Helmerich & Payne
Annual Report 2020

Plain-text annual report

2020 ANNUAL REPORT Stockholders’ Meeting Helmerich & Payne shareholders are invited to attend our annual meeting which will be held on March 2, 2021. Stock Transfer Agent and Registrar Computershare Trust Company, N.A. First Class/Registered/Certified Mail PO Box 505000 Louisville, KY 40233-5022 Courier Services 462 South 4th Street Suite 1600 Louisville, KY 40202 Shareholder Services 781.575.2879 800.884.4225 (Toll Free) Independent Registered Public Accounting Firm Ernst & Young LLP Tulsa, Oklahoma Direct Inquiries To David T. Wilson Vice President, Investor Relations Helmerich & Payne, Inc. 1437 South Boulder Avenue Tulsa, Oklahoma 74119 918.742.5531 NYSE : HP helmerichpayne.com DIRECTORS THE H&P WAY THE H&P WAY IS A CORE SET OF PILLARS THAT LAY THE FOUNDATION OF HOW WE CREATE, INTERACT AND COMMUNICATE. OUR PURPOSE Improving lives through efficient and responsible energy WHAT WE DO We safely provide performance-driven drilling solutions OUR VALUES Our values reflect who we are and the way we interact with one another, our customers, partners and shareholders Actively C.A.R.E. We treat one another with respect. We care about each other. We are committed to Controlling and Removing Exposures for ourselves and others. Service Attitude We do our part and more for those around us. We consider the needs of others and provide solutions to meet their needs. Innovative Spirit We constantly work to improve and try new approaches. We make decisions based on our clients’ challenges and goals with the long-term view in mind. Teamwork We listen to one another and work across teams toward a common goal. We collaborate to achieve results and focus on success with our customers and shareholders. Do the Right Thing We are honest and transparent. We tackle tough situations, make decisions and speak up when needed. Randy A. Foutch **(***) Lead Director Director since 2007 Chairman, Retired, Laredo Petroleum, Inc. Director since 2012 Thomas A. Petrie **(***) Chairman, Petrie Partners, LLC Delaney Bellinger *(***) Vice President and Chief Information Officer, Retired, Huntsman Corporation Director since 2018 Kevin G. Cramton *(***) Operating Partner, HCI Equity Partners Director since 2017 Hans Helmerich Chairman of the Board Director since 1987  John W. Lindsay President and Chief Executive Officer Director since 2012 José R. Mas **(***) Chief Executive Officer, MasTec, Inc. Director since 2017 Donald F. Robillard, Jr. *(***) Executive Vice President, Chief Financial Officer and Chief Risk Officer, Retired, Hunt Consolidated, Inc. Director since 2012 Edward B. Rust, Jr. *(***) Chairman and Chief Executive Officer, Retired, State Farm Mutual Automobile Insurance Company Director since 1997 Mary M. VanDeWeghe **(***) President and Chief Executive Officer, Forte Consulting, Inc. Director since 2019 John D. Zeglis *(***) Chairman and Chief Executive Officer, Retired, AT&T Wireless Services, Inc. Director since 1989  * Member Audit Committee ** Member Human Resources Committee *** Nominating & Corporate Governance Committee 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, 2020 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) (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) Delaware 73-0679879 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b 2 of the Exchange Act). Yes No At March 31, 2020, 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 $1.68 billion based on the closing price of such stock on the New York Stock Exchange on such date of $15.65. Number of shares of common stock outstanding at November 12, 2020: 107,601,988 Portions of the Registrant’s 2020 Proxy Statement for the Annual Meeting of Stockholders to be held on March 2, 2021 are incorporated by reference into Part III of this Form 10 K. The 2020 Proxy Statement will be filed with the U.S. Securities and Exchange Commission 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 16 30 30 30 30 31 31 33 34 48 50 98 98 98 98 98 98 99 99 99 99 99 102 103 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; estimates of our revenues, income, earnings per share, and market share; our capital structure and our ability to return cash to stockholders through dividends or share repurchases; the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures; the volatility of future oil and natural gas prices; the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing nations (together, “OPEC+”) with respect to production levels or other matters related to the prices of oil and natural gas; 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; the effect, impact, potential duration or other implications of the ongoing outbreak of a novel strain of coronavirus ("COVID-19") and the oil price collapse in 2020, and any expectations we may have with respect thereto; 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, including as a result of the U.S. presidential election, 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” and 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 solutions 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 three reportable business segments: North America Solutions, Offshore Gulf of Mexico, and International Solutions. During the third quarter of fiscal year 2020, as part of our restructuring efforts (see Note 19— Restructuring Charges to our Consolidated Financial Statements) and consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, we implemented organizational changes. We are moving from a product-based offering, such as a rig or separate technology package, to an integrated solution-based approach by combining proprietary rig technology, automation software, and digital expertise into our rig operations. Operations previously reported within the former U.S. Land and H&P Technologies operating and reportable segments are now managed and presented within the North America Solutions reportable segment. Our technology services focus on developing, promoting and commercializing technologies designed to improve the efficiency and accuracy of drilling operations, as well as wellbore quality and placement. During the fiscal year ended September 30, 2020, our North America Solutions operations were primarily located in Colorado, Ohio, Oklahoma, New Mexico, North Dakota, Pennsylvania, Texas, West Virginia and Wyoming. Our Offshore Gulf of Mexico operations were conducted in Louisiana and in U.S. federal waters in the Gulf of Mexico. Our International Solutions operations had rigs located in four international locations during fiscal year 2020: 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 containing approximately 389,000 leasable square feet and approximately 210 acres of undeveloped real estate. Our research and development endeavors include both internal development and external acquisition of developing technologies. On October 1, 2019, we elected to utilize a wholly-owned insurance captive (“Captive”) to insure the deductibles for our workers’ compensation, general liability and automobile liability insurance programs. The Company and the Captive maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of significant events covered under these programs. Our real estate operations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are included in "Other." Drilling Fleet The following map shows the number of working rigs by basin in our North America Solutions reportable segment as of September 30, 2020: 4 The following table sets forth certain information concerning our North America Solutions drilling rigs as of September 30, 2020: North America Solutions Fleet Super-Spec FlexRig (1) ® Non Super-Spec FlexRig (2) ® Total Fleet Current Location Total Available Rigs Contracted Total Available Rigs Contracted Total Available Rigs Contracted TX OK NM ND CO PA OH WY WV Totals 156 26 25 10 2 3 5 4 3 234 42 4 12 4 1 — 1 — 3 67 7 2 — 4 11 4 — — — 28 — — — — 2 — — — — 2 163 28 25 14 13 7 5 4 3 262 42 4 12 4 3 — 1 — 3 69 (1) 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. (2) AC drive, 1,500 horsepower drawworks, 500,000 or 750,000 lbs. hookload rating, 5,000 or 7,500 psi mud circulating system, may or may not have multiple-well pad capability. The following table sets forth certain information concerning our Offshore Gulf of Mexico drilling rigs as of September 30, 2020: Current Location Louisiana (2) Gulf of Mexico Totals Offshore Gulf of Mexico Fleet Shallow Water (1) Deep Water (1) Total Fleet Total Available Rigs Contracted Total Available Rigs Contracted Total Available Rigs Contracted 3 2 5 — 2 2 — 3 3 — 3 3 3 5 8 — 5 5 (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 Solutions drilling rigs as of September 30, 2020: International Solutions Fleet AC (FlexRig® 3) (1) AC (FlexRig® 4) (2) Other AC SCR (3) Total Fleet Current Location Total Available Rigs Contracted Total Available (1) Rigs Contracted Total Available (1) Rigs Contracted Total Available (1) Rigs Contracted Total Available Rigs Contracted Argentina Colombia Bahrain U.A.E. Totals 12 2 — 2 16 2 — — — 2 4 2 3 — 9 — — 3 — 3 — 1 — — 1 — — — — — 4 2 — — 6 — — — — — 20 7 3 2 32 2 — 3 — 5 (1) Other than one super–spec rig (as described above) in Argentina, the FlexRig® 3 is equipped with an AC drive, 1,500 horsepower drawworks, and a 750,000 lb. hookload rating. It can be equipped with an optional skid or walking system, third mud pump, and 7,500 psi high pressure mud system. The other 11 rigs in Argentina are equipped with skid systems. (2) The FlexRig® 4 model has a small footprint and is designed to be highly mobile. The rig is equipped with a 300,000 lb. mast, 400HP top drive and two mud pumps. Range 3 drill pipe is used without setback. The rig is capable of horizontal and vertical drilling. (3) A silicon-controlled-rectifier (“SCR”) system converts alternate current (“AC”) produced by one or more AC generator sets into direct current (“DC”). Of the six SCR rigs, one is equipped with 2,100 horsepower drawworks and the remaining five are equipped with 3,000 horsepower drawworks to drill deep conventional wells. 5 Drilling Services and Solutions General We are the largest provider of super-spec 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 cap oil companies and private independent companies (including private equity-backed companies) that are focused on unconventional shale basins. In South America and the Middle East, our customers primarily include major international and national oil companies. We do not operate any legacy mechanical rigs. We had revenues from individual customers, within our North America Solutions segment, that constituted 10 percent or more of our total revenues as follows: (in thousands) EOG Resources, Inc. 2018 $ 258,194 We did not have any individual customers that represented 10% or more of our total consolidated revenues in fiscal years 2019 or 2020. 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 2020, 2019, and 2018: North America Solutions Offshore Gulf of Mexico International Solutions 2020 (1) 2019 (2) 2018 2020 2019 2018 2020 2019 (3) 2018 Year Ended September 30, Average active rigs per day 134.3 224.1 213.6 Average utilization (4) 47% 67% 61% 5.3 66% 5.9 74% 5.6 70% 12.6 40% 17.6 55% 18.3 49% (1) At the beginning of the third quarter of fiscal year 2020, the fleet was downsized by 37 rigs. See Note 5—Property, Plant and Equipment to our Consolidated Financial Statements. (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. (4) 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, or stacked under contract. Our Segments North America Solutions Segment We believe we operate the largest technologically advanced AC drive drilling rig fleet in North America 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 oil basins, which include the Permian Basin, Eagle Ford Shale, and Woodford Shale. Nearly all of our active rigs are drilling horizontal or directional wells. As of September 30, 2020, we had approximately 20 percent of the total market share in U.S. land drilling and approximately 29 percent of the super-spec market share in U.S. land drilling. In the United States, we have the industry's largest super-spec fleet with 234 rigs, of which 67 were under contract at September 30, 2020. In total, 69 of our 262 marketed rigs were under contract, 54 were under fixed term contracts, and 15 were working well-to-well as of September 30, 2020. Our drilling technology solutions within this segment enables a holistic solution-based approach that includes products, services and capabilities. This approach provides performance-driven drilling services intended to deliver greater levels of accuracy, consistency, optimization and a reduction of human error to create higher quality wellbores. This technology is intended to address our customers' unique challenges and should result in less wellbore tortuosity and reduce positional uncertainty in the directional drilling process. During fiscal year 2019, we released AutoSlide®, 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. Currently, our AutoSlide® application is commercially available in all U.S. oil and gas basins. Many components of our digital technology, including the MOTIVE Bit Guidance System® technology 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. 6 Our North America Solutions segment contributed approximately 83.1 percent ($1.5 billion) of our consolidated operating revenues during fiscal year 2020, compared to approximately 86.7 percent ($2.4 billion) and 84.2 percent ($2.1 billion) of our consolidated operating revenues during fiscal years 2019 and 2018, respectively. In North America, our customers are primarily from the major oil companies, large independent oil companies, small cap oil companies and private independent companies (including private equity-backed companies). Offshore Gulf of Mexico Segment Our Offshore Gulf of Mexico segment has been in operation since 1968 and currently consists of eight platform 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 conventional fixed leg 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, 2020, five of the eight offshore rigs were under contract. Our Offshore Gulf of Mexico operations contributed approximately 8.1 percent ($143.1 million) of our consolidated operating revenues during fiscal year 2020, compared to approximately 5.3 percent ($147.6 million) and 5.7 percent ($142.5 million) of our consolidated operating revenues during fiscal years 2019 and 2018, respectively. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 81.1 percent ($116.1 million) of offshore revenues during fiscal year 2020. International Solutions Segment Our International Solutions segment operates primarily in Argentina, Colombia, Bahrain and U.A.E. During the fourth quarter of fiscal year 2018, we ceased operations in Ecuador. As of September 30, 2020, we had 5 land rigs contracted for work in locations outside of the United States. Our International Solutions operations contributed approximately 8.1 percent ($144.2 million) of our consolidated operating revenues during fiscal year 2020, compared to approximately 7.6 percent ($211.7 million) and 9.6 percent ($238.4 million) of our consolidated operating revenues during fiscal years 2019 and 2018, respectively. Argentina As of September 30, 2020, we had 20 rigs in Argentina. Revenues generated by Argentine drilling operations contributed approximately 4.8 percent ($84.4 million) of our consolidated operating revenues during fiscal year 2020 compared to approximately 5.9 percent ($165.7 million) and 7.6 percent ($190.0 million) of our consolidated operating revenues during fiscal years 2019 and 2018, respectively. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 3.6 percent of our consolidated operating revenues and approximately 43.9 percent of our international operating revenues during fiscal year 2020. The Argentine drilling contracts are primarily with large international or national oil companies. Colombia As of September 30, 2020, we had seven rigs in Colombia. Revenues generated by Colombian drilling operations contributed approximately 0.4 percent ($6.4 million) of our consolidated operating revenues in fiscal year 2020, compared to approximately 1.1 percent ($29.8 million) and 1.6 percent ($38.8 million) of our consolidated operating revenues during fiscal years 2019 and 2018, respectively. Revenues from drilling services performed for our two largest customers in Colombia totaled approximately 0.4 percent of our consolidated operating revenues and approximately 4.4 percent of our international operating revenues during fiscal year 2020. The Colombian drilling contracts are primarily with large international or national oil companies. Bahrain As of September 30, 2020, we had three rigs in Bahrain. Revenues generated by Bahrain drilling operations contributed approximately 1.6 percent ($28.7 million) of our consolidated operating revenues in fiscal year 2020, compared to approximately 0.4 percent ($11.5 million) and 0.4 percent ($9.5 million) of our consolidated operating revenues during fiscal years 2019 and 2018, respectively. All of our revenues in Bahrain are from a partner of the local national oil company. United Arab Emirates As of September 30, 2020, we had two rigs in the U.A.E. Revenues generated by U.A.E. drilling operations contributed approximately 1.4 percent ($24.7 million) of our consolidated operating revenues in fiscal year 2020, compared to approximately 0.2 percent ($4.7 million) in fiscal year 2019 and nominal amounts in fiscal year 2018. Other Operations Other Operations include additional non-reportable operating segments. 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 and undeveloped real estate. 7 On October 1, 2019, we elected to utilize the Captive to insure the deductibles for our workers’ compensation, general liability and automobile liability insurance programs. Casualty claims occurring prior to October 1, 2019 will remain recorded within each of the operating segments and future adjustments to these claims will continue to be reflected within the operating segments. Reserves for legacy claims occurring prior to October 1, 2019, will remain as liabilities in our operating segments until they have been resolved. Changes in those reserves will be reflected in segment earnings as they occur. We will continue to utilize the Captive to finance the risk of loss to equipment and rig property assets. The Company and the Captive maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of significant events covered under these programs. Our operating subsidiaries are paying premiums to the Captive, typically on a monthly basis, for the estimated losses based on the external actuarial analysis. The Company is also utilizing the Captive to provide stop-loss coverage over its self-insured employee health plan, which covers insured claims in excess of employee deductibles. The Company did not previously purchase any stop-loss coverage. 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. 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® drilling rig entered the market in 1998. The original 18 rigs were designated as FlexRig® 1 and FlexRig® 2 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 “FlexRig® 3 rigs,” which incorporated new drilling technology and improved the safety and environmental design. The FlexRig® 3 rigs 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, predominantly all new FlexRig® drilling rigs were built supported by a firm contract and attractive returns. To date, we have built over 200 FlexRig® 3 rigs that align with this strategy. An important part of our strategy was to design a rig that could support continuous improvement through upgrade capability of the hardware and software on the rigs to take advantage of technology improvements and lengthening the industry rig replacement cycle. These upgrades included, but were not limited to, enhanced drilling control systems and software, skid and walking systems for drilling multiple well pads, 7,500 psi mud systems, set back capacity to accommodate the pipe that the longer laterals demanded, and additional mud system capacity. 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 FlexRig®4 drilling rig, which was designed to efficiently drill shallower wells on multi-well pads. The FlexRig® 4 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 FlexRig® 4 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 significantly reduced environmental impact and increased production from a smaller footprint. In 2011, we announced the introduction of the FlexRig® 5 drilling rig. The FlexRig® 5 drilling rig was designed for deeper wells than the FlexRig® 4 drilling rig 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 FlexRig® 3 rig design but adds a bi-directional skidding system and equipment capacities suitable for wells in excess of 25,000 feet of measured depth. In 2016, we saw the progression of longer lateral wells and the technical challenges involved in drilling longer lateral wells. At that time, we began delivering rigs to the market that were equipped and capable of drilling the longer lateral wells. The industry would later refer to these rigs as super-spec rigs, which have the following specific characteristics: AC drive, minimum 1,500 horsepower drawworks, minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and multiple-well pad capability. Additionally, our competency in design and construction as well as our financial strength enabled us to efficiently upgrade our other existing rigs to super-spec, resulting in what we believe to be the largest fleet of super-spec rigs in the world. As of September 30, 2020, we held approximately 29 percent of the super-spec market share in the U.S. land drilling market with 234 super-spec rigs. In 2017, we introduced our first walking rig by reconfiguring our skid designed FlexRig® 3 drilling rigs. Since then, we have reconfigured, converted, and upgraded a total of 44 FlexRig® drilling rigs to super-spec walking rigs. Years of designing and building our fleet of AC drive FlexRig® drilling rigs has given us many competitive benefits. One key advantage is fleet uniformity. We have overseen the design and assembly of all of our AC FlexRig® drilling rigs, 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 FlexRig® drilling rigs to super-spec in a capital efficient way. High levels of uniformity in crew training and rotation and our ability to control and remove safety exposures across a more standard fleet allow us to deliver higher performance in a safer and more reliable manner for the customer. Further, our fleet is supported by a cost-effective Company-owned supply chain that provides standardized materials directly to the rigs from our regional warehouses. 8 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 Rig Systems Monitoring and Support Center (“RSMS”) and Remote Operations Centers ("ROCs"). Our RSMS and ROCs are 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 RSMS provides real-time help and feedback to our wellsite employees, as well as our customers, to fully optimize our operational performance. Additionally, our RSMS and ROCs have staffs of engineers and industry experts that work with our customers to enhance wellbore positioning, drilling program execution and overall drilling performance. The monitoring group and our performance engineers capture our drilling work steps to help 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 assembly facility is located near Houston, Texas. Our facility near Tulsa, Oklahoma is utilized for overhauling, recertification, and repairs. During fiscal year 2020, we continued to see adoption and growth with our technologies and automation focused solutions. Our FlexApp solutions, which layer on top of our FlexRig® drilling control system, continue to add value for our customers. Our AutoSlide® service, which is powered by our Motive Bit Guidance System® technology, continued to grow in commercial feet steered, new customer adoption and the number of deployments. Our MagVarTM, Drillscan® and Motive Bit Guidance System® solutions continue to be available on both H&P and third-party rigs. These solutions continue to provide differentiated value for our customers in the areas of drilling engineering, wellbore placement, and wellbore quality. Our path to autonomous drilling continues to evolve with several solutions in Alpha and Beta testing. All of our automation focused solutions and 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. All of our technologies play an important role in developing our strategy as we head towards autonomous drilling. The technologies that are currently in use include the following: Application Name FlexTorque™ Hardware and software designed to decrease downhole drilling vibration and "slip-stick" during drilling. This helps with drilling efficiency and is intended to help extend bit and downhole tool life to help reduce costly nonproductive time. Description Flex-Oscillator 2.0™ 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 helps support more effective directional drilling. FlexB2D™ FlexDrill 1.0™ AutoSlide ® MagVarTM DrillScan ® Software to engage and disengage the bit during connections in an established controlled and consistent manner that is intended to help extend bit and downhole tool life, better drilling parameters and less costly bit trips out of the hole. Software licensed from ExxonMobil to help maximize the bit's rate of penetration, which we have automated, that is intended to allow the drilling control system to achieve the ideal mechanical specific energy at the bit. Powered by Motive’s Bit Guidance System with FlexRig ® control systems to allow for automatic slide drilling via computer control. ® technology and utilizes machine learning and automation to help interface Solution intended to help improve surveying accuracy and contribute to increased horizontal well economics while reducing collision risk. Industry leader in physics-based modeling software to help select bottom hole assemblies and help provide real-time drilling dynamics evaluation. MOTIVE Bit Guidance System ® Automated directional drilling guidance system that helps improve wellbore quality with a scalable, repeatable data driven platform approach to help increase horizontal well economics and help 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, 2020, we had 79 rigs under contract, compared to 218 and 259 rigs under contract as of September 30, 2019 and 2018, 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. 9 Our industry is highly competitive, and we strive to differentiate our services based upon the quality of our FlexRig® drilling rigs and our engineering design expertise, operational efficiency, software technologies, 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. In many instances, our contracts 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 2020, a majority 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 H&P compared to contracts performed on a “daywork” basis. Also, we may enter into “lump-sum” 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. “Lump-sum” contracts entail varying degrees of risk greater than the usual “footage” contract. We also actively pursue “performance daywork” contracts, pursuant to which we are compensated based upon our performance against a mutually agreed upon set of predetermined targets. These contracts typically have a lower base dayrate but give us the opportunity to receive additional compensation by meeting or exceeding certain performance targets. The risks associated with these contracts relate to the failure to reach the agreed upon performance targets. If we do not meet these targets, we will not receive additional compensation beyond the base dayrate and will recognize less overall drilling services revenue than we would by utilizing other types of contracts. We are seeing a growing adoption of performance contracts by our customers and we expect this trend to continue. The duration of our drilling contracts are generally either “well to well” or for a fixed term. “Well to well” contracts can be terminated at the option of either party upon the completion of drilling of any one well. Fixed-term contracts generally have a minimum term of at least six months up to multiple years. These contracts customarily provide for termination at the election of the customer but may include an “early termination payment” to be paid to us if the contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances such as destruction of a drilling rig, bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. Contracts generally contain renewal or extension provisions exercisable at the option of the customer at prices mutually agreeable to us and the customer. In most instances, contracts provide for additional payments for mobilization and demobilization of the rig. Contract Backlog Drilling contract backlog is the expected future dayrate revenue from executed contracts. We calculate backlog as the total expected revenue from fixed-term contracts and do not include any anticipated contract renewals as part of its calculation. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. In addition to depicting the total expected revenue from fixed-term contracts, backlog is indicative of expected future cash flow that the Company expects to receive regardless of whether a customer honors the fixed-term contract to expiration of a contract or decides to terminate the contract early and pay an early termination payment. In the event of an early termination payment, the timing of the recognition of backlog and the total amount of revenue may differ; however, the overall associated cash flow is preserved. As such, management finds backlog a useful metric for future planning and budgeting, whereas investors consider it in estimating future revenue and cash flows of the Company. As of September 30, 2020, and 2019, our drilling contract backlog was $0.7 billion and $1.2 billion, respectively. The decrease in backlog at September 30, 2020 from September 30, 2019 is primarily due to prevailing market conditions causing a decline in the number of drilling contracts executed and to some extent an increase in the number of early terminations of contracts. Approximately 33.3 percent of the total September 30, 2020 backlog is reasonably expected to be filled in fiscal year 2022 and thereafter. 