuant to the grant of an award under the Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan may be authorized as treasury shares. 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. Recently Issued Accounting Updates Changes to U.S. GAAP are established by the Financial Accounting Standards Board (“FASB”) in the form of 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 Date of Adoption Effect on the Financial Statements or Other Significant Matters October 1, 2018 We adopted this ASU during the first quarter of fiscal year 2019, as required. There was no impact to our consolidated financial statements and disclosures. October 1, 2018 We adopted this ASU during the first quarter of fiscal year 2019, as required, on a retrospective basis. The retrospective impact was not material to our consolidated financial statements and disclosures. our financial statements: Standard Description Recently Adopted Accounting Pronouncements ASU No. 2017-09, Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost 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. The ASU changes how employers that sponsor defined benefit pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers should 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 should 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. The amendments are applied retrospectively for the presentation of the service cost component and other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement. 60 Standard Description 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 cash amounts for the periods shown on the statement of cash flows. Under prior U.S. GAAP, the tax effects of intra-entity asset transfers (intercompany sales) were deferred until the transferred asset was sold to a third party or otherwise recovered through use. This was 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 recognizes 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 is also 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. The ASU was 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. One of the key changes is related to contingent consideration payments made after a business combination. Cash payments not made soon after the acquisition date of a business combination by an acquirer to settle a contingent consideration liability should be separated and classified as cash outflows for financing activities and operating activities. Cash payments up to the amount of the contingent consideration liability recognized at the acquisition date (including measurement-period adjustments) should be classified as financing activities; any excess should be classified as operating activities. 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. At adoption, a cumulative-effect adjustment to beginning retained earnings is recorded to reflect the fair value of such investments at the date of adoption in retained earnings rather than accumulated other comprehensive income. ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities Date of Adoption October 1, 2018 October 1, 2018 Effect on the Financial Statements or Other Significant Matters We adopted this ASU during the first quarter of fiscal year 2019, as required, on a retrospective basis. The retrospective impact on the consolidated statement of cash flows for the year ended September 30, 2018 and 2017 was an increase of $2.7 million and $9.6 million in net cash provided by operating activities, respectively. We adopted this ASU during the first quarter of fiscal year 2019, as required. There was no material impact to our consolidated financial statements and disclosures. October 1, 2018 October 1, 2018 We adopted this ASU during the first quarter of fiscal year 2019, as required, on a retrospective basis. The retrospective impact on the consolidated statement of cash flows for the year ended September 30, 2018 was a reclassification of $10.6 million from net cash provided by operating activities to net cash used in financing activities. There was no impact in fiscal year 2017. We adopted this ASU during the first quarter of fiscal year 2019, as required. As a result, changes in the fair value of our equity investments have been recognized in net income since the date of adoption, and our future results of operations will continue to be subject to stock market fluctuations for these investments. The cumulative catch up impact that was recorded to the beginning balance of retained earnings at October 1, 2018 was a reclassification of $44.0 million ($29.1 million after-tax) of cumulative gains from the beginning balance of accumulated other comprehensive income. 61 Standard Description ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) 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 In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”). The update outlined a single comprehensive model for companies to use in accounting for revenue arising from contracts with customers and superseded other 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 required 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. Companies could use either a full retrospective or a modified retrospective approach to adopt the updates. This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of the FASB’s 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 update is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted. This ASU relates to the impacts of the Tax Reform Act. The guidance permits the reclassification of certain income tax effects of the Tax Reform Act from Accumulated Other Comprehensive Income (Loss) 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. Standards that are not yet adopted as of September 30, 2019 This ASU aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). This update is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted. ASU No. 2018-15, Intangibles - Goodwill and Other - Internal Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract Date of Adoption October 1, 2018 Effect on the Financial Statements or Other Significant Matters We adopted this topic, using the modified retrospective transitional approach, during the first quarter of fiscal year 2019, as required. We recognized the cumulative effect by initially applying the revenue standard as an adjustment to the opening balance of retained earnings during the period (October 1, 2018). Refer to Note 10—Revenue from Contracts with Customers for the impact of the adoption. June 30, 2019 June 30, 2019 October 1, 2019 We early adopted this ASU during the third quarter of fiscal year 2019. The adoption did not have a material impact to our consolidated financial statements and disclosures. Refer to Note 13—Fair Value Measurement of Financial Instruments. We early adopted this ASU during the third quarter of fiscal year 2019. We reclassified $4.2 million from accumulated other comprehensive income (loss) to retained earnings for stranded income tax effects resulting from the Tax Reform Act. The adoption did not have a material impact to our consolidated financial statements and disclosures. We plan to early adopt this ASU in the first quarter of fiscal year 2020. At this time, we are currently evaluating the impact the new guidance may have on our consolidated financial statements and disclosures; however, we do not believe the adoption of this ASU will have a material effect on the consolidated financial statements and disclosures. 62 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. 2016-13, Financial Instruments – Credit Losses (Topic 326) and related ASUs issued subsequent ASU No. 2016-02, Leases (Topic 842) and related ASUs issued subsequent Standard Description This ASU amends ASC 715 to add, remove, and clarify disclosure requirements related to defined benefit, pension and other postretirement plans. This update is effective for annual and interim periods ending after December 15, 2020. Date of Adoption October 1, 2021 Effect on the Financial Statements or Other Significant Matters We are currently evaluating the impact the new guidance may have on our consolidated financial statements and disclosures. 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. ASU No. 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 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. ASU No. 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 of adoption with an option to use certain practical expedients. October 1, 2020 We are currently evaluating the impact the new guidance may have on our consolidated financial statements and disclosures. October 1, 2019 We adopted the new lease guidance on October 1, 2019, using the transition method that allows us to initially apply Topic 842 as of October 1, 2019 and recognize a cumulative- effect adjustment in the period of adoption, without restating prior years' financial statements. Refer to the paragraph below for additional disclosure. Adoption of ASU No. 2016-02 - Leases As stated in the table above, we adopted ASU No. 2016-02 on October 1, 2019. Additionally, we have elected most of the standard’s available practical expedients upon adoption, including the package of practical expedients that allows us to not reassess expired or existing contracts for: (1) embedded leases, (2) lease classification and (3) initial direct costs. In addition, we are expecting to elect the Topic 842 practical expedient available to lessors to not separate lease and non-lease components and account for the combined component under Topic 606 when the non-lease component is the predominant element of the combined component. The lessor practical expedient is limited to circumstances in which the lease, if accounted for separately, would be classified as an operating lease under Topic 842. For existing contracts that do not require reassessment due to the practical expedient package we have elected, those contracts will continue to be classified in our financial statements according to our accounting policies in place at September 30, 2019. New contracts entered into or any contract in existence at September 30, 2019 modified on or after October 1, 2019 will be assessed in accordance with Topic 842 and Topic 606, as applicable. We are analyzing and updating data previously collected to evaluate the impact the adoption will have on our financial statements and implementing a system to capture the increased reporting and disclosure requirements. Currently, we tentatively estimate that, as a lessee, our assets and liabilities will increase by no more than $100 million upon adoption of the new lease guidance. Based upon the transition method and practical expedients we have elected, we do not believe the adoption of this standard will have a material effect on our statements of operations and cash flows. 