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. As a result of the depressed market conditions and negative outlook for the near term, beginning in the second quarter of fiscal year 2020, certain of our customers, as well as those of our competitors, have opted to renegotiate or early terminate existing drilling contracts. Such renegotiations have included requests to lower the contract dayrate in exchange for additional terms, temporary stacking of the rig, and other proposals. During the fiscal years ended September 30, 2020 and 2019, early termination revenue associated with term contracts was $73.4 million and $11.3 million, respectively. 10 In response to the current market conditions, several operators included in our North America Solutions operating segment have opted to place their rigs in an idle-but-contracted state as an alternative to early termination. This includes "warm stacking" and "cold stacking." Warm stacking occurs when a rig remains on-site while pausing drilling activity, while cold stacking occurs when a rig is demobilized and returned to the yard temporarily until next steps are determined. When rigs are stacked, they remain under the terms of the contract but typically pay a reduced rate, where the remaining term days are generally not reduced, but our operating expenses are reduced. In many instances for stacked rigs, for the total days stacked there are proportional days added to the original contract length at the original contracted rate. As of September 30, 2020, there are five rigs that are warm stacked, five rigs that are cold stacked within the North America Solutions segment. The following table sets forth the total backlog by reportable segment as of September 30, 2020 and 2019, and the percentage of the September 30, 2020 backlog reasonably expected to be filled in fiscal year 2022 and thereafter: (in billions) North America Solutions Offshore Gulf of Mexico International Solutions Total Backlog Revenue September 30, 2020 September 30, 2019 Percentage Reasonably Expected to be Filled in Fiscal Year 2022 and Thereafter $ $ 0.6 $ — 0.1 0.7 $ 1.0 — 0.2 1.2 33.3% — 39.3 The early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. In some limited circumstances, such as sustained unacceptable performance by us, no early termination payment would be paid to us. Early terminations could cause the actual amount of revenue earned to vary from the backlog reported. See Item 1A— “Risk Factors — Our current backlog of drilling services and solutions revenue may continue to decline and may not be ultimately realized as fixed term contracts and may, in certain instances, be terminated without an early termination payment" within this Form 10-K regarding fixed-term contract risk. Additionally, see Item 1A— “Risk Factors — The impact and effects of public health crises, pandemics and epidemics, such as the ongoing outbreak of COVID-19, have adversely affected and are expected to continue to adversely affect our business, financial condition and results of operations" within this Form 10-K. Employees As of September 30, 2020, we had 3,634 employees within the United States and 504 employees in our 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. Human Capital Objectives and Programs 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. Recruiting Our recruiting practices and decisions on whom to hire are among our most important activities. In a downturn year such as fiscal year 2020, we maintain relationships with former employees and prioritize recalling our most experienced people for field positions. In addition, we utilize social media, local job fairs and educational organizations across the United States to find diverse, motivated and responsible employees. Core Values and Culture Fostering and maintaining a strong, healthy culture is a key strategic focus. Our core values reflect who we are and the way our employees interact with one another, our customers, partners and shareholders. Our 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 core value of 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. Our core value of teamwork means that we listen to one another and work across teams toward a common goal. We collaborate to achieve results and focus on success for our customers and shareholders. Finally, we do the right thing. That means we are honest and transparent. We tackle tough situations, make decisions, and speak up when needed. To further encourage living out our core values, during fiscal year 2020, an average of 10 organizational health sessions per month were conducted with employee teams. 11 Education and Training 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 training starts right at the beginning with 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 and laws applicable to our business skills and competencies directly related to employees' positions; and responsibility for personal safety and the safety of fellow employees, others on location and the environment. Safety Training and Serious Injury and/or Fatality ("SIF") Reduction Program Over the last three years, 94% of our Rig Managers and 91% of Drillers received in-field coaching from a Safety Leadership Coach and employees received, on average, 26 hours of training. One of our most critical responsibilities is the safety of our employees and the employees of our customers. Traditional approaches to safety focused on lagging indicators that centered on reacting to injuries after they occurred. However, we believe the best approach is to focus on exposures (leading indicators) and controlling and removing them, thus helping prevent injuries before they occur. Accordingly, we have moved to tracking potential SIFs with annual goals targeted at reducing SIFs. In calendar year 2019, we focused on reducing the number of SIF incidents by improving pre-job planning tools as a means for reducing incidents with SIF potential, year-over-year reduction in incidents related to handling of tubulars and year-over-year increase in seatbelt usage among employees based on self-reported seatbelt use. Educational Assistance Plan We offer an Educational Assistance Plan for eligible employees pursuing an undergraduate degree and, in some cases, post-graduate degrees. Health and Welfare We support our employees’ and their families’ health by offering 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 variety of resources and services to help our employees for Retirement. H&P offers a comprehensive retiree medical plan for those who meet eligibility requirements. In addition, we provide a 401(k) plan with a company match. 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. 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. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage. 12 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 affected from time to time and in varying degrees by foreign and domestic political developments and a variety of federal, state, foreign, regional and local laws, rules and regulations, including those relating to: • drilling of oil and natural gas wells; • directional drilling services; • protection of the environment; • workplace health and safety; • labor and employment; • data privacy; • taxation; • exportation or importation of equipment, technology and software; and • currency conversion and repatriation. Environmental laws and regulations that apply to our operations include the Clean Air Act, the Clean Water Act, the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), the Resource Conservation and Recovery Act (each, as amended) and similar laws that provide for responses to, and liability for, air emissions, water discharges or releases of oil or hazardous substances into the environment, including damages to natural resources. Applicable environmental laws and regulations also include similar foreign, state or local counterparts to the above-mentioned federal laws, which regulate air emissions, water discharges and hazardous substances and waste. Environmental 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. The Occupational Safety and Health Act (“OSHA”) and other similar laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, the Environmental Protection Agency community right-to-know regulations under Title III of CERCLA, the Emergency Planning and Community Right-to-Know Act and similar state statutes and local regulations require that information be maintained about hazardous materials used in our operations and that this information be provided to employees, state and local governments, emergency responders and citizens. A number of countries actively regulate and control the importation and/or exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government actions and initiatives by OPEC+ may continue to contribute to oil price volatility. In some areas of the world, government activity has adversely affected the amount of exploration and development work done by oil and gas companies and influenced their need for drilling services, and likely will continue to do so. In addition, we are subject to a variety of other U.S. and foreign laws and regulations, including, but not limited to, the U.S. Foreign Corrupt Practices Act and other anti-bribery and anti-corruption laws. The U.S. Foreign Corrupt Practices Act and similar anti-bribery and anti-corruption laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to non-U.S. officials for the purpose of obtaining or retaining business. Failure to comply with applicable laws or regulations or acts of misconduct could subject us to fines, penalties or other sanctions. For more information, see Item 1A— “Risk Factors — Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti bribery legislation could adversely affect our business.” We are also subject to the jurisdiction of the U.S. Treasury Department’s Office of Foreign Assets Control, the U.S. Commerce Department’s Bureau of Industry and Security, the U.S. Customs and Border Protection and other U.S. and non-U.S. laws and regulations governing the international trade of goods, services and technology. Such regulations regarding exports and imports of covered goods or dealings with sanctioned countries, persons or entities include licensing, recordkeeping and reporting requirements. Failure to comply with applicable laws and regulations relating to customs, tariffs, sanctions and export controls may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets. For more information, see Item 1A— “Risk Factors — 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.” We are also subject to regulation by numerous other regulatory agencies, including, but not limited to, the U.S. Department of Labor, which sets employment practice standards for workers. In addition, we are subject to certain requirements to contribute to retirement funds or other benefit plans, and laws in some jurisdictions restrict our ability to dismiss employees. 13 We monitor our compliance with applicable governmental rules and regulations in each country of operation. We have made and will continue to make the required expenditures to comply with current and future regulatory requirements. We do not anticipate that compliance with currently applicable rules and regulations and required controls will significantly change our competitive position, capital spending or earnings during 2021. We believe we are in material compliance with applicable rules and regulations and, to date, the cost of such compliance has not been material to our business or financial condition. However, future events such as additional laws and regulations, changes in existing laws and regulations or their interpretation or more vigorous enforcement policies of regulatory agencies, may require additional expenditures by us, which may be material. Specifically, 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. Accordingly, there can be no assurance that we will not incur significant compliance costs in the future. See Item 1A— “Risk Factors — Failure to comply with or changes to governmental and environmental laws could adversely affect our business.” Sustainability We marked our 100 year anniversary in 2020 in a cyclical industry that at times has proven to be highly volatile. Much planning and work goes into our Company by all its employees, both past and present, to ensure our sustainability. The Company continues to refine its comprehensive sustainability strategy rooted in our core value to "do the right thing," as discussed under "— Human Capital Objectives and Programs — Core Values and Culture." This strategy uses data to better understand our impacts in areas like emissions, diversity, and safety so we can make any necessary improvements. Improving Lives Through Affordable and Responsible Energy We believe affordable and responsible energy improves lives globally. With a focus on leading-edge technology, we strive to deliver industry-leading efficiency, safety, and value while continuing to reduce the environmental impact of our solutions. Energy has been essential to human life, but the forms of energy that have been relied on have evolved over time. People have relied upon and harnessed energy from resources like fire, water, wind, horsepower, fossil fuels, nuclear, solar, and more, with each having its own unique societal benefits and costs. At a certain point, the continued growth of the world’s population highlighted a need to capture more concentrated forms of energy, making a reliance on fossil fuels increasingly central. Over the last several decades, those responsible for producing fossil fuels gained more expertise and became more specialized. A “service sector” developed to supply the most scientific and technologically specialized needs of the oil and gas sector. We provide highly specialized services in this narrow segment of the very broad and constantly evolving energy sector. We continue to innovate in an effort to increase efficiency for our customers and provide continued societal benefits with less impact to the environment. Focused on Safer and More Efficient Drilling We design, build and operate rigs that make drilling for oil and gas safer and more efficient. Focused on the drilling segment of the oil and gas production value chain, we provide the expertise, technology and equipment to drill oil and gas wells for our customers - the exploration and production ("E&P") companies. Our E&P customers then determine if and when to extract those resources from the ground, following completion of the well. H&P and the Fossil Fuel Value Chain While we do play an important role in helping our customers make overall production as safe and efficient as possible, our most critical responsibility is ensuring the safety of our employees and the employees of our customers. Although many of the environmental and safety risks associated with the oil and gas sector fall outside of our operations, we remain committed to utilizing our expertise and advancing our technologies to aid our customers in minimizing personal and environmental risks and maximizing industry sustainability efforts. Below is a description of the roles that H&P plays, in the oil and gas value chain, as a drilling solutions provider in comparison to the roles that participants in other sectors of the oil and gas industry play. H&P: build and renovates drilling rigs at two industrial facilities in Texas and Oklahoma; oversees drilling operations on its rigs on customer sites; drills predominantly on-shore in the United States (88 percent of available rigs are on onshore); • makes drilling for oil safer and more efficient; • • • • makes significant and impactful investments in research and development and new technologies; • • employs over 4,100 people; and provides robust benefit plans to protect the physical and financial health of its valued employees. 14 Other Sectors of the Oil and Gas Industry: • • • • • • • buy, lease, prepare, manage or restore land or are responsible for the protection of wildlife on or biodiversity of property; engage in hydraulic fracturing; pump oil or gas from the ground; procure, transport or pump water underground, or treat or remove wastewater from the site, or arrange for its disposal; assume responsibility for the prevention of fugitive releases or emissions associated with the oil and gas production process; engage in oil and gas transport, refining or storage; and engage in downstream operations. Human Capital For a description of our recruiting practices, education and training for employees, and employee benefits, see "— Human Capital Programs and Objectives" above. 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 Securities and Exchange Commission ("SEC"). The information contained on our website, or accessible from our website, is not incorporated into, and should not be considered part of, this Form 10 K or any other documents we file with, or furnish to, the SEC. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Annual reports, quarterly reports, current reports, amendments to those reports, earnings releases, financial statements and our various corporate governance documents are also available free of charge upon written request. Investors and others should note that we announce material financial information to our investors using our investor relations website (https://helmerichandpayneinc.gcs-web.com/), SEC filings, press releases, public conference calls and webcasts. We use these channels as well as social media to communicate with our stockholders and the public about our company, our services and other issues. It is possible that the information we post on social media could be deemed to be material information. Therefore, we encourage investors, the media, and others interested in our company to review the information we post on the social media channels listed on our investor relations website. 15 Item 1A. RISK FACTORS An investment in our securities involves a variety of risks. In addition to the other information included and incorporated by reference in this Form 10-K and the risk factors discussed elsewhere in this Form 10-K, 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. Business and Operating Risks The impact and effects of public health crises, pandemics and epidemics, such as the ongoing outbreak of COVID-19, have adversely affected and are expected to continue to adversely affect our business, financial condition and results of operations. Public health crises, pandemics and epidemics, such as the ongoing outbreak of COVID-19, have adversely impacted and are expected to continue to adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our services. Fear of such events has also altered the level of capital spending by oil and gas companies for exploration and production activities and adversely affected the economies and financial markets of many countries (or globally), resulting in an economic downturn that has affected demand for our services. For instance, the outbreak of COVID-19 and its development into a pandemic has caused governmental authorities in many countries in which we operate to impose mandatory closures, seek voluntary closures and impose restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions. Among other matters, these actions have resulted in our "remote work" model for office personnel and the quarantine of some of our personnel, which, in turn, has caused the inability or unwillingness of certain personnel to access our offices, rigs or customer facilities and could decrease organizational effectiveness. Governmental authorities have also implemented multi-step policies with the goal of re-opening various sectors of the economy. However, certain jurisdictions began re-opening only to return to restrictions in the face of increases in new COVID-19 cases, while other jurisdictions are continuing to re-open or have nearly completed the re-opening process despite increases in COVID-19 cases. The COVID-19 outbreak may significantly worsen during the upcoming months, which may cause governmental authorities to reconsider restrictions on business and social activities. In the event governmental authorities increase restrictions, the re-opening of the economy may be further curtailed. We have experienced, and expect to continue to experience, some resulting disruptions to our business operations, as these restrictions have significantly impacted, and may continue to impact, many sectors of the economy. In addition, the perceived risk of infection and health risk associated with COVID-19, and the illness of many individuals across the globe, has resulted in many of the same effects intended by such governmental authorities to stop the spread of COVID-19. Further, in early March 2020, the increase in crude oil supply resulting from production escalations from OPEC+ combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Although OPEC+ subsequently agreed to cut oil production and has extended such production cuts through December 2020, crude oil prices remain depressed as a result of an increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. These events have had, and could continue to have, an adverse impact on numerous aspects of our business, financial condition and results of operations, including, but not limited to, our growth, costs, labor or equipment shortages, logistics constraints, customer demand for our services and industry demand generally, capital spending by oil and gas companies, our liquidity, the price of our securities and trading markets with respect thereto, our ability to access capital markets, asset impairments and other accounting changes, certain of our customers experiencing bankruptcy or otherwise becoming unable to pay vendors, including us, and the global economy and financial markets generally. The ultimate extent of the impact of COVID-19 on our business, financial condition and results of operations will depend largely on future developments, including the duration and spread of the outbreak within the United States and the parts of the world in which we operate and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the development and availability of effective treatments and vaccines, all of which are highly uncertain and cannot be predicted with certainty at this time. 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. The sharp decline in oil prices resulting from the COVID-19 outbreak and the activities of OPEC+ has caused a significant decline in both drilling activity and prices for our services, which has had and is expected to continue to have a material adverse effect on our business, financial condition and results of operations. 16 Oil and natural gas prices and production levels, as well as market expectations regarding such prices and production levels, have been volatile, which has had, and may in the future have, adverse effects on our business and operations. The volatility in prices and production levels 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 availability of and constraints in storage and transportation capacity, including, for example, concerns regarding storage availability that has been exacerbated by the significant reduction in demand and corresponding oversupply of oil and natural gas as a result of the global COVID-19 pandemic, as well as takeaway constraints experienced in the Permian Basin over the past several years; the worldwide economy; expectations about future oil and natural gas prices and production levels; local and international political, economic, health and weather conditions, especially in oil and natural gas producing countries, including, for example, the impacts of local and international pandemics and other disasters or events such as the global COVID-19 pandemic; actions of 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; 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, as well as our customers' ability to access sources of capital to fund their operating and capital expenditures. However, a sustained decline in worldwide demand for oil and natural gas, as well as excess supply of oil or natural gas coupled with storage and transportation capacity constraints, shutting in of wells or wells being drilled but not completed, prolonged low oil or natural gas prices or a reduction in the ability of our customers to access capital, has resulted in, and may in the future result in, reduced exploration and development of land and offshore areas and a decline in the demand for our services, which has had, and may in the future, 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 and could 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. 17 The drilling services and solutions business is highly competitive, and a surplus of available drilling rigs may adversely affect our rig utilization and profit margins. Competition in drilling services and solutions 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. In addition, development of new drilling technology by competitors has increased in recent years, which could negatively affect our ability to differentiate our services. We periodically seek to increase the prices on our services to offset rising costs, earn returns on our capital investment and otherwise 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. Following periods of downturn in our industry, 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, which could have a material adverse effect on our business, financial condition and results of operations. As of September 30, 2020, 223 of our available rigs were not under contract. Further, as a result of the significant reduced demand for oil and natural gas services due to the global COVID-19 pandemic, certain of our competitors may engage in bankruptcy proceedings, debt refinancing transactions, management changes, or other strategic initiatives in an attempt to reduce operating costs to maintain a position in the market. This could result in such competitors emerging with stronger or healthier balance sheets and in turn an improved ability to compete with us in the future. We may also see corporate consolidations among our competitors, which could significantly alter industry conditions and competition within the industry, and have a material adverse effect on our business, financial condition and results of operations. New technologies may cause our drilling methods and equipment to become less competitive 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 • successfully improve our financial condition, results of operations, business or prospects as a result of improving existing drilling rigs or building new drilling rigs. 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. 18 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, equipment failure, pollution, and reservoir damage. These hazards could cause significant environmental and reservoir 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 Gulf of Mexico 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 Gulf of Mexico 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, we may experience disruptions in operations due to damage to customer platforms and other related facilities in the area. We also lease a fabrication facility near the Houston, Texas ship channel, 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, subcontractors, 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. 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. In addition, 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. In some cases, we self-insure large deductibles on certain insurance policies. 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. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage. 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 insurance coverage will continue to be available at rates considered reasonable or that our coverage will respond to a specific loss. In addition, our insurance may not cover losses associated with pandemics such as the COVID-19 pandemic. 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. 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. 19 Our business is subject to cybersecurity risks. Our operations depend on effective and secure information technology systems. Threats to information technology systems, including as a result of cyberattacks 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 intellectual property or theft of our FlexRig® and other sensitive or proprietary technology, loss or damage to our data delivery systems, or other cybersecurity and infrastructure systems, including our property and equipment. In response to the COVID-19 pandemic, the Company moved to a "remote work" model for office personnel in March 2020. This model has significantly increased the use of remote networking and online conferencing services that enable employees to work outside of our corporate infrastructure and, in some cases, use their own personal devices. This has resulted in increased demand for information technology resources and exposes the Company to additional cybersecurity risks, including unauthorized access to sensitive information as a result of increased remote access and other cybersecurity related incidents. 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 procedures 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. Further, as cyber incidents continue to evolve, we may be required to incur additional costs to continue to modify or enhance our protective measures or to investigate or remediate the effects of cyber incidents. 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. These strategic transactions, among others, are intended to (but may not) result in the realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or income, or the reduction of risk. Acquisition transactions may use cash on hand or be financed by additional borrowings or by the issuance of our common stock. These transactions may also affect our liquidity, consolidated results of operations and consolidated financial condition. These transactions also involve risks, and we cannot ensure that: • • • • • • • any acquisitions we attempt will be completed on the terms announced, or at all; any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated benefits; any acquisitions would be successfully integrated into our operations and internal controls; the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, 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, 2020, we had goodwill of $45.7 million and other intangible assets, net of $81.0 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. 