63 Cash Flows The following is a summary of the retrospective impact of our adoption of ASU No. 2016-15 and ASU 2016-18: (in thousands) Consolidated Statements of Cash Flows Change in prepaid expenses and other Change in noncurrent assets Change in accrued liabilities Net cash provided by operating activities Payment of contingent consideration from acquisition of business Net cash used in financing activities (in thousands) Consolidated Statements of Cash Flows Change in prepaid expenses and other Change in noncurrent assets Net cash provided by operating activities Concentration of Credit Risk Historical Accounting Method Year Ended September 30, 2018 Effect of Adoption of ASU No. 2016-15 Effect of Adoption of ASU No. 2016-18 As Adjusted $ (11,218) $ 10,263 33,173 544,531 — (309,189) — $ — 10,625 10,625 (10,625) (10,625) 7,391 $ (4,695) — 2,696 — — (3,827) 5,568 43,798 557,852 (10,625) (319,814) Historical Accounting Method Year Ended September 30, 2017 Effect of Adoption of ASU No. 2016-15 Effect of Adoption of ASU No. 2016-18 $ 24,579 $ — $ 4,873 $ 6,855 361,631 — — 4,695 9,568 As Adjusted 29,452 11,550 371,199 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 that constituted 10 percent or more of our total revenues as follows: (in thousands) EOG Resources, Inc. 2018 2017 $ 258,194 $ 163,582 In fiscal year 2019, no individual customers constituted 10 percent or more of our total revenues. 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. 64 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, historical experience and statistical methods commonly used within the insurance industry that we believe are reliable. We have also engaged a third-party 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 also has a history of implementing currency controls, which restrict the conversion and repatriation of U.S. dollars, including controls which were implemented in September 2019 and are presently in effect. As a result of these currency controls, our ability to remit funds from our Argentine subsidiary to its U.S. parent has been limited. Furthermore, the Argentine government has also instituted price controls on crude oil, diesel and gasoline prices and instituted an exchange rate freeze in connection with those prices. 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. Although we attempt to minimize the potential impact of such risks by operating in more than one geographical area, during the year ended September 30, 2019, approximately 7.6 percent of our operating revenues were generated from international locations in our contract drilling services business compared to 9.6 percent during the year ended September 30, 2018. During the year ended September 30, 2019, approximately 91.6 percent of operating revenues from international locations were from operations in South America compared to 96.0 percent during the year ended September 30, 2018. 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. 65 NOTE 3 BUSINESS COMBINATIONS Fiscal Year 2019 Acquisitions On August 21, 2019, we completed an acquisition of an unaffiliated company, DrillScan Energy SAS and its subsidiaries ("DrillScan"), which is now a wholly-owned subsidiary of the Company, a total consideration of approximately $32.7 million, which includes $17.7 million of contingent consideration. The fair value of total assets acquired, and liabilities assumed, as of the acquisition date, were $36.3 million and $3.6 million, respectively, including goodwill of $14.9 million. Of the total assets acquired, $19.1 million was allocated to identifiable intangible assets. DrillScan is a leading provider of proprietary drilling engineering software, well engineering services and training for the oil and gas industry. The operations of DrillScan are included in the H&P Technologies reportable business segment. The acquisition of DrillScan was accounted for as a business combination in accordance with FASB ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. In accordance with GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. This acquisition is still within this measurement period, and as a result, the acquisition date fair values we have recorded for the assets acquired and liabilities assumed are subject to change. On November 1, 2018, we completed an acquisition of an unaffiliated company, Angus Jamieson Consulting (“AJC”), which is now a wholly-owned subsidiary of the Company, for total consideration of approximately $3.4 million. AJC is a software- based training and consultancy company based in Inverness, Scotland and is widely recognized as an industry leader in wellbore positioning. The operations of AJC are included in the H&P Technologies reportable segment. The acquisition of AJC has been accounted for as a business combination in accordance with FASB ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. The allocation of the purchase price includes goodwill of $3.1 million. Fiscal Year 2018 Acquisition 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. 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. The amounts placed in escrow as of September 30, 2018 were released to the sellers during the year ended September 30, 2019. Of the $48.5 million total consideration, $28.7 million was allocated to identifiable intangible assets and $17.8 million was recorded as goodwill. 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, 2019 was primarily 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 United States 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 21,028 Bolivars per United States dollar at September 30, 2019. The DICOM floating rate might not reflect the barter market exchange rates. 66 NOTE 5 PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment as of September 30, 2019 and 2018 consisted of the following: (in thousands) Contract drilling services equipment Tubulars Real estate properties Other Construction in progress Accumulated depreciation Property, plant and equipment, net Impairments Estimated Useful Lives September 30, 2019 September 30, 2018 4 - 15 years $ 7,881,323 7,829,038 4 years 10 - 45 years 2 - 23 years 618,310 72,507 471,803 117,761 9,161,704 (4,659,620) $ 4,502,084 $ 613,043 68,888 471,310 163,968 9,146,247 (4,288,865) 4,857,382 During the third quarter of fiscal year 2019, the Company's management performed a detailed assessment, considering a number of approaches, to maximize the utilization and enhance the margins of the domestic and international FlexRig4 asset groups. In June 2019, this assessment concluded that marketing a smaller fleet of these two asset groups would provide the best economic outcome. As such, the decision was made to downsize the number of domestic and international FlexRig4 drilling rigs, to be marketed to our customers, from 71 rigs to 20 domestic rigs and from 10 rigs to 8 international rigs and utilize the major interchangeable components of the decommissioned drilling rigs within these asset groups as capital spares for all of our remaining rig fleet. This has reduced the aggregate net book values of the FlexRig4 asset groups as of June 30, 2019 from $317.8 million to $107.5 million for domestic rigs and from $55.7 million to $47.8 million for international rigs. Following the downsizing process, we performed a detailed study to optimize the quantities of capital spares and drilling support equipment required to support the future operations of our rig fleet going forward. These decisions and analysis resulted in a write down of excess capital spares and drilling support equipment, which had an aggregate net book value of $235.3 million, to their estimated proceeds to ultimately be received on sale or disposal based on our historical experience with sales and disposals of similar assets, resulting in an impairment of $224.3 million ($195.0 million, net of tax, or $1.78 per diluted share), which was recorded in our Consolidated Statement of Operations for the year ended September 30, 2019. Of the $224.3 million total impairment charge recorded, $216.9 million ($188.6 million, net of tax, or $1.72 per diluted share) and $7.4 million ($6.4 million, net of tax, or $0.06 per diluted share) was recorded in our U.S. Land and International Land segment, respectively. The significant assumptions in the valuation are classified as Level 2 inputs by ASC Topic 820, Fair Value Measurement and Disclosures. Due to the downsizing of our domestic and international FlexRig4 asset groups, at June 30, 2019, we performed impairment testing on these two asset groups. We concluded that the net book values of the asset groups are 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, operating dayrates, operating costs, rig reactivation costs, drilling rig utilization, estimated remaining useful life, and net proceeds received upon future sale/disposition. The assumptions are consistent with the Company's internal forecasts for future years. Although we believe the assumptions used in our analysis are reasonable and appropriate and the probability-weighted average of expected future undiscounted net cash flows exceed the net book value for each of the domestic and international FlexRig4 asset groups as of June 30, 2019, different assumptions and estimates could materially impact the analysis and our resulting conclusion. 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, were sold to a third party to be recycled. Certain components of these rigs, with an $8.5 million net book value, that were not subject to the sale agreement were 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. Depreciation 67 Depreciation in the Consolidated Statements of Operations of $556.9 million, $578.4 million and $584.4 million includes abandonments of $11.4 million, $27.7 million and $42.6 million for fiscal years 2019, 2018 and 2017, respectively. During fiscal year 2019, we have shortened the estimated useful lives of certain components of rigs planned for conversion, resulting in an increase in depreciation expense during fiscal year 2019 of approximately $4.7 million. This will decrease the depreciation expense for fiscal years 2020, 2021, 2022, 2023, and 2024 by $0.8 million, $0.8 million, $0.6 million, $0.3 million, and $0.3 million, respectively, and thereafter by $0.5 million. Gain on Sale of Assets We had a gain on sales of assets of $39.7 million, $22.7 million and $20.6 million in fiscal years 2019, 2018 and 2017, respectively. These gains were primarily related to customer reimbursement for the replacement value of drill pipe damaged or lost in drilling operations. NOTE 6 GOODWILL AND INTANGIBLE ASSETS Goodwill All of our goodwill is within our H&P Technologies reportable segment. The following is a summary of changes in goodwill (in thousands): September 30, 2017 Additions Impairment September 30, 2018 Additions September 30, 2019 Intangible Assets $ $ 51,705 17,791 (4,719) 64,777 18,009 82,786 Intangible assets arising from business acquisitions consisted of the following: September 30, 2019 September 30, 2018 Weighted Average Estimated Useful Lives Gross Carrying Amount Accumulated Amortization Net Gross Carrying Amount Accumulated Amortization Net (in thousands) Finite-lived intangible asset: Developed technology 15 years $ 89,096 $ 10,256 $ 78,840 $ 70,000 $ 5,589 $ 64,411 Trade name Customer relationships 20 years 5 years 5,865 4,000 522 1,467 5,343 2,533 5,700 4,000 237 667 5,463 3,333 $ 98,961 $ 12,245 $ 86,716 $ 79,700 $ 6,493 $ 73,207 Amortization expense in the Consolidated Statements of Operations was $5.8 million, $5.4 million and $1.1 million for fiscal years 2019, 2018 and 2017, respectively, and is estimated to be $7.0 million for each of the next three succeeding fiscal years, approximately $6.4 million for fiscal year 2023 and approximately $6.2 million for fiscal year 2024. 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 year 2018 did not result in an impairment charge. Beginning October 1, 2018, the goodwill associated with our technology reporting units were combined into one reporting unit, H&P Technologies. Our goodwill impairment analysis performed in the fourth quarter fiscal year of 2019 indicated that the fair value of the H&P Technologies reporting unit exceeded its carrying value. Therefore, no goodwill impairment was recognized. 68 NOTE 7 DEBT We had the following unsecured long-term debt outstanding at rates and maturities shown in the following table: September 30, 2019 September 30, 2018 Unamortized Discount and Debt Issuance Cost Face Amount Book Value Face Amount Unamortized Discount and Debt Issuance Cost Book Value $ 487,148 $ (7,792) $ 479,356 $ 500,000 $ (6,032) $ 493,968 487,148 — (7,792) 479,356 500,000 (6,032) 493,968 — — — — — $ 487,148 $ (7,792) $ 479,356 $ 500,000 $ (6,032) $ 493,968 (in thousands) Unsecured senior notes: Due March 19, 2025 Less long-term debt due within one year Long-term debt Senior Notes HPIDC 2025 Notes On March 19, 2015, we issued $500 million of 4.65 percent unsecured senior notes due 2025, which were redeemed in full on September 27, 2019 as described under "––Private Exchange Offer, Consent Solicitation and Redemption." Interest on such notes was payable semi-annually on March 15 and September 15. The debt discount was being amortized to interest expense using the effective interest method. The debt issuance costs were being amortized straight-line over the stated life of the obligation, which approximated the effective interest method. Private Exchange Offer, Consent Solicitation and Redemption On November 19, 2018, we commenced an offer to exchange (the “Exchange Offer”) any and all outstanding HPIDC 2025 Notes for (i) up to $500 million aggregate principal amount of new 4.65 percent unsecured senior notes due 2025 of the Company (the “Company 2025 Notes”), with registration rights, and (ii) cash. Concurrently with the Exchange Offer, we solicited consents (the “Consent Solicitation”) to adopt certain proposed amendments (the “Proposed Amendments”) to the indenture governing the HPIDC 2025 Notes, which include eliminating substantially all of the restrictive covenants in such indenture and limiting the reporting covenant under such indenture. On December 20, 2018, we settled the Exchange Offer, pursuant to which we issued approximately $487.1 million in aggregate principal amount of Company 2025 Notes. Interest on the Company 2025 Notes is payable semi-annually on March 15 and September 15 of each year, commencing March 15, 2019. The debt issuance costs are being amortized straight-line over the stated life of the obligation, which approximates the effective interest method. The terms of the Company 2025 Notes are governed by an indenture, dated December 20, 2018, as amended and supplemented by the first supplemental indenture thereto, dated December 20, 2018, each among the Company, HPIDC and Wells Fargo Bank, National Association, as trustee. Following the consummation of the Exchange Offer, HPIDC had outstanding approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes. In connection with the Consent Solicitation, the requisite number of consents to adopt the Proposed Amendments was received. Accordingly, on December 20, 2018, HPIDC, the Company and Wells Fargo Bank, National Association, as trustee, entered into a supplemental indenture to the indenture governing the HPIDC 2025 Notes to adopt the Proposed Amendments. On September 27, 2019, we redeemed the remaining approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes for approximately $14.6 million, including accrued interest and a prepayment premium. Simultaneously with the redemption of the HPIDC 2025 Notes, HPIDC was released as a guarantor under the Company 2025 Notes and the 2018 Credit Facility (as defined herein). As a result of such release, H&P is the only obligor under the Company 2025 Notes and the 2018 Credit Facility. Registered Exchange Offer On February 15, 2019, we commenced a registered exchange offer (the “Registered Exchange Offer”) to exchange the Company 2025 Notes for new SEC-registered notes that are substantially identical to the terms of the Company 2025 Notes, except that the offer and issuance of the new notes have been registered under the Securities Act of 1933, as amended (the “Securities Act”), and certain transfer restrictions, registration rights and additional interest provisions relating to the Company 2025 Notes do not apply to the new notes. The Registered Exchange Offer expired on March 18, 2019, and approximately 99.99% of the Company 2025 Notes were exchanged. The Company 2025 Notes that were not exchanged pursuant to the Registered Exchange Offer have not been registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements or a transaction not subject to the registration requirements of the Securities Act or any state securities law. 69 Credit Facilities On November 13, 2018, we entered into a credit agreement by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, providing for an unsecured revolving credit facility (the “2018 Credit Facility”), which was originally set to mature on November 13, 2023. Pursuant to the 2018 Credit Facility Amendment entered into on November 13, 2018, among other things, the maturity date was extended by one year to November 13, 2024. 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 was originally guaranteed by HPIDC, but such guarantee was released simultaneously with the redemption of the HPIDC 2025 Notes and the release of HPIDC as a guarantor under the Company 2025 Notes. 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 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, as determined by Moody’s and Standard & Poor’s (“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 the Company on September 30, 2019, the spread over LIBOR would have been 1.125 percent had borrowings been outstanding under the facility and commitment fees are 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 or equal to 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 September 30, 2019, there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. In connection with entering into the 2018 Credit Facility, we terminated our $300.0 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 Bank, National Association, as administrative agent, and the lenders party thereto. At September 30, 2019, we had two outstanding letters of credit with banks under bilateral line of credit agreements, in the amounts of $25.5 million and $2.1 million, respectively. Subsequent to our fiscal year end, in October 2019, the balance of the $25.5 million outstanding letter of credit was reduced to $24.8 million. At September 30, 2019, we also had a $20.0 million unsecured standalone line of credit facility, for the purpose of obtaining the issuance of bid and performance bonds, as well as other miscellaneous international needs. Of the $20.0 million, $11.5 million of letters of credit was outstanding as of September 30, 2019. 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, 2019, we were in compliance with all debt covenants. At September 30, 2019, aggregate maturities of long-term debt are as follows (in thousands): Year ending September 30, 2020 2021 2022 2023 2024 Thereafter $ $ — — — — — 487,148 487,148 70 NOTE 8 INCOME TAXES Income Tax Provision and Rate The components of the provision (benefit) for income taxes are as follows: (in thousands) Current: Federal Foreign State Deferred: Federal Foreign State Total benefit Year Ended September 30, 2018 2017 2019 $ $ $ 21,745 732 3,365 25,842 (35,809) 2,804 (11,549) (44,554) (18,712) $ $ 757 6,492 2,340 9,589 (508,256) 7,415 14,083 (486,758) (477,169) $ (36,260) 4,108 (472) (32,624) (14,953) (7,827) (1,331) (24,111) (56,735) The amounts of domestic and foreign income (loss) before income taxes are as follows: (in thousands) Domestic Foreign Year Ended September 30, 2019 2018 2017 $ $ (45,118) $ 27,436 $ (173,157) (6,104) (11,595) (11,441) (51,222) $ 15,841 $ (184,598) Effective income tax rates as compared to the U.S. Federal income tax rate are as follows: Year Ended September 30, 2019 2018 2017 24.5 % 35.0% 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) Excess officer's compensation (1) Contingent consideration adjustment (1) Other (1) Effective income tax rate 21.0% (0.6) 17.2 — — 0.9 (2.5) 2.7 (1.9) 4.5 (4.8) 87.8 68.8 — (3,169.4) (43.4) 8.2 (5.3) 1.7 10.7 4.1 36.5% (3,012.3)% 1.8 0.6 (2.1) — (2.9) — — — — (1.7) 30.7% (1) For fiscal year 2017, “Other” reflects adjustments for non-deductible meals and entertainment, equity compensation, excess officer’s compensation and contingent consideration. Effective tax rates differ from the U.S. federal statutory rate of 21.0 percent due to state and foreign income taxes and the tax effect of non-deductible expenditures (primarily related to certain meals and entertainment, excess officer’s compensation limited pursuant to Section 162(m) of the IRC, and adjustments to the contingent consideration related to our acquisition of MOTIVE Drilling Technologies, Inc. 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. 71 The components of our net deferred tax liabilities are as follows: (in thousands) Deferred tax liabilities: Property, plant and equipment Marketable securities Other Total deferred tax liabilities Deferred tax assets: Marketable securities 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 September 30, 2019 2018 $ 867,909 $ 904,734 — 15,681 883,590 771 7,324 14,294 41,126 54,511 2,531 120,557 (43,578) 76,979 10,464 12,787 927,985 — 3,477 13,100 55,889 45,708 4,888 123,062 (48,213) 74,849 $ 806,611 $ 853,136 The change in our net deferred tax assets and liabilities is impacted by foreign currency remeasurement. As of September 30, 2019, we had federal, state and foreign tax net operating loss carryforwards of $8.9 million, $14.5 million and $62.0 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 2020 through 2039. The valuation allowance is primarily attributable to foreign and certain state net operating loss carryforwards of $16.9 million and $0.5 million, respectively, and foreign tax credit carryforwards of $20.1 million, equity compensation of $4.1 million, and foreign minimum tax credit carryforwards of $1.9 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, 2019, and 2018, we had accrued interest and penalties of $2.1 million and $2.2 million, respectively. A reconciliation of the change in our gross unrecognized tax benefits for the fiscal years ended September 30, 2019 and 2018 is as follows: (in thousands) Unrecognized tax benefits at October 1, Gross increases - 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, 2019 2018 $ 14,905 $ — (28) 1,067 (185) 4,773 3 (280) 10,537 (128) $ 15,759 $ 14,905 As of September 30, 2019, and 2018, our liability for unrecognized tax benefits includes $15.3 million and $14.3 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. 