20 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. 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. Similarly, we utilize highly skilled personnel in operating and supporting our businesses and in developing new technologies. In times of high utilization, it can be difficult to find and retain qualified individuals and, during the recent period of sustained declines in oil and natural gas prices, there have been reductions in the oil field services workforce, both of which could result in higher labor costs. The loss of members of management or the inability to attract and retain qualified personnel could have a material adverse effect on our business, financial condition and results of operations. In addition, the unexpected loss of members of management, qualified personnel or a significant number of employees due to disease, including COVID-19, disability, or death, could have a detrimental effect on us. 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 2020, we received approximately 46 percent of our consolidated operating revenues from our ten largest drilling services and solutions 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 drilling services and solutions revenue may continue to decline and may not be ultimately realized as fixed term contracts and 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, 2020, our drilling services backlog was approximately $0.7 billion for future revenues under firm commitments. Our 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. 21 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 solutions 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 drilling services operating expense includes fixed costs that may not decline in proportion to decreases in rig utilization and dayrates. Our drilling services operating 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 drilling services and solutions expense, which could have a material adverse impact on our business, financial condition and results of operations. We depend on a limited number of vendors, some of which are thinly capitalized, and the loss of any of which could disrupt our operations. Certain key rig components, parts and equipment are either purchased from or fabricated by a single or limited number of vendors, and we have no long term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply, the acquisition of a vendor by a competitor, increased demands in the industry or other reasons beyond our control. Similarly, certain key rig components, parts and equipment are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from us or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, downturn in the energy industry or reduction or unavailability of credit. If we are unable to procure certain of such rig components, parts or equipment, our ability to maintain, improve, upgrade or construct drilling rigs could be impaired, which could have a material adverse effect on our business, financial condition and results of operations. Shortages of drilling equipment and supplies could adversely affect our operations. The drilling services and solutions business is highly cyclical. During periods of increased demand for drilling services and solutions and periods of supply chain disruption, including as a result of COVID-19, 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 drilling services and solutions 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. For example, worker strikes of short duration are common in Argentina and our operations have experienced such strikes in the past. 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. 22 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 (primarily Argentina and Colombia) 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, 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 September 2020. As a result of these currency controls, our ability to remit funds from our Argentine subsidiary to its U.S. parent has been limited. 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 2020, we experienced aggregate foreign currency losses of $7.6 million in Argentina. Our aggregate foreign currency losses across all of our operations for fiscal years 2020 and 2019 were $8.8 million and $8.2 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. 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. 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. Financial Risks 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. 23 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 2020 and 2019, we recognized impairment charges of $563.2 million and $224.3 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.” 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, including the impact of COVID-19. 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 oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health or market perceptions of the drilling and overall oil and gas industry, the liquidity of the capital markets and other factors, including the impact of COVID-19. 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, which, if successful, could limit our ability to access capital markets. Many of the factors that affect our ability to access capital markets are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations. Our marketable securities may lose significant value due to credit, market and interest rate risks. At September 30, 2020, we had marketable securities, primarily consisting of equity in Schlumberger, Ltd., with a total fair value of approximately $7.3 million. The total fair value of the security was $16.3 million at September 30, 2019. At November 12, 2020, the fair value increased to approximately $8.1 million. The value of this investment is subject to general credit, liquidity, market and interest rate risks, which may be exacerbated by unusual events, such as the COVID-19 pandemic. A further significant loss in value of the investment would negatively impact our debt ratio and financial strength. 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. 24 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 (as defined herein), 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 the United States, the Alternative Reference Rates Committee has proposed the Secured Overnight Financing Rate ("SOFR") as an alternative to LIBOR for use in contracts that are currently indexed to U.S. dollar LIBOR and has proposed a paced market transition plan to SOFR. It is not presently known whether SOFR or any other alternative reference rates that have been proposed will attain market acceptance as replacements of LIBOR. 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. Legal and Regulatory Risks 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 customers' products and services. 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 United States 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. The U.S. President announced the United States planned to withdraw from the Paris Agreement in June 2017. This withdrawal formally took effect November 4, 2020. The terms and timeline under 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 wildfires, 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. 25 It is not possible at this time to predict the timing and effect of climate change or to predict the timing or effect of rejoining 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, additional operating restrictions or affect the demand for our customers' products and, accordingly, our services. For example, a coalition of over 20 governors of U.S. states formed the United States Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have committed to advance the objectives of the Paris Agreement at the state or local level despite the federal withdrawal. To this end, the California governor issued an executive order on September 23, 2020 ordering actions to pursue GHG emissions reductions, including a direction to the California State Air Resources Board to develop and propose regulations to require increasing volumes of new zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the sale of new gasoline vehicles by 2035. 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 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.” 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 are analyzing, and a number of federal agencies have historically been requested to review, and, under a new administration, may be requested to review again, a variety of environmental issues associated with hydraulic fracturing and the possibility of more stringent regulation. At September 30, 2020, we had approximately 15 rigs placed on federal land and eight rigs in federal waters. 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. 26 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 non-U.S. 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. In addition, investors could negatively view potential violations, inquiries or allegations of misconduct under the FCPA or similar laws, which could adversely affect our reputation and the market for our shares. 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. 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. Moreover, many countries, including the United States, control the import and export of certain goods, services and technology and impose related import and export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. In particular, U.S. sanctions are targeted against certain countries that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities. 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. The laws and regulations concerning import and export activity, recordkeeping and reporting, including customs, export controls and economic sanctions, are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Ongoing economic challenges may increase some governments’ efforts to enact, enforce, amend or interpret laws and regulations as a method to increase revenue. Shipments can be delayed and denied import or export for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal or regulatory requirements governing international trade could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges. 27 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. Our ownership and use of proprietary technology and equipment could also result in infringement of intellectual property claims against us. See above “— Technology disputes could negatively impact our operations or increase our costs." 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. Further, actions or decisions we have taken or may take as a consequence of COVID-19 may result in investigations, litigation or legal claims 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. Additional tax liabilities and/or our significant net deferred tax liability could affect our financial condition, income tax provision, net income, and cash flows. 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. Additionally, our future effective tax rates could be adversely affected by changes in tax laws (including tax treaties) or their interpretation. Our deferred tax liability associated with property, plant and equipment is significant, which could materially increase the amount of cash income taxes that we pay in the future and, thus, adversely affect our cash flows. Our future capital expenditures, our results of operations and changes in income tax laws could significantly impact the timing of the reversal of our deferred tax liabilities and the timing and amount of our future cash income taxes. While management intends to minimize our income taxes payable in future years to the extent possible, the amount and timing of cash income taxes ultimately paid are based on the aforementioned factors as well as others and are subject to change. 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. 28 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. Risks Related to Our Common Stock and Corporate Structure 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 $0.25 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 or uncertainty, such as the current downturn as a result of the COVID-19 outbreak and the oil price collapse in 2020. 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. 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 or financial 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; 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; increased focus by the investment community on sustainability practices at our company and in the oil and natural gas industry generally; 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. Certain provisions of our corporate governing documents could make an acquisition of our company more difficult. The following provisions of our charter documents, as currently in effect, and Delaware law could discourage potential proposals to acquire us, delay or prevent a change in control of us or limit the price that investors may be willing to pay in the future for shares of our common stock: • • our certificate of incorporation permits our Board of Directors to issue and set the terms of preferred stock and to adopt amendments to our bylaws; our bylaws contain restrictions regarding the right of stockholders to nominate directors and to submit proposals to be considered at stockholder meetings; our bylaws restrict the right of stockholders to call a special meeting of stockholders; and • • we are subject to provisions of Delaware law which restrict us from engaging in any of a broad range of business transactions with an “interested stockholder” for a period of three years following the date such stockholder became classified as an interested stockholder. 29 Item 1B. UNRESOLVED STAFF 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 2020 and that remain unresolved. Item 2. PROPERTIES Drilling Services and Solutions 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 — Drilling Fleet.” 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 and undeveloped real estate. Item 3. LEGAL PROCEEDINGS See Note 17—Commitments and Contingencies to our Consolidated Financial Statements for information regarding our legal proceedings. Item 4. MINE SAFETY DISCLOSURES Not applicable. 30 PART II Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Market Information and Dividends The principal market on which our common stock is traded is the New York Stock Exchange under the symbol “HP.” As of November 12, 2020, there were 425 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 $72.94 $58.05 $64.51 $52.15 $44.95 $48.05 $48.40 $45.54 $47.15 $36.36 $36.40 $0.71 $0.71 $0.71 $0.71 $0.71 $28.29 $0.71 $12.80 $14.24 $20.48 $13.48 $0.25 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 Stock price low Stock price high Dividend 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 Dow Jones U.S. Select Oil Equipment & Services Index PHLX Oil Service Index Base Period INDEXED RETURNS Years Ending Sep 2015 Sep 2016 Sep 2017 Sep 2018 Sep 2019 Sep 2020 100.00 100.00 100.00 100.00 148.00 122.00 163.00 109.00 60.00 115.00 136.00 159.00 166.00 189.00 110.00 102.00 105.00 106.00 94.00 100.00 55.00 48.00 27.00 25.00 31 $200 $150 $100 $50 $0 Sep 15 Comparison of Cumulative Five Year Total Return Sep 16 Sep 17 Sep 18 Sep 19 Sep 20 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 — Liquidity and Capital Resources — Investing Activities — Marketable Securities” included in this Form 10 K. 32 Item 6. SELECTED FINANCIAL DATA The following table summarizes selected financial information and should be read in conjunction with Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8— “Financial Statements and Supplementary Data” included in this Form 10 K. (in thousands except per share amounts) 2020 2019 2018 2017 2016 Five year Summary of Selected Financial Data Statements of Operations Selected Data Operating revenues Depreciation and amortization Selling, general and administrative Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) Per Share Data $ 1,773,927 $ 2,798,490 $ 2,487,268 $ 1,804,741 $ 1,624,332 481,885 167,513 (496,392) 1,895 (494,497) 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) Basic earnings (loss) per share from continuing operations Basic earnings (loss) per share from discontinued operations Basic earnings (loss) per share Diluted earnings (loss) per share from continuing operations Diluted earnings (loss) per share from discontinued operations Diluted earnings (loss) per share Cash dividends declared per common share $ $ $ $ $ Balance Sheet Data (4.62) $ (0.33) $ 4.49 $ (1.20) $ (0.50) 0.02 (0.01) (0.10) — (4.60) $ (0.34) $ 4.39 $ (1.20) $ (0.04) (0.54) (4.62) $ (0.33) $ 4.47 $ (1.20) $ (0.50) 0.02 (4.60) 2.38 $ $ (0.01) (0.34) 2.84 $ $ (0.10) 4.37 2.82 $ $ — (1.20) $ (0.04) (0.54) 2.80 $ 2.78 Cash, cash equivalents and short-term investments $ 577,219 $ 400,903 $ 325,816 $ 565,866 $ 949,709 Property, plant and equipment, net Total assets (1) Total debt (2) Total shareholders' equity Debt to capital ratio (3) Net debt to net capital ratio (4) Net working capital (5) 3,646,341 4,829,621 487,148 3,318,514 4,502,084 5,839,515 487,148 4,857,382 6,214,867 500,000 5,001,051 6,439,988 500,000 5,144,733 6,832,019 500,000 4,012,223 4,382,735 4,164,591 4,560,925 12.8 % (2.7)% 10.8% 2.1% 10.2% 3.8% 10.7 % (1.6)% 9.9 % (9.9)% $ 194,198 $ 381,708 $ 490,663 $ 401,499 $ 368,965 (1) Total assets for all years include amounts related to discontinued operations. Our Venezuelan subsidiary was classified as discontinued operations on June 30, 2010, after the seizure of our drilling assets in that country by the Venezuelan government. (2) Total debt excludes unamortized discount and debt issuance cost. Refer to Note 8—Debt. (3) The debt to capital ratio is calculated by dividing total debt by total capitalization (total debt, excluding unamortized discount and debt issuance cost, 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 debt to net capital ratio is calculated as the excess of our total debt over total cash, cash equivalents and short-term investments divided by total shareholders' equity plus any positive net debt balances. The net debt to net 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. (5) For the purpose of understanding the impact on our Cash Flow from Operations, net working capital is calculated as current assets, excluding cash and short-term investments, less current liabilities, excluding dividends payable, short–term debt and the current portion of long–term debt. Net working capital 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. 33 Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with Part I of this Form 10 K as well as the Consolidated Financial Statements and related notes thereto included in Item 8— “Financial Statements and Supplementary Data” of this Form 10 K. Our future operating results may be affected by various trends and factors which are beyond our control. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Form 10-K 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. (“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. As of September 30, 2020, our drilling rig fleet included a total of 302 drilling rigs. Our drilling services and solutions segments consist of the North America Solutions segment with 262 rigs, the Offshore Gulf of Mexico segment with eight offshore platform rigs and the International Solutions segment with 32 rigs as of September 30, 2020. At the close of fiscal year 2020, we had 79 contracted rigs, of which 56 were under a fixed-term contract and 23 were working well-to-well, compared to 218 contracted rigs at September 30, 2019. 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, technology offerings, financial strength, contract backlog and strong customer and employee base position us very well to respond to continued volatile market conditions and 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”). Generally, 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 North America Solutions, 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 and the type of rig utilized in the U.S. land drilling industry. The advent of unconventional drilling for oil 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 to the market new technology AC drive rigs (FlexRig®), 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 United States 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. The technical requirements of drilling longer lateral wells often necessitate the use of super-spec rigs and even when not required for shorter lateral wells, there is a strong customer preference for super-spec due to the drilling efficiencies gained in utilizing a super-spec rig. As a result, there has been a structural decline in the use of non-super-spec rigs across the industry. However, as a result of having a large super-spec fleet, we gained market share and became the largest provider of super-spec rigs in the industry. As such, we believe we are well positioned to respond to various market conditions. In early March 2020, the increase in crude oil supply resulting from production escalations from the Organization of the Petroleum Exporting Countries and other oil producing nations ("OPEC+") combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Since the beginning of the calendar year 2020, crude oil prices fell from approximately $60 per barrel to the low-to-mid-$20 per barrel range, lower in some cases. Consequently, we have seen a significant decrease in customer 2020 capital budgets representing a decline of nearly 50% from calendar year 2019 levels. There has been a corresponding dramatic decline in the demand for land rigs, such that the overall rig count for calendar year 2020 will average significantly less than in calendar year 2019. 34 During calendar year 2020, our North American Solutions rig count has declined from 195 contracted rigs at December 31, 2019 to 69 contracted rigs at September 30, 2020. Of the 69 contracted rigs at September 30, 2020, 58 are active with 11 stacked. When contracted rigs are stacked, they remain under the terms of the contract but typically pay a reduced rate, where the remaining term days are generally not reduced, but our operating expenses are typically reduced. We experienced much of our rig count decline during our second and third fiscal quarters with the absolute level of our rigs remaining relatively stable during the fourth fiscal quarter. Additionally, during our fourth fiscal quarter, the market experienced a stabilization of crude oil prices in the $40 per barrel range. At such levels, we believe our customers will have more robust capital budgets entering into 2021 and are already seeing evidence of this in our near-term rig count activity projections. Consequently, we believe we will experience a higher level of rig activity in fiscal year 2021 compared to where we stand today. However, given the current levels of commodity prices and the lasting impacts of the global pandemic, we do not expect or anticipate customers' capital budgets will support activity levels like those experienced prior to March 2020. Utilization for our super-spec FlexRig® fleet peaked in late calendar year 2018 with 216 of 221 super-spec rigs working (98 percent utilization); however, the recent decline in the demand for land rigs resulted in customers idling a large portion of our super-spec FlexRig® fleet. At September 30, 2020, we had 167 idle super-spec rigs out of our FlexRig® fleet of 234 super-spec rigs (29% percent utilization). Collectively, our other business segments, Offshore Gulf of Mexico and International Solutions, are exposed to the same macro environment adversely affecting our North America Solutions segment and those unfavorable factors are creating similar challenges for these business segments as well. H&P recognizes the uncertainties and concerns caused by the COVID-19 pandemic; however, we have managed the Company over time to be in a position of strength both financially and operationally when facing uncertainties of this magnitude. The COVID-19 pandemic has had an indirect, yet significant financial impact on the Company. The global response to coping with the pandemic has resulted in a drop in demand for crude oil, which, when combined with a more than adequate supply of crude oil, has resulted in a sharp decline in crude oil prices, causing our customers to have pronounced pullbacks in their operations and planned capital expenditures. The direct impact of COVID-19 on H&P's operations has created some challenges that we believe the Company is adequately addressing to ensure a robust continuation of our operations albeit at a lower activity level. The Company is an ‘essential critical infrastructure’ company as defined by the Department of Homeland Security and the Cybersecurity and Infrastructure Security Agency and, as such, continues to operate rigs and technology solutions, providing valuable services to our customers in support of the global energy infrastructure. The health and safety of all H&P stakeholders - our employees, customers, and vendors - remain a top priority at the Company. Accordingly, H&P has implemented additional policies and procedures designed to protect the well-being of our stakeholders and to minimize the impact of COVID-19 on our ongoing operations. Some of the safeguards we have implemented include: The Company mobilized a global COVID-19 response team to manage the evolving situation The Company moved to a global "remote work" model for office personnel (beginning March 13, 2020) The Company suspended all non-essential travel • • • • We are adhering to Center for Disease Control ("CDC") guidelines for evaluating actual and potential COVID-19 exposures Operational and third-party personnel are required to complete a COVID-19 questionnaire prior to reporting to a field location and office personnel are required to complete one prior to returning to their respective offices in order to evaluate actual and potential COVID-19 exposures and individuals identified as being high risk are not allowed on location The temperatures of operational personnel are taken prior to them being allowed to enter a rig site The Company has implemented enhanced sanitization and cleaning protocols • We are complying with local governmental jurisdiction policies and procedures where our operations reside; in some instances, policies and procedures are more stringent in our foreign operations than in our North America operations and this has resulted in a complete suspension, for a certain period of time, of all drilling operations in at least one foreign jurisdiction As of September 30, 2020, the Company was aware that 109 out of its approximately 4,100 employees have had confirmed cases of COVID-19 since the COVID-19 outbreak began, of which we believe approximately 52% contracted the virus outside of their work location. We have had no fatalities and 100 of 109 employees who had confirmed cases have returned to work. Upon being notified that an employee has tested positive, the Company follows pre-established guidelines and places the employee on leave as appropriate. Per CDC Guidelines, employees testing positive are permitted to return to their worksite after 10 days. Employees who are considered a Level 1 exposure but who have not tested positive are required to quarantine and are permitted to return to their worksite after 14 days. In addition, the Company applies its enhanced sanitization procedures to the employee’s work location prior to allowing employees to re-enter the location. Since the COVID-19 outbreak began, no rigs have been fully shut down (other than temporary shutdowns for disinfecting) and such measures to disinfect facilities have not had a significant impact on service. We believe our service levels are unchanged from pre-pandemic levels. 