72 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 2015 through 2018, with exception of certain state jurisdictions currently under audit. The tax years remaining open to examination by foreign jurisdictions include 2003 through 2019. 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. During fiscal 2019, we purchased one million common shares at an aggregate cost of $42.8 million, which are held as treasury shares. We had no purchases of common shares during the fiscal years ended September 30, 2018 and 2017. Accumulated Other Comprehensive Income (Loss) Components of accumulated other comprehensive income (loss) were as follows: (in thousands) Pre-tax amounts: Unrealized appreciation on securities (1) Unrealized actuarial loss After-tax amounts: Unrealized appreciation on securities (1) Unrealized actuarial loss September 30, 2019 2018 2017 $ $ $ $ — $ 44,023 $ (37,084) (21,693) (37,084) $ 22,330 $ — $ 29,071 $ (28,635) (12,521) (28,635) $ 16,550 $ 31,700 (28,873) 2,827 20,070 (17,770) 2,300 (1) As disclosed in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties, we adopted ASU No. 2016-01 on October 1, 2018. The standard requires that changes in the fair value of our equity investments must be recognized in net income. 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, 2019: (in thousands) Balance at September 30, 2018 Adoption of ASU No. 2016-01 (1) Adoption of ASU No. 2018-02 (2) Activity during the period Amounts reclassified from accumulated other comprehensive loss Net current-period other comprehensive loss Balance at September 30, 2019 Unrealized Appreciation on Equity Securities Defined Benefit Pension Plan Total $ $ 29,071 $ (12,521) $ (29,071) — — — — — (4,239) (16,760) (11,875) (11,875) — $ (28,635) $ 16,550 (29,071) (4,239) (16,760) (11,875) (11,875) (28,635) (1) As disclosed in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties, we adopted ASU No. 2016-01 on October 1, 2018. The transition provisions enforced upon adoption require any unrealized gains or losses as of October 1, 2018 to be recognized in the beginning balance of equity. (2) As disclosed in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties, we adopted ASU No. 2018-02 as of June 30, 2019. The standard permits the reclassification of certain income tax effects of the Tax Reform Act from Accumulated Other Comprehensive Income (Loss) to Retained Earnings. NOTE 10 REVENUE FROM CONTRACTS WITH CUSTOMERS Impact of Adoption Effective October 1, 2018, we adopted ASU No. 2014-09, "Revenue from Contracts with Customers" and ASC 340-40, “Contracts with Customers.” ASC 606 introduced a five step approach to revenue recognition and ASC 340-40 introduced detailed rules for contract revenue related costs. Details of the new requirements as well as the impact on our Consolidated Financial Statements are described below. 73 We have applied ASC 606 in accordance with the modified retrospective transitional approach recognizing the cumulative effect of initially applying the revenue standard as an adjustment to the opening balance of retained earnings during this period (October 1, 2018). Comparative prior year periods were not adjusted. In applying the modified retrospective approach, we elected practical expedients for (a) completed contracts as described in ASC 606-10-65-c2, and (b) contract modifications as described in ASC 606-10-65-1-f(4), allowing the application of the revenue standard only to contracts that were not completed as of the date of initial application and to reflect the aggregate effect of all modifications that occur before the adoption date in accordance with the new standard when: (i) identifying the satisfied and unsatisfied performance obligations, (ii) determining the transaction price, and (iii) allocating the transaction price to the satisfied and unsatisfied performance obligations. We believe that the impact on the opening balance of retained earnings during the period (October 1, 2018) would not have been significantly different had we not elected to use the practical expedients. Apart from providing more extensive disclosures for our revenue transactions, the application of ASC 606 has not had a significant impact on our financial position and/or financial performance. Contract Drilling Services Revenue Substantially all of our drilling services are performed on a “daywork” contract basis, under which we charge 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. These contract drilling services represent a series of distinct daily services that are substantially the same, with the same pattern of transfer to the customer. Because our customers benefit equally throughout the service period and our efforts in providing contract drilling services are incurred relatively evenly over the period of performance, revenue is recognized over time using a time-based input measure as we provide services to the customer. Contracts generally contain renewal or extension provisions exercisable at the option of the customer at prices mutually agreeable to us and the customer. 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. During the year ended September 30, 2019 and 2018, early termination revenue was approximately $11.3 million and $17.1 million, respectively. We also act as a principal for certain reimbursable services and auxiliary equipment provided by us to our clients, for which we incur costs and earn revenues. Many of these costs are variable, or dependent upon the activity that is performed each day under the related contract. Accordingly, reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs during the period to which they relate within the series of distinct time increments. All of our revenues are recognized net of sales taxes, when applicable. With most drilling contracts, we also receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenues associated with the mobilization and demobilization of our drilling rigs to and from the client’s drill site do not relate to a distinct good or service. These revenues are deferred and recognized ratably over the related contract term that drilling services are provided. Demobilization fees expected to be received upon contract completion are estimated at contract inception and recognized on a straight-line basis over the contract term. The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced or no payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Any change in the expected amount of demobilization revenue is accounted for with the net cumulative impact of the change in estimate recognized in the period during which the revenue estimate is revised. Contract Costs Mobilization costs include certain direct costs incurred for mobilization of contracted rigs. These costs relate directly to a contract, enhance resources that will be used in satisfying the future performance obligations and are expected to be recovered. These costs are capitalized when incurred and recorded as current or noncurrent contract fulfillment cost assets (depending on the length of the initial contract term), and are amortized on a systematic basis consistent with the pattern of the transfer of the goods or services to which the asset relates which typically includes the initial term of the related drilling contract or a period longer than the initial contract term if management anticipates a customer will renew or extend a contract, which we expect to benefit from the cost of mobilizing the rig. Abnormal mobilization costs are fulfillment costs that are incurred from excessive resources, wasted or spoiled materials, and unproductive labor costs that are not otherwise anticipated in the contract price and are expensed as incurred. As of September 30, 2019, we had capitalized fulfillment costs of $13.9 million. If capital modification costs are incurred for rig modifications or if upgrades are required for a contract, these costs are considered to be capital improvements. These costs are capitalized as property, plant and equipment and depreciated over the estimated useful life of the improvement. 74 Remaining Performance Obligations The total aggregate transaction price allocated to the unsatisfied performance obligations, commonly referred to as backlog, as of September 30, 2019 was approximately $1.2 billion, of which $0.9 billion is expected to be recognized during fiscal year 2020, and approximately $0.3 billion in fiscal year 2021 and thereafter. These amounts do not include anticipated contract renewals. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. Our contracts are subject to cancellation or modification at the election of the customer; however, due to the level of capital deployed by our customers on underlying projects, we have not been materially adversely affected by contract cancellations or modifications in the past. We do not have material long-term contracts related to our H&P Technologies segment. Contract Assets and Liabilities Amounts owed from our customers under our revenue contracts are typically billed on a monthly basis as the service is being provided and are due within 30 days of billing. Such amounts are classified as accounts receivable on our Consolidated Balance Sheets. Under certain of our contracts, we recognize revenues in excess of billings, referred to as contract assets, within prepaid expenses and other current assets within our Consolidated Balance Sheets. Under certain of our contracts, we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized, referred to as deferred revenue or contract liabilities, within accrued liabilities and other noncurrent liabilities in our Consolidated Balance Sheets. Contract balances are presented at the net amount at a contract level. The following table summarizes the balances of our contract assets and liabilities at the dates indicated: (in thousands) Contract assets (in thousands) Contract liabilities balance at October 1, 2018 Payment received/accrued and deferred Revenue recognized during the period September 30, 2019 NOTE 11 STOCK-BASED COMPENSATION September 30, 2019 October 1, 2018 $ 2,151 $ 2,600 September 30, 2019 $ $ 38,472 30,863 (45,981) 23,354 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, restricted stock awards and performance share units 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 under the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan and the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan remain subject to the terms and conditions of those plans. During the fiscal year ended September 30, 2019, there were no new non-qualified stock options granted, as we have, prospectively and for fiscal year 2019, replaced stock options with performance share units as a component of our executives’ long-term equity incentive compensation. We have also eliminated stock options as an element of our director compensation program. The Board has determined to award stock-based compensation to directors solely in the form of restricted stock. During the fiscal year ended September 30, 2019, 474,775 shares of restricted stock awards and 145,153 performance share units were granted under the 2016 Plan. 75 A summary of compensation cost for stock-based payment arrangements recognized in contract drilling services operating expense and selling, general and administrative expense in fiscal years 2019, 2018 and 2017 is as follows: (in thousands) Stock-based compensation expense Stock options Restricted stock Performance share units September 30, 2019 2018 2017 $ $ 3,721 $ 7,913 $ 26,149 4,422 23,774 — 7,439 18,744 — 34,292 $ 31,687 $ 26,183 Of the total stock-based compensation expense, $7.5 million was recorded in contract drilling services operating expense and $26.8 million in selling, general and administrative expense for fiscal year 2019 on our Consolidated Statements of Operations. Stock Options 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. Risk-free interest rate (1) Expected stock volatility (2) Dividend yield (3) Expected term (in years) (4) 2018 2017 2.2% 36.1% 4.7% 6.0 2.0% 38.9% 3.7% 5.5 (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 expected 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 and $20.48 per share for fiscal years 2018 and 2017, respectively. The following summary reflects the stock option activity for our common stock and related information for fiscal years 2019, 2018 and 2017: 2019 Weighted- Average Exercise Price 2018 2017 Weighted- Average Exercise Price Weighted- Average Exercise Price (shares in thousands) Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available to grant Shares 3,499 $ — (217) (44) 3,238 2,482 2,999 $ $ 58.62 — 24.46 62.14 60.86 60.38 Shares $ 3,278 694 (375) (98) 3,499 2,193 5,140 $ $ 56.41 59.03 36.88 70.77 58.62 56.31 Shares $ 3,312 396 (415) (15) 3,278 2,167 5,624 $ $ 51.74 76.61 38.04 68.32 56.41 50.87 76 The following table summarizes information about stock options at September 30, 2019 (shares in thousands): Range of Exercise Prices Shares Weighted-Average Remaining Life Weighted-Average Exercise Price Shares Weighted-Average Exercise Price Outstanding Stock Options Exercisable Stock Options $0.00 to $40.00 $40.00 to $55.00 $55.00 to $70.00 $70.00 to $85.00 209 493 2,032 504 3,238 $ 0.17 2.93 6.09 5.95 38.02 51.85 60.53 80.49 $ 209 468 1,432 373 2,482 38.02 51.78 61.26 80.34 At September 30, 2019, the weighted-average remaining life of exercisable stock options was 4.47 years and the aggregate intrinsic value was $0.4 million with a weighted-average exercise price of $60.38 per share. The number of options vested or expected to vest at September 30, 2019 was 755,761 with an aggregate intrinsic value of zero and a weighted-average exercise price of $62.42 per share. As of September 30, 2019, the unrecognized compensation cost related to the stock options was $3.2 million. That cost is expected to be recognized over a weighted-average period of 2 years. The total intrinsic value of options exercised during fiscal years 2019, 2018 and 2017 was $7.9 million, $9.9 million and $13.1 million, respectively. The grant date fair value of shares vested during fiscal years 2019, 2018 and 2017 was $8.0 million, $8.8 million and $6.7 million, respectively. Restricted Stock Restricted stock awards consist of our common stock and are time-vested over four years. Non-forfeitable dividends are paid on non-vested shares of restricted stock. 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, 2019, there was $34.9 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 2.3 years. A summary of the status of our restricted stock awards as of September 30, 2019, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2019, 2018 and 2017, is as follows: (shares in thousands) Outstanding at October 1, Granted Vested (1) Forfeited 2019 2018 2017 Weighted-Average Grant Date Fair Value per Share Shares Weighted-Average Grant Date Fair Value per Share Shares Weighted-Average Grant Date Fair Value per Share Shares 1,001 $ 475 (371) (20) 63.74 58.45 64.32 60.85 $ 659 626 (258) (26) 70.76 59.53 70.60 66.73 63.74 $ 648 292 (271) (10) 659 $ 64.24 78.69 63.81 68.09 70.76 Outstanding on September 30, 1,085 $ 61.28 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. Performance Share Units We have made awards to certain employees that are subject to market-based performance conditions ("performance share units"). Subject to the terms and conditions set forth in the applicable performance share unit award agreements and the 2016 Plan, grants of performance share units are subject to a vesting period of three years (the “Vesting Period”) that is dependent on the achievement of certain performance goals. Such performance share unit awards consist of two separate components. Performance share units that comprise the first component are subject to a three-year performance cycle. Performance share units that comprise the second component are further divided into three separate tranches, each of which is subject to a separate one-year performance cycle within the full three-year performance cycle. The vesting of the performance share units is generally dependent on (i) the achievement of the Company’s total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Group”) over the applicable performance cycle, and (ii) the continued employment of the recipient of the performance share unit award throughout the Vesting Period. 77 At the end of the Vesting Period, recipients receive dividend equivalents, if any, with respect to the number of vested performance share units. The vesting of units ranges from zero to 200% of the units granted depending on the Company’s TSR relative to the TSR of the Peer Group on the vesting date. The grant date fair value of performance share units was determined through use of the Monte Carlo simulation method. The Monte Carlo simulation method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined Peer Group's stock, risk free rate of return and cross-correlations between the Company and our Peer Group. The valuation model assumes dividends are immediately reinvested. As of September 30, 2019, there was $4.7 million of unrecognized compensation cost related to unvested performance share units. That cost is expected to be recognized over a weighted-average period of 1.9 years. A summary of the status of our performance share units as of the fiscal year ended September 30, 2019 is presented below: Outstanding at October 1, Granted Outstanding on September 30, Shares Weighted- Average Grant Date Fair Value per Share — $ 145 145 $ — 62.66 62.66 The weighted-average fair value calculations for performance share units granted within the fiscal period are based on the following weighted-average assumptions set forth in the table below. Risk-free interest rate (1) Expected stock volatility (2) Expected term (in years) 2019 2.7% 35.9% 3.0 (1) The risk-free interest rate is based on U.S. Treasury securities for the expected term of the performance share units. (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 performance share units. NOTE 12 EARNINGS (LOSSES) PER COMMON SHARE ASC 260, Earnings per Share, requires companies to treat unvested share-based payment awards that have non- forfeitable rights to dividends or dividend equivalents as a separate class of securities in calculating earnings per share. 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. As such, we are required to include these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. 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, nonvested restricted stock and performance share units. Under the two-class method of calculating earnings per share, dividends paid and a portion of undistributed net income, but not losses, are allocated to unvested restricted stock grants that receive dividends, which are considered participating securities. 78 The following table sets forth the computation of basic and diluted earnings per share: (in thousands, except per share amounts) Numerator: Income (loss) from continuing operations Loss from discontinued operations Net income (loss) Adjustment for basic earnings per share Earnings allocated to unvested shareholders Numerator for basic earnings (loss) per share: From continuing operations From discontinued operations Adjustment for diluted earnings (loss) per share: September 30, 2019 2018 2017 $ (32,510) $ 493,010 $ (127,863) (1,146) (33,656) (10,338) 482,672 (349) (128,212) (3,102) (4,346) (1,811) (35,612) (1,146) (36,758) 488,664 (10,338) 478,326 (129,674) (349) (130,023) Effect of reallocating undistributed earnings of unvested shareholders — 7 — Numerator for diluted earnings (loss) per share: From continuing operations From discontinued operations Denominator: (35,612) (1,146) 488,671 (10,338) (129,674) (349) $ (36,758) $ 478,340 $ (130,023) Denominator for basic earnings (loss) per share - weighted-average shares Effect of dilutive shares from stock options, restricted stock and performance share units Denominator for diluted earnings (loss) per share - adjusted weighted-average shares 109,216 — 109,216 108,851 536 109,387 108,500 — 108,500 Basic earnings (loss) per common share: Income (loss) from continuing operations Loss from discontinued operations Net income (loss) Diluted earnings (loss) per common share: Income (loss) from continuing operations Loss from discontinued operations Net income (loss) $ $ $ $ (0.33) $ (0.01) (0.34) $ (0.33) $ (0.01) (0.34) $ 4.49 $ (0.10) 4.39 $ 4.47 $ (0.10) 4.37 $ (1.20) — (1.20) (1.20) — (1.20) We had a net loss for fiscal years 2019 and 2017. 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 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 average shares attributable to outstanding equity awards were excluded from the calculation of diluted earnings per share because their inclusion would have been anti-dilutive: (in thousands, except per share amounts) 2019 2018 2017 Shares excluded from calculation of diluted earnings (loss) per share 3,031 1,559 Weighted-average price per share $ 63.33 $ 68.28 $ 1,008 74.38 79 NOTE 13 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 $15.7 million and $16.2 million at September 30, 2019 and 2018, 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. 