35 From a financial perspective we believe the Company is well positioned to continue as a going concern even through a more protracted disruption caused by COVID-19. We have taken measures to reduce costs and capital expenditures to levels that better reflect a lower activity environment. Actions taken during the second quarter of fiscal year 2020 included a reduction to the annual dividend of approximately $200 million, a reduction in planned fiscal year 2020 capital spend of $95 million, and a reduction of over $50 million in fixed operational overhead. During the third quarter of fiscal year 2020, the Company took further steps to reduce its planned fiscal year 2020 capital spend by another $40 million and its selling, general and administrative cost structures by another $25 million on an annualized basis. The culmination of these cost-saving initiatives resulted in a $16.0 million restructuring charge during fiscal year 2020. We anticipate further cost reductions in our International Solutions operations as well and are working through local jurisdictional regulations to implement those measures. At September 30, 2020, the Company had cash and cash equivalents and short-term investments of $577.2 million and availability under the 2018 Credit Facility (as defined herein) of $750.0 million resulting in approximately $1.3 billion in near-term liquidity. We currently do not anticipate the need to draw on the 2018 Credit Facility. As part of the Company's normal operations, we regularly monitor the creditworthiness of our customers and vendors, screening out those that we believe have a high risk of failure to honor their counter-party obligations either through payment or delivery of goods or services. We also perform routine reviews of our accounts receivable and other amounts owed to us to assess and quantify the ultimate collectability of those amounts. At September 30, 2020, the Company had a net allowance against its accounts receivable of $1.8 million and incurred bad debt expense of $2.2 million during fiscal year 2020. Subsequent to March 31, 2020, we adjusted our credit risk monitoring for specific customers, in response to the recent economic events described above. The nature of the COVID-19 pandemic is inherently uncertain, and as a result, the Company is unable to reasonably estimate the duration and ultimate impacts of the pandemic, including the timing or level of any subsequent recovery. As a result, the Company cannot be certain of the degree of impact on the Company’s business, results of operations and/or financial position for future periods. Recent Developments Restructuring Beginning in the third quarter of fiscal year 2020, we implemented cost controls and began evaluating further measures to respond to the combination of weakened commodity prices, uncertainties related to the COVID-19 pandemic, and the resulting market volatility. We restructured our operations to accommodate scale during an industry downturn and to re-organize our operations to align to new marketing and management strategies. We commenced a number of restructuring efforts as a result of this evaluation, which included, among other things a reduction in our capital allocation plans, changes to our organizational structure, and a reduction of staffing levels. Refer to Note 19—Restructuring Charges to our Consolidated Financial Statements. Business Segments During the third quarter of fiscal year 2020, as part of our restructuring efforts (see Note 19—Restructuring Charges to our Consolidated Financial Statements) and consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, we implemented organizational changes. We are moving from a product-based offering, such as a rig or separate technology package, to an integrated solution-based approach by combining proprietary rig technology, automation software, and digital expertise into our rig operations. Operations previously reported within the former U.S. Land and H&P Technologies operating and reportable segments are now managed and presented within the North America Solutions reportable segment. As a result, beginning with the third quarter of fiscal year 2020, our drilling services operations are organized into the following reportable operating business segments: North America Solutions, Offshore Gulf of Mexico and International Solutions. All prior period segment disclosures have been recast for these segment changes. Our real estate operations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are included in "Other." Consolidated revenues and expenses reflect the elimination of intercompany transactions. 36 Self-Insurance On October 1, 2019, we elected to utilize a wholly-owned insurance captive (“Captive”) to insure the deductibles for our workers’ compensation, general liability and automobile liability insurance programs. Casualty claims occurring prior to October 1, 2019 will remain recorded within each of the operating segments' and future adjustments to these claims will continue to be reflected within the operating segments. Reserves for legacy claims occurring prior to October 1, 2019, will remain as liabilities in our operating segments until they have been resolved. Changes in those reserves will be reflected in segment earnings as they occur. We will continue to utilize the Captive to finance the risk of loss to equipment and rig property assets. The Company and the Captive maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of significant events covered under these programs. Our operating subsidiaries are paying premiums to the Captive, typically on a monthly basis, for the estimated losses based on an external actuarial analysis. These premiums are currently held in a restricted account, resulting in a transfer of risk from our operating subsidiaries to the Captive. The actuarial estimated underwriting expenses for the fiscal year ended September 30, 2020 were approximately $16.4 million and were recorded within drilling services operating expenses in our Consolidated Statement of Operations. Intercompany premium revenues and expenses during the fiscal year ended September 30, 2020 amounted to $36.9 million, which were eliminated upon consolidation. These intercompany insurance premiums are reflected as segment operating expenses within the North America Solutions, Offshore Gulf of Mexico, and International Solutions reportable operating segments and are reflected as intersegment sales within "Other." The Company self-insures employee health plan exposures in excess of employee deductibles. Starting in the second quarter of fiscal year 2020, the Captive insurer issued a stop-loss program that will reimburse the Company's health plan for claims that exceed $50,000. This program will also be reviewed at the end of each policy year by an outside actuary. One hundred percent of the stop- loss premium is being set aside by the Captive as reserves. The stop-loss program does not have a material impact on a consolidated basis. Dispositions During the fiscal year ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including six industrial sites, for total consideration, net of selling related expenses, of $40.7 million and an aggregate net book value of $13.5 million, resulting in a gain of $27.2 million, which is included within Gain on Sale of Assets on our Consolidated Statement of Operations. In December 2019, we closed on the sale of a wholly-owned subsidiary of Helmerich & Payne International Drilling Co. ("HPIDC"), TerraVici Drilling Solutions, Inc. ("TerraVici"). As a result of the sale, 100% of TerraVici's outstanding capital stock was transferred to the purchaser in exchange for approximately $15.1 million, resulting in a total gain on the sale of TerraVici of approximately $15.0 million. Prior to the sale, TerraVici was a component of the North America Solutions operating segment. This transaction does not represent a strategic shift in our operations and will not have a significant effect on our operations and financial results going forward. Impairments During the second quarter of fiscal year 2020, several significant economic events took place that severely impacted the current demand on drilling services, including the significant drop in crude oil prices caused by OPEC+'s price war coupled with the decrease in the demand due to the COVID-19 pandemic. Property, Plant and Equipment and Inventory During the second quarter of fiscal year 2020, to maintain a competitive edge in a challenging market, the Company’s management introduced a new strategy focused on operating various types of highly capable upgraded rigs and phasing out the older, less capable fleet. This resulted in grouping the super-spec rigs of our legacy Domestic FlexRig® 3 asset group and our FlexRig® 5 asset group creating a new "Domestic super-spec FlexRig®" asset group, while combining the legacy Domestic conventional asset group, FlexRig® 4 asset group and FlexRig® 3 non-super-spec rigs into one asset group (Domestic non-super-spec asset group). Given the current and projected low utilization for our Domestic non- super-spec asset group and all International asset groups, we considered these economic factors to be indicators that these asset groups may be impaired. As a result of these indicators, we performed impairment testing at March 31, 2020 on each of our Domestic non-super- spec and International conventional, FlexRig® 3, and FlexRig® 4 asset groups which had an aggregate net book value of $605.8 million. We concluded that the net book value of each asset group is not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of $441.4 million in the Consolidated Statement of Operations for the fiscal year ended September 30, 2020. Of the $441.4 million total impairment charge recorded, $292.4 million and $149.0 million was recorded in the North America Solutions and International Solutions segments, respectively. Impairment was measured as the amount by which the net book value of each asset group exceeds its fair value. No further impairments were recognized in fiscal year 2020. The most significant assumptions used in our undiscounted cash flow model include timing on awards of future drilling contracts, drilling rig utilization, estimated remaining useful life, and net proceeds received upon future sale/disposition. These assumptions are classified as Level 3 inputs by Accounting Standards Codification ("ASC") Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. 37 In determining the fair value of each asset group, we utilized a combination of income and market approaches. The significant assumptions in the valuation are based on those of a market participant and are classified as Level 2 and Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures. As of March 31, 2020, the Company also recorded an additional non-cash impairment charge related to in-progress drilling equipment and rotational inventory of $44.9 million and $38.6 million, respectively, which had aggregate book values of $68.4 million and $38.6 million, respectively, in the Consolidated Statement of Operations for the fiscal year ended September 30, 2020. Of the $83.5 million total impairment charge recorded for in-progress drilling equipment and rotational inventory, $75.8 million and $7.7 million was recorded in the North America Solutions and International Solutions segments, respectively. Goodwill Consistent with our policy, we test goodwill annually for impairment in the fourth quarter of our fiscal year, or more frequently if there are indicators that goodwill might be impaired. Due to the market conditions described above, during the second quarter of fiscal year 2020, we concluded that goodwill and intangible assets might be impaired and tested the H&P Technologies reporting unit, where the goodwill balance is allocated and the intangible assets are recorded, for recoverability. This resulted in a goodwill only non-cash impairment charge of $38.3 million recorded in Asset Impairment Charge on the Consolidated Statement of Operations during the fiscal year ended September 30, 2020. The recoverable amount of the H&P Technologies reporting unit was determined based on a fair value calculation which uses cash flow projections based on the Company’s financial projections presented to the Board covering a five-year period, and a discount rate of 14 percent. Cash flows beyond that five-year period were extrapolated using the fifth-year data with no implied growth factor. The reporting unit level is defined as an operating segment or one level below an operating segment. The recoverable amount of the intangible assets tested for impairment within the H&P Technologies reporting unit is determined based on undiscounted cash flow projections using the Company’s financial projections presented to the Board covering a five-year period and extrapolated for the remaining weighted average useful lives of the intangible assets. The most significant assumptions used in our cash flow model include timing on awards of future contracts, commercial pricing terms, utilization, discount rate, and the terminal value. These assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. Although we believe the assumptions used in our analysis and the probability-weighted average of expected future cash flows are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and our resulting conclusion. Results of Operations for the Fiscal Years Ended September 30, 2020 and 2019 Consolidated Results of Operations All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Except as specifically discussed, the following results of operations pertain only to our continuing operations. Net Loss We reported a loss from continuing operations of $496.4 million ($4.62 loss per diluted share) from operating revenues of $1.8 billion for the fiscal year ended September 30, 2020 compared to a loss from continuing operations of $32.5 million ($0.33 loss per diluted share) from operating revenues of $2.8 billion for the fiscal year ended September 30, 2019. Included in the net loss for the fiscal year ended September 30, 2020 is income of $1.9 million ($0.02 impact per diluted share) from discontinued operations. Including discontinued operations, we recorded a net loss of $494.5 million ($4.60 loss per diluted share) for the fiscal year ended September 30, 2020 compared to a net loss of $33.7 million ($0.34 loss per diluted share) for the fiscal year ended September 30, 2019. Revenue Consolidated operating revenues were $1.8 billion in fiscal year 2020 and $2.8 billion in fiscal year 2019, including early termination revenue of $73.4 million and $11.3 million in each respective fiscal year. Excluding early termination revenue, operating revenue decreased $1.1 billion in fiscal year 2020 compared to fiscal year 2019. The decrease in fiscal year 2020 from fiscal year 2019 was driven by lower activity and pricing as a result of the collapse in oil prices that occurred in March 2020, which drove our customers to quickly reduce rig activity beginning in the second half of March 2020 and continuing throughout the remainder of fiscal year 2020. Direct Operating Expenses, Excluding Depreciation and Amortization Direct operating expenses in fiscal year 2020 were $1.2 billion, compared with $1.8 billion in fiscal year 2019. The decrease in fiscal year 2020 from fiscal year 2019 was primarily attributable to the previously-mentioned lower activity levels. Depreciation and Amortization Depreciation and amortization expense was $481.9 million in fiscal year 2020 and $562.8 million in fiscal year 2019. The decrease in depreciation and amortization during fiscal year ended September 30, 2020 compared to fiscal year ended September 30, 2019 was primarily attributable to the lower carrying cost of our impaired assets. Depreciation and amortization includes amortization of intangible assets of $7.2 million and $5.8 million in fiscal years 2020 and 2019, respectively, and abandonments of equipment of $4.0 million and $11.4 million in fiscal years 2020 and 2019, respectively. 