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, 2019 and 2018. The following table summarizes our assets measured at fair value presented in our Consolidated Balance Sheet: (in thousands) Recurring fair value measurements: Short-term investments: 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 September 30, 2019 Fair Value Level 1 Level 2 Level 3 $ 6,590 $ — $ 6,590 $ 17,984 28,386 52,960 — 28,386 28,386 347,943 347,943 16,267 31,291 3,737 15,974 31,291 3,737 17,984 — 24,574 — 293 — — Total assets measured at fair value $ 452,198 $ 427,331 $ 24,867 $ — — — — — — — — — Liabilities: Contingent earnout liability $ 18,373 $ — $ — $ 18,373 At September 30, 2019, 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, 2019, 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. 80 Our financial instruments measured using Level 3 unobservable inputs consist of potential earnout payments associated with the acquisition of DrillScan and AJC in fiscal year 2019 and MOTIVE Drilling Technologies, Inc. in fiscal year 2017. As of September 30, 2019, the fair value of the MOTIVE contingent consideration is zero. The fair value of the potential earnout payments were calculated using either a Monte Carlo simulation, which evaluates numerous potential earnings and pay out scenarios, or a probability analysis. The following table presents a reconciliation of changes in the fair value of our financial assets and liabilities classified as Level 3 fair value measurements in the fair value hierarchy for the indicated periods: (in thousands) Net liabilities at beginning of period Additions Total gains or losses: Included in earnings Settlements (1) Net liabilities at end of period 2019 2018 $ 11,160 $ 14,879 18,373 — (11,160) — $ 18,373 $ 6,906 (10,625) 11,160 (1) Settlements represent earnout payments that have been earned or paid during the period. The following table provides quantitative information (in thousands) about our Level 3 unobservable inputs at September 30, 2019: Fair Value Valuation Technique Unobservable Input Unobservable Input Range Weighted Average (1) $6,000 Monte Carlo simulation Discount rate $12,373 Probability Analysis Revenue Volatility Risk free rate Discount rate Payment amounts Probabilities 2.8% 24.4% 1.9% 3.0% $3,000 - $7,000 $ 40% - 54% 4,800 47% (1) The weighted average of the payment amounts and the probabilities (Level 3 unobservable inputs), associated with the contingent consideration valued using probability analysis, were weighted by the relative undiscounted fair value of payment amounts and of probability payment amounts, respectively. The above significant unobservable inputs are subject to change based on changes in economic and market conditions. The use of significant unobservable inputs creates uncertainty in the measurement of fair value as of the reporting date. The significant unobservable inputs used in the fair value measurement of the contingent consideration using Monte Carlo simulation are (i) discount rate, (ii) revenue volatility and (iii) risk-free rate. Significant increases or decreases in the discount rate and risk-free rate in isolation would result in a significantly lower or higher fair value measurement. Significant changes in revenue volatility in isolation would result in a significantly lower or higher fair value measurement. The significant unobservable inputs used in the fair value measurement of the contingent consideration using probability analysis are (i) discount rate, (ii) payment amounts and (iii) probabilities. Significant increases or decreases in the discount rate in isolation would result in a significantly lower or higher fair value measurement. On the contrary, significant increases or decreases in the payment amounts or probabilities in isolation would result in a significantly higher or lower fair value measurement. It is not possible for us to predict the effect of future economic or market conditions on our estimated fair values. The following information presents the supplemental fair value information about long-term fixed-rate debt at September 30, 2019 and 2018. (in millions) Carrying value of long-term fixed-rate debt Fair value of long-term fixed-rate debt September 30, 2019 2018 $ $ 479.4 526.4 $ $ 494.0 509.3 The fair value for the $487.1 million fixed-rate debt was based on broker quotes at September 30, 2019. The notes are classified within Level 2 of the fair value hierarchy as they are not actively traded in markets. We adopted ASU No. 2016-01 on October 1, 2018, and as a result, we recognize our marketable equity securities that have readily determinable fair values at fair value, with changes in such values reflected in net income. Previously, we recognized changes in fair value of equity securities in other comprehensive income in the Consolidated Statements of Comprehensive Income (Loss). There is no longer a requirement to consider whether the decline in fair value is other-than-temporary. 81 The estimated fair value of our investments, reflected on our Consolidated Balance Sheets as Investments, is based on Level 1 inputs. In September 2019, we sold our remaining 1.6 million shares in Valaris, previously known as Ensco Rowan plc, for total proceeds of approximately $12.0 million. NOTE 14 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, 2019 and a statement of the funded status as of September 30, 2019 and 2018: (in thousands) 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 2019 2018 119,845 $ 106,205 106,205 $ 109,976 4,389 16,914 (7,663) 4,077 (2,143) (5,705) 119,845 $ 106,205 94,897 $ 3,865 43 (7,663) 91,142 $ 92,816 7,754 32 (5,705) 94,897 (28,703) $ (11,308) $ $ $ $ $ $ The amounts recognized in the Consolidated Balance Sheets at September 30, 2019 and 2018 are as follows (in thousands): Accrued liabilities Noncurrent liabilities-other Net amount recognized $ $ (50) $ (28,653) (28,703) $ (58) (11,250) (11,308) The amounts recognized in Accumulated Other Comprehensive Income (Loss) at September 30, 2019 and 2018, and not yet reflected in net periodic benefit cost, are as follows (in thousands): Net actuarial loss $ (37,084) $ (21,693) 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 $2.7 million. The weighted average assumptions used for the pension calculations were as follows: Discount rate for net periodic benefit costs Discount rate for year-end obligations Expected return on plan assets September 30, 2019 2018 2017 4.27% 3.16% 5.60% 3.79% 4.27% 6.06% 3.64% 3.79% 6.17% The mortality table issued by the Society of Actuaries in October 2018 was used for the September 30, 2019 pension calculation. We did not make any contributions to the Pension Plan in fiscal year 2019. In fiscal year 2020, we do not expect minimum contributions required by law to be needed. However, we may make contributions in fiscal year 2020 if needed to fund unexpected distributions in lieu of liquidating pension assets. 82 Components of the net periodic pension expense (benefit) were as follows: (in thousands) Interest cost Expected return on plan assets Recognized net actuarial loss Settlement Net pension expense Year Ended September 30, 2019 2018 2017 $ $ 4,389 $ 4,077 $ (5,523) 1,229 1,953 (5,555) 1,926 913 2,048 $ 1,361 $ 4,053 (5,130) 2,891 1,640 3,454 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). 2020 2021 2022 2023 2024 2025 – 2029 Total $ 7,958 $ 6,164 $ 6,698 $ 6,745 $ 7,121 $ 32,313 $ 66,999 Year Ended September 30, 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. The target allocation for 2020 and the asset allocation for the Pension Plan at the end of fiscal years 2019 and 2018, by asset category, follows: Asset Category U.S. equities International equities Fixed income Total Target Allocation September 30, 2020 2019 2018 45% 20 35 100% 47% 16 37 100% 52% 15 33 100% 83 Plan Assets The fair value of Pension Plan assets at September 30, 2019 and 2018, summarized by level within the fair value hierarchy described in Note 13—Fair Value Measurement of Financial Instruments, are as follows: (in thousands) Short-term investments Mutual funds: Domestic stock funds Bond funds Balanced funds International stock funds Total mutual funds Domestic common stock Oil and gas properties Total (in thousands) Short-term investments Mutual funds: Domestic stock funds Bond funds Balanced funds International stock funds Total mutual funds Domestic common stock Oil and gas properties Total September 30, 2019 Total Level 1 Level 2 Level 3 $ 3,072 $ 3,072 $ — $ 17,555 18,034 17,878 14,181 67,648 20,261 161 17,555 18,034 17,878 14,181 67,648 17,748 — — — — — — 2,513 — $ 91,142 $ 88,468 $ 2,513 $ — — — — — — — 161 161 September 30, 2018 Total Level 1 Level 2 Level 3 $ 2,745 $ 2,745 $ — $ 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 — $ 94,897 $ 92,320 $ 2,461 $ — — — — — — — 116 116 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 domestic 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. 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, 2019 and 2018: (in thousands) Balance, beginning of year Unrealized gains (losses) relating to property still held at the reporting date Balance, end of year Defined Contribution Plan Oil and Gas Properties Year Ended September 30, 2019 2018 $ $ 116 $ 45 161 $ 97 19 116 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 $30.5 million, $26.6 million and $16.6 million in fiscal years 2019, 2018 and 2017, respectively. 84 NOTE 15 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in our reserve for bad debt for fiscal years 2019, 2018 and 2017: (in thousands) Reserve for bad debt: Balance at October 1, Provision for bad debt (Write-off) recovery of bad debt Balance at September 30, 2019 2018 2017 $ $ 6,217 $ 5,721 $ 2,321 1,389 2,193 (1,697) 9,927 $ 6,217 $ 2,696 2,016 1,009 5,721 Accounts receivable, prepaid expenses and other current assets, accrued liabilities and long-term liabilities at September 30, 2019 and 2018 consist of the following: (in thousands) Accounts receivable, net of reserve: Trade receivables Income tax receivable Total accounts receivable, net of reserve 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 Accrued demobilization 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 revenue Accrued income taxes Escrow Litigation and claims Contingent earnout liability Other Total accrued liabilities Noncurrent liabilities — Other: Pension and other non-qualified retirement plans Self-insurance liabilities Contingent earnout liability Deferred revenue Uncertain tax positions including interest and penalties Other Total noncurrent liabilities — other 85 $ $ $ $ $ $ $ September 30, 2019 2018 461,774 $ 530,859 33,828 34,343 495,602 $ 565,202 31,291 $ 39,830 10,571 5,556 5,209 9,113 — 2,151 5,037 68,928 $ 34,992 $ 79,465 50,566 37,117 25,426 14,737 19,277 1,388 9,990 5,535 8,599 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 — 8,920 287,092 $ 244,504 51,768 $ 37,118 12,838 9,471 2,544 2,007 35,051 39,380 11,160 2,738 2,870 2,407 $ 115,746 $ 93,606 NOTE 16 COMMITMENTS AND CONTINGENCIES Purchase Commitments Equipment, parts and supplies are ordered in advance to promote efficient construction and capital improvement progress. At September 30, 2019, we had purchase commitments for equipment, parts and supplies of approximately $13.7 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 off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements. Lease Obligations At September 30, 2019, we were leasing our corporate office headquarters near downtown Tulsa, Oklahoma. We also lease other office space and equipment for use in operations. Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of a year at September 30, 2019 (in thousands) are as follows: Fiscal Year 2020 2021 2022 2023 2024 Thereafter Total Amount 27,396 13,969 11,343 10,556 10,124 12,373 85,761 $ $ Total rent expense was $15.5 million, $13.7 million and $14.0 million for fiscal years 2019, 2018 and 2017, 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 March 12, 2018. The agreement will expire on January 31, 2025; however, we have two three-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 or loss contingency. We account for gain contingencies in accordance with the provisions of ASC 450, Contingencies, and, therefore, we do not record gain contingencies or recognize income until realized. The property and equipment of our Venezuelan subsidiary was seized by the Venezuelan government on June 30, 2010. HPIDC, our wholly-owned subsidiary and the parent company of our Venezuelan subsidiary, has a lawsuit pending in the United States District Court for the District of Columbia against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. and PDVSA Petroleo, S.A., seeking damages for the taking of their Venezuelan drilling business in violation of international law. 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, 2019, 2018 and 2017. In January 2018, an employee of HPIDC suffered personal injury and subsequently brought a lawsuit against the operator and H&P. Pursuant to the terms of the drilling contract between HPIDC and the operator, HPIDC indemnified the operator in the lawsuit, subject to certain limitations. H&P has settled this matter on behalf of itself and the operator with $21.0 million of the settlement amount to be paid by the Company. The settlement was paid out during the year ended September 30, 2019. While we believe we had meritorious defenses to the matter, we determined that settlement was a reasonable alternative to the uncertainty and expense associated with a jury trial. 86 In October 2017, an employee of HPIDC suffered personal injury and subsequently brought a lawsuit against the operator. Pursuant to the terms of the drilling contract between HPIDC and the operator, HPIDC indemnified the operator in the lawsuit, subject to certain limitations. Settlement discussions related to this lawsuit remain ongoing. As of September 30, 2019, we have accrued $9.5 million for this lawsuit. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact on our financial condition, cash flows, or results of operations. NOTE 17 BUSINESS SEGMENTS AND GEOGRAPHIC INFORMATION Description of the Business We are a global contract drilling services 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 services 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. Effective October 1, 2018, and during the fourth quarter of fiscal year 2019, we implemented organizational changes, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. Effective October 1, 2018, technology reporting units previously reported in “Other” within our segment disclosures are now managed and presented within the new H&P Technologies reportable segment. As a result, beginning with the reporting of first quarter of fiscal year 2019, our operations are organized into the following reportable business segments: U.S. Land, Offshore, International Land and H&P Technologies. Additionally, during the fourth quarter of fiscal year 2019, we migrated our FlexApp offerings into our H&P Technologies segment. The activity of our FlexApps was previously included in our U.S. Land segment. Our real estate operations and our incubator program for new research and development projects are included in "Other". All segment disclosures have been restated, as practicable, for these segment changes. Consolidated revenues and expenses reflect the elimination of intercompany transactions. At September 30, 2019, our contract drilling services business includes the following reportable operating segments: • U.S. Land • Offshore • International Land • H&P Technologies 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” primarily consist of 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 amortization • Allocated general and administrative costs • Asset impairment charges but excludes corporate costs for other depreciation, income from asset sales, other corporate income and expense, and corporate assets. 87 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. (in thousands) External Sales Intersegment Total Sales U.S. Land Offshore International Land H&P Technologies Other Eliminations Total $ 2,366,201 $ 147,635 $ 211,731 $ 59,990 $ 12,933 $ — $2,798,490 September 30, 2019 — — — 2,366,201 147,635 211,731 — — 59,990 12,933 Segment Operating Income (Loss) Depreciation and Amortization Total Assets 93,088 496,770 19,594 10,010 5,099,583 102,442 5,366 35,466 217,094 (12,190) 7,696 3,375 1,523 184,558 32,532 — — — 2,798,490 — — 109,233 551,465 — 5,636,209 (in thousands) External Sales Intersegment Total Sales September 30, 2018 U.S. Land (2) Offshore International Land H&P Technologies (1) (2) Other (1) Eliminations Total $ 2,063,362 $ 142,500 $ 238,356 $ 30,239 $ 12,811 — 2,487,268 — — — — — — $ 2,063,362 $ 142,500 $ 238,356 $ 30,239 $ 12,811 — 2,487,268 Segment Operating Income (Loss) Depreciation and Amortization Total Assets 148,251 504,805 26,124 10,392 5,007,548 105,439 (683) 46,826 362,033 (39,554) 7,153 5,883 1,486 — — 140,021 570,662 151,787 29,525 — 5,656,332 (1) Prior period information has been restated to reflect the change in operating segments structure. (2) Prior period information has been restated to reflect the transfer of FlexApp revenue and the related costs from U.S. Land to H&P Technologies. Certain FlexApp revenue not separately priced in drilling contracts, and recorded in the U.S. Land segment, was impracticable to retrospectively quantify, and as such was not restated. (in thousands) External Sales Intersegment Total Sales September 30, 2017 U.S. Land (2) Offshore International Land H&P Technologies (1) (2) Other (1) Eliminations Total $ 1,437,427 $ 136,263 $ 212,972 $ 5,815 $ 12,264 — — — — — $ 1,437,427 $ 136,263 $ 212,972 $ 5,815 $ 12,264 — 1,804,741 — — — 1,804,741 Segment Operating Income (Loss) Depreciation and Amortization Total Assets (97,231) 499,272 4,962,808 24,201 11,764 99,533 (7,224) 53,622 413,392 (13,356) 3,915 6,065 1,424 — — (87,545) 569,997 110,468 26,883 — 5,613,084 (1) Prior period information has been restated to reflect the change in operating segments structure. (2) Prior period information has been restated to reflect the transfer of FlexApp revenues and the related costs from U.S. Land to H&P Technologies. Certain FlexApp revenue not separately priced in a drilling contract, and recorded in the U.S. Land segment, was impracticable to retrospectively quantify, and as such was not restated. 88 The following table reconciles segment operating income (loss) to income from continuing operations before income taxes as reported on the Consolidated Statements of Operations: (in thousands) Segment operating income (loss) Gain on sale of assets Corporate depreciation Corporate selling, general and administrative costs Operating income (loss) from continuing operations Other income (expense) Interest and dividend income Interest expense Gain (loss) on investment securities Other Total unallocated amounts Year Ended September 30, 2019 2018 2017 As adjusted, Note 2 109,233 39,691 140,021 22,660 (11,338) (13,140) (117,004) (116,577) (87,545) 20,627 (15,546) (86,623) 20,582 32,964 (169,087) 9,468 (25,188) (54,488) (1,596) (71,804) 8,017 (24,265) 1 (876) (17,123) 5,915 (19,747) — (1,679) (15,511) Income (loss) from continuing operations before income taxes $ (51,222) $ 15,841 $ (184,598) The following table reconciles segment total assets to total assets as reported on the Consolidated Balance Sheets: (in thousands) Segment assets Corporate assets Total consolidated assets Year Ended September 30, 2019 2018 $ 5,636,209 $ 5,656,332 203,306 558,535 $ 5,839,515 $ 6,214,867 The following table presents revenues from external customers and long-lived assets by country based on the location of service provided: (in thousands) Operating revenues United States Argentina Colombia Ecuador Other Foreign Total Property, plant and equipment, net United States Argentina Colombia Ecuador Other Foreign Total Year Ended September 30, 2019 2018 2017 $ 2,585,008 $ 2,247,400 $ 1,591,769 165,718 29,757 — 18,007 190,038 38,793 — 11,037 157,257 37,554 6 18,155 $ 2,798,490 $ 2,487,268 $ 1,804,741 $ 4,269,405 $ 4,591,913 $ 4,686,235 132,321 61,757 12 38,589 133,617 155,978 74,042 10,781 47,029 81,798 22,298 54,742 $ 4,502,084 $ 4,857,382 $ 5,001,051 89 NOTE 18 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) Fiscal Year 2019 Quarters Ended Operating revenues Operating income (loss) Income (loss) from continuing operations Net income (loss) Basic earnings per common share: Income (loss) from continuing operations Net income (loss) Diluted earnings per common share: Income (loss) from continuing operations Net income (loss) $ 740,598 $ 720,868 $ 687,974 $ 649,050 $ 2,798,490 54,289 8,364 18,959 0.07 0.17 0.07 0.17 95,146 71,857 60,891 0.65 0.55 0.65 0.55 (167,874) (154,621) (154,683) (1.42) (1.42) (1.42) (1.42) 39,021 41,890 41,177 0.38 0.37 0.38 0.37 20,582 (32,510) (33,656) (0.33) (0.34) (0.33) (0.34) (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 2019, net income includes an after-tax gain from the sale of assets of approximately $4.2 million, or $0.04 per share on a diluted basis. In the second quarter of fiscal year 2019, net income includes an after-tax gain from the sale of assets of $8.9 million, or $0.08 per share on a diluted basis. In the third quarter of fiscal year 2019, net loss includes an after-tax gain from the sale of assets of $7.7 million, or $0.07 per share on a diluted basis and an after-tax loss from asset impairments of approximately $173.2 million, or $1.58 per share on a diluted basis. In the fourth quarter of fiscal year 2019, net income includes an after-tax gain from the sale of assets of $9.8 million, or $0.09 per share on a diluted basis. Fiscal Year 2018 Quarters Ended As adjusted, Note 2 (in thousands, except per share amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) Operating revenues Operating income (loss) Income (loss) from continuing operations Net income (loss) Basic earnings per common share: Income (loss) from continuing operations Net income (loss) Diluted earnings per common share: Income (loss) from continuing operations Net income (loss) $ 564,087 $ 577,484 $ 648,872 $ 696,825 $ 2,487,268 3,609 500,642 500,106 4.57 4.57 4.55 4.55 (1,164) (1,633) (11,879) (0.03) (0.12) (0.03) (0.12) 6,306 (8,174) (8,008) (0.08) (0.08) (0.08) (0.08) 24,213 2,175 2,453 0.02 0.02 0.02 0.02 32,964 493,010 482,672 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 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 income 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. NOTE 19 SUBSEQUENT EVENTS On November 13, 2019, we entered into the first amendment to our 2018 Credit Facility by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “2018 Credit Facility Amendment”). Amongst other things, the 2018 Credit Facility Amendment (i) extended the maturity date of the 2018 Credit Facility by one year to November 13, 2024, (ii) deleted certain negative covenants and (iii) refreshed the number of permissible extensions of the maturity date that require only the consent of extending lenders. 90 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. PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 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 3, 2020, to be filed with the SEC not later than 120 days after September 30, 2019. 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 2019” and “Corporate Governance— Compensation Committee Interlocks and Insider Participation” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 3, 2020, to be filed with the SEC not later than 120 days after September 30, 2019. 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 3, 2020, to be filed with the SEC not later than 120 days after September 30, 2019. 91 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 3, 2020, to be filed with the SEC not later than 120 days after September 30, 2019. 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 3, 2020, to be filed with the SEC not later than 120 days after September 30, 2019. 92 PART IV Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 1. Financial Statements: Our consolidated financial statements, together with the notes thereto and the report of Ernst & Young LLP dated November 15, 2019, 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, 2019 and 2018 Consolidated Statements of Operations for the Years Ended September 30, 2019, 2018 and 2017 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended September 30, 2019, 2018 and 2017 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2019, 2018 and 2017 Consolidated Statements of Cash Flows for the Years Ended September 30, 2019, 2018 and 2017 Notes to Consolidated Financial Statements Page 48 51 52 53 54 55 56 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 3.1 3.2 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). 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). 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 Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934. 4.2 4.3 4.4 4.5 4.6 Indenture, dated March 19, 2015, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, as trustee (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). First Supplemental Indenture, dated March 19, 2015, to the Indenture, dated March 19, 2015, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, as trustee (including the form of 4.65% Senior Note due 2025) (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). Second Supplemental Indenture, dated December 20, 2018, to the Indenture, dated March 19, 2015, among Helmerich & Payne International Drilling Co., Helmerich & Payne, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.6 of the Company’s Form 8 K filed on December 20, 2018, SEC File No. 001 04221). Indenture, dated December 20, 2018, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co. and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 of the Company’s Form 8-K filed on December 20, 2018, SEC File No. 001-04221). First Supplemental Indenture, dated December 20, 2018, to the Indenture, dated December 20, 2018, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co. and Wells Fargo Bank, National Association, as trustee (including the forms of 4.65% Senior Note due 2025) (incorporated herein by reference to Exhibit 4.2 of the Company’s Form 8 K filed on December 20, 2018, SEC File No. 001 04221). 93 4.7 Registration Rights Agreement, dated December 20, 2018, among Helmerich & Payne, Inc., Helmerich & Payne International Drilling Co., Credit Suisse Securities (USA) LLC, Goldman Sachs & Co. LLC and Morgan Stanley & Co. LLC (incorporated herein by reference to Exhibit 4.3 of the Company’s Form 8-K filed on December 20, 2018, SEC File No. 001-04221). 10.1 Credit Agreement, dated November 13, 2018, among Helmerich & Payne, Inc., the lenders from time to time party thereto and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.2 of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2018, SEC File No. 001-04221). 10.2 Amendment No. 1 to Credit Agreement, dated November 13, 2019, among Helmerich & Payne, Inc., the lenders party thereto and Wells Fargo Bank, National Association. *10.3 *10.4 *10.5 *10.6 *10.7 *10.8 *10.9 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). 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). 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). 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). Form of Agreements for the 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). 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) Inventive 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). 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 Agreements for the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan applicable to certain executives: (i) Nonqualified Stock Option Agreement and (ii) Restricted Stock Award Agreement (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 Agreements for the Helmerich & Payne, Inc. 2010 Long-Term 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 10.2 of the Company’s Form 8-K filed on March 14, 2012, SEC File No. 001-04221). 94 *10.14 Form of Restricted Stock Award Agreement for the 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) Nonqualified Stock Option Agreement and (ii) 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). *10.18 *10.19 Form of Agreements for the 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). Form of Agreements for the 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 the Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan applicable to Directors: (i) Nonqualified Stock Option Agreement and (ii) 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). *10.24 Form of Performance-Vested Restricted Share Unit Award Agreement for the Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 18, 2018 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. 95 101 Financial statements from this Form 10 K formatted in Inline 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. 104 Cover Page Interactive Date File (formatted as Inline XBRL and contained in Exhibit 101). * Management or Compensatory Plan or Arrangement. Item 16. FORM 10-K SUMMARY None. 96 (This page has been left blank intentionally.) 97 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 15, 2019 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 /s/ John W. Lindsay John W. Lindsay /s/ Mark W. Smith Mark W. Smith /s/ Sara M. Momper Sara M. Momper /s/ Hans Helmerich Hans Helmerich /s/ Delaney Bellinger Delaney Bellinger /s/ Kevin G. Cramton Kevin G. Cramton /s/ Randy A. Foutch Randy A. Foutch /s/ Jose R. Mas Jose R. Mas /s/ Thomas A. Petrie Thomas A. Petrie /s/ Donald F. Robillard, Jr. Donald F. Robillard, Jr. /s/ Edward B. Rust, Jr. Edward B. Rust, Jr. /s/ Mary M. VanDeWeghe Mary M. VanDeWeghe /s/ John D. Zeglis John D. Zeglis Title Date Director, President and Chief Executive Officer (Principal Executive Officer) Vice President and Chief Financial Officer (Principal Financial Officer) Vice President and Chief Accounting Officer (Principal Accounting Officer) November 15, 2019 November 15, 2019 November 15, 2019 Director and Chairman of the Board November 15, 2019 Director Director Director Director Director Director Director Director Director 98 November 15, 2019 November 15, 2019 November 15, 2019 November 15, 2019 November 15, 2019 November 15, 2019 November 15, 2019 November 15, 2019 November 15, 2019 (This page has been left blank intentionally.) TOPPAN MERRILL CHE109576//28-JAN-20 09:59 DISK108:[20ZAH2.20ZAH71102]MD71102A.;10 mrll_0119.fmt Free: 28DM/0D Foot: 0D/ 0D VJ RSeq: 1 Clr: 0 DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;141 2 C Cs: 18843 Directors Officers 27JAN202014084706 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 3, 2020. Hans Helmerich Chairman of the Board Tulsa, Oklahoma Kevin G. Cramton*(***) Operating Partner HCI Equity Partners Washington, D.C. Mark W. Smith Senior Vice President and Chief Financial Officer Robert L. Stauder Senior Vice President and Chief Engineer Randy A. Foutch**(***) Chairman and Retired Chief Executive Helmerich & Payne International Officer Laredo Petroleum, Inc. Tulsa, Oklahoma Drilling Co. (subsidiary) Cara M. Hair Vice President, Corporate Services and Chief Legal and Compliance Officer John W. Lindsay President and Chief Executive Officer Tulsa, Oklahoma John R. Bell Vice President Delaney Bellinger*(***) Helmerich & Payne International Vice President and Chief Information Holdings and Helmerich & Payne Officer, Retired Huntsman Corporation Woodlands, Texas Offshore (subsidiaries) 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 Todd W. Benson President Helmerich & Payne Technologies (subsidiary) Wade W. Clark Vice President U.S. Land Helmerich & Payne International Drilling Co. (subsidiary) Michael P. Lennox Vice President U.S. Land Helmerich & Payne International Drilling Co. (subsidiary) 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 Mary M. VanDeWeghe**(***) Chief Executive Officer and President Forte Consulting, Inc. Bethesda, Maryland 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 Helmerich & Payne, Inc. 10-K Proj: P3311DFW20 Job: 20ZAH71102 (20-3311-2) Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 39.6 X 59.3 File: MD71102A.;10 v6.8 ai158017465635_2019 Annual Report Cover--PRINT READY w-spine.pdf 2 1/27/20 8:24 PM 1 2 3 4 5 1. Based on EnergyPoint Research 2018-19 Customer Satisfaction Survey. 2. For fiscal year 2019. 3. Since 1971. 4. Based on December 31, 2019 closing stock price. 5. From January 1, 2010 through December 31, 2019. 20_48280_Merrill Crop.indd 3 20_48280_Merrill Crop.indd 3 1/27/20 8:25 PM 1/27/20 8:25 PM ai158017465635_2019 Annual Report Cover--PRINT READY w-spine.pdf 1 1/27/20 8:24 PM 20_48280_Merrill Crop.indd 4 20_48280_Merrill Crop.indd 4 1/27/20 8:25 PM 1/27/20 8:25 PM

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