38 Research and Development For the fiscal years ended September 30, 2020 and 2019, we incurred $21.6 million and $27.5 million, respectively, of research and development expenses. The decrease in expense was primarily due to reduced spending related to the development of rotary steerable system tools given the December 2019 sale of TerraVici. Selling, General and Administrative Expense Selling, general and administrative expenses decreased to $167.5 million in the fiscal year ended September 30, 2020 compared to $194.4 million in the fiscal year ended September 30, 2019. The $26.9 million decrease in fiscal year 2020 compared to fiscal year 2019 is primarily due to lower accrued variable compensation expense and a reduction of staffing levels that was implemented in third quarter of fiscal year 2020. Asset Impairment During the fiscal year ended September 30, 2020, we impaired several assets, including inventory, property, plant and equipment, and goodwill, which resulted in a non-cash impairment charge of $563.2 million ($437.5 million, net of tax, or $5.21 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations. Comparatively, during the fiscal year ended September 30, 2019, mainly driven by the downsizing of our fleet of FlexRig® 4 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 asset impairment charge of $224.3 million ($195.0 million, net of tax, or $1.78 per diluted share) was recorded in our Consolidated Statements of Operations. Restructuring Charges Beginning in the third quarter of fiscal year 2020, we implemented cost controls and began evaluating further measures to respond to the combination of weakened commodity prices, uncertainties related to the COVID-19 pandemic, and the resulting market volatility. We commenced a number of restructuring efforts as a result of this evaluation, which included, among other things, a reduction in our capital allocation plans, changes to our organizational structure, and a reduction of staffing levels. For the fiscal year ended September 30, 2020, we incurred $16.0 million in restructuring charges. Interest and Dividend Income Interest and dividend income was $7.3 million and $9.5 million in fiscal years 2020 and 2019, respectively. The decrease in interest and dividend income in fiscal year 2020 was primarily due to lower interest rates. Interest Expense Interest expense totaled $24.5 million in fiscal year 2020 and $25.2 million in fiscal year 2019. Interest expense is primarily attributable to fixed rate debt outstanding. Income Taxes We had an income tax benefit of $140.1 million in fiscal year 2020 compared to an income tax benefit of $18.7 million in fiscal year 2019. The effective income tax rate was 22.0 percent in fiscal year 2020 compared to 36.5 percent in fiscal year 2019. The effective rates differ from the U.S. federal statutory rate (21.0 percent for fiscal years 2020 and 2019) due to non-deductible permanent items, state and foreign income taxes, and adjustments to the deferred state income tax rate. 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 9—Income Taxes to our Consolidated Financial Statements for additional income tax disclosures. Discontinued Operations Expenses incurred within the country of Venezuela are reported as discontinued operations. Our wholly-owned subsidiaries, HPIDC and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. 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. In March 2016, the Venezuelan government implemented the previously announced plans for a new foreign currency exchange system. Activity within discontinued operations for both fiscal years 2020 and 2019 is primarily a result of the impact of exchange rate fluctuations due to the remeasurement of uncertain tax liabilities. 39 North America Solutions The following table presents certain information with respect to our North America Solutions reportable segment: (in thousands, except operating statistics) Operating revenues Direct operating expenses Depreciation Research and development Selling, general and administrative expense Asset impairment charge Restructuring charges Segment operating income (loss) Operating Statistics (2): Revenue days Average rig revenue per day (3) Average rig expense per day (3) Average rig margin per day (3) Number of rigs at the end of period Rig utilization 2020 2019 (1) % Change $ 1,474,380 $ 2,426,191 (39.2)% 942,277 438,039 20,699 53,714 406,548 7,005 1,532,576 504,466 25,164 66,179 216,908 — (38.5) (13.2) (17.7) (18.8) 87.4 — $ (393,902) $ 80,898 (586.9) $ $ 49,003 26,589 15,730 10,859 $ $ 262 47% 81,805 26,167 15,243 10,924 299 67% (40.1) 1.6 3.2 (0.6) (12.4) (29.9) (1) Operations previously reported within the H&P Technologies reportable segment are now managed and presented within the North America Solutions reportable segment. (2) These operating metrics allow investors to analyze the various components of segment financial results in terms of volume, revenue per unit, cost per unit and margin per unit. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. (3) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out of pocket” expenses of $171.5 million and $285.6 million for fiscal years 2020 and 2019, respectively. Operating Income (Loss) The North America Solutions segment had an operating loss of $393.9 million for the fiscal year ended September 30, 2020 compared to operating income of $80.9 million for the fiscal year ended September 30, 2019. The decrease was primarily driven by increased asset impairment charges and reduced rig activity in fiscal year 2020. Revenues were $1.5 billion and $2.4 billion in fiscal year 2020 and 2019, respectively. Included in revenues for fiscal year 2020 is early termination revenue of $68.8 million compared to $6.4 million during fiscal year 2019. Fixed term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term (except in limited circumstances including sustained unacceptable performance by us). Revenue Excluding early termination per day revenue of $1,404 and $78 for fiscal years 2020 and 2019, respectively, average rig revenue per day decreased by $904 to $25,185 primarily due to a portion of our contracted rigs operating in an idle- but-contracted state during the third and fourth quarters of fiscal year 2020, with lower average daily revenue and average daily expense and lower pricing for rigs working in the spot market. Compared to fiscal year 2019, our revenue days declined by 40.1 percent. This decline was initially driven by the collapse in oil prices that occurred in March of 2020, which led our customers to quickly reduce rig activity beginning in the second half of March 2020 and continuing throughout fiscal year 2020. Our level of contracted rigs hit a low of 62 rigs in August of 2020 before modestly recovery to 69 rigs at fiscal year end. Direct Operating Expenses Average rig expense per day increased $487 to $15,730 during the fiscal year ended September 30, 2020 compared to the fiscal year ended September 30, 2019. The increase is due to higher self-insurance expenses and idle rig expenses, partially offset by the previously mentioned effect of idle-but-contracted rigs. Depreciation Depreciation expense decreased to $438.0 million during the fiscal year ended September 30, 2020 compared to the fiscal year ended September 30, 2019. The decrease in depreciation during fiscal year ended September 30, 2020 compared to fiscal year ended September 30, 2019 was primarily attributable to the lower carrying cost of our impaired assets. Depreciation includes charges for abandoned equipment of $2.5 million and $10.6 million for the fiscal years ended September 30, 2020 and 2019, respectively. In the fiscal year ended September 30, 2020, depreciation expense included $1.5 million of accelerated depreciation for components on rigs that are scheduled for conversion in fiscal year 2021 as compared to $4.7 million of accelerated depreciation for fiscal year ended September 30, 2019. 40 Asset Impairment Charge During the fiscal year ended September 30, 2020, we impaired our Domestic non-super-spec asset group, in addition to in-progress drilling equipment and rotational inventory. This resulted in an aggregate non-cash impairment charge of $368.2 million ($284.1 million, net of tax, or $3.41 per diluted share) for the fiscal year ended September 30, 2020. During the fiscal year ended September 30, 2020, we also recorded a goodwill impairment loss of $38.3 million ($29.6 million, net of tax, or $0.35 per diluted share). Comparatively, during the fiscal year ended September 30, 2019, we recorded an asset impairment charge of $216.9 million ($188.6 million, net of tax, or $1.72 per diluted share), mainly driven by the downsizing of our fleet of FlexRig® 4 drilling rigs. These non-cash impairment charges are included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal years ended September 30, 2020 and 2019. Restructuring Charges For the fiscal year ended September 30, 2020, we incurred $7.0 million in restructuring charges primarily comprised of one-time severance benefits to employees as a result of headcount reductions that occurred during the third fiscal quarter of 2020. Utilization Rig utilization decreased to 47 percent for the fiscal year ended September 30, 2020 compared to 67 percent during the fiscal year ended September 30, 2019. In addition to the previously mentioned reduction in revenue days, we decommissioned two rigs and 35 rigs from our legacy Domestic Conventional asset group and FlexRig® 3 asset group, respectively effective as of April 30, 2020. At September 30, 2020, 69 out of 262 existing rigs in the North America Solutions segment were contracted. Of the 69 contracted rigs, 54 were under fixed-term contracts and 15 were working in the spot market. Offshore Gulf of Mexico The following table presents certain information with respect to our Offshore Gulf of Mexico reportable segment: (in thousands, except operating statistics) Operating revenues Direct operating expenses Depreciation Selling, general and administrative expense Restructuring charges (1): Segment operating income Operating Statistics Revenue days Average rig revenue per day (2) Average rig expense per day (2) Average rig margin per day (2) Number of rigs at the end of period Rig utilization $ $ $ $ 2020 143,149 119,371 11,681 3,365 1,254 7,478 1,922 45,145 37,410 7,735 8 66% $ $ $ $ 2019 147,635 114,306 10,010 3,725 — 19,594 2,163 37,478 28,663 8,815 8 74% % Change (3.0)% 4.4 16.7 (9.7) — (61.8) (11.1) 20.5 30.5 (12.3) — (10.8) (1) These operating metrics allow investors to analyze the various components of segment financial results in terms of volume, revenue per unit, cost per unit and margin per unit. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. (2) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out of pocket” expenses of $30.4 million and $26.4 million for fiscal years 2020 and 2019, respectively. The operating statistics only include rigs that we own and exclude offshore platform management and contract labor service revenues of $26.0 million and $40.1 million, offshore platform management and contract labor service expenses of $17.0 million and $25.9 million, and currency revaluation expense of $30.1 thousand and $1.0 thousand for fiscal years 2020 and 2019, respectively. Operating Income During the fiscal year ended September 30, 2020, the Offshore Gulf of Mexico segment had operating income of $7.5 million compared to operating income of $19.6 million for the fiscal year ended September 30, 2019. This decrease is primarily attributable to lower contribution from two rigs that demobilized back to shore during the first quarter of fiscal year 2020. One of the two rigs began mobilizing to a new platform during March 2020 and commenced drilling operations during the third quarter of fiscal year 2020. Additionally, we incurred $4.2 million of bad debt expense during fiscal year 2020. Revenue Average rig revenue per day increased 20.5 percent to $45,145 in fiscal year 2020 compared to fiscal year 2019. This was primarily due to one of our customers shifting its activity from a customer-owned rig managed by H&P to a rig owned by H&P. Direct Operating Expenses Average rig expense per day increased to $37,410 during fiscal year 2020 from $28,663 during fiscal year 2019, primarily due to factors mentioned above. Restructuring Charges For the fiscal year ended September 30, 2020, we incurred $1.3 million in restructuring charges primarily comprised of one-time severance benefits to employees as a result of headcount reductions that occurred during the third fiscal quarter of 2020. Utilization As of September 30, 2020, five of our eight available platform rigs were under contract, compared to six of our eight available platform rigs as of September 30, 2019. 41 International Solutions The following table presents certain information with respect to our International Solutions reportable segment: (in thousands, except operating statistics) Operating revenues Direct operating expenses Depreciation Selling, general and administrative expense Asset impairment charge Restructuring charges Segment operating income (loss) Operating Statistics (1): Revenue days Average rig revenue per day (2) Average rig expense per day (2) Average rig margin per day (2) Number of rigs at the end of period Rig utilization 2020 2019 % Change $ 144,185 $ 211,731 (31.9)% 124,791 17,531 4,565 156,686 2,980 $ (162,368) $ $ $ 4,605 29,116 23,066 6,050 $ $ 32 40% 157,856 35,466 5,624 7,419 — 5,366 6,426 31,269 21,626 9,643 31 55% (20.9) (50.6) (18.8) 2,012.0 — (3,125.9) (28.3) (6.9) 6.7 (37.3) 3.2 (27.3) (1) These operating metrics allow investors to analyze the various components of segment financial results in terms of volume, revenue per unit, cost per unit and margin per unit. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. (2) Operating statistics for per day revenue, expense and margin do not include reimbursements of “out of pocket” expenses of $10.1 million and $10.8 million for fiscal years 2020 and 2019, respectively. Also excluded are the effects of currency revaluation expense of $8.5 million and $8.1 million for fiscal years 2020 and 2019, respectively. Operating Income (Loss) The International Solutions segment had an operating loss of $162.4 million for fiscal year 2020 compared to operating income of $5.4 million for fiscal year 2019. The decrease was primarily driven by asset impairment charges during fiscal year 2020. Revenue We experienced a 28.3 percent decrease in revenue days when comparing fiscal year 2020 to fiscal year 2019. The average number of active rigs was 12.6 during fiscal year 2020 compared to 17.6 during fiscal year 2019. Average rig revenue per day decreased by 6.9 percent primarily due to a shifting rig mix. Direct Operating Expenses Average rig expense per day increased to $23,066 during fiscal year 2020 as compared to $21,626 during fiscal year 2019. The increase was driven by lower activity coupled with fixed minimum levels of country overhead. Depreciation Depreciation expense decreased to $17.5 million during the fiscal year ended September 30, 2020 compared to the fiscal year ended September 30, 2019. The decrease in depreciation during fiscal year ended September 30, 2020 compared to fiscal year ended September 30, 2019 was primarily attributable to the lower carrying cost of our impaired assets. Asset Impairment Charge During the fiscal year ended September 30, 2020, we impaired our International Conventional, FlexRig® 3, and FlexRig® 4 asset groups, in addition to rotational inventory. This resulted in an aggregate non-cash impairment charge of $156.7 million ($123.8 million, net of tax, or $1.45 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2020. Comparatively, during the fiscal year ended September 30, 2019, mainly driven by the downsizing of our fleet of FlexRig® 4 drilling rigs, we wrote down capital spares and drilling support equipment and, as a result, we recorded an asset impairment charge of $7.4 million, in our Consolidated Statements of Operations for the fiscal year ended September 30, 2019. Restructuring Charges For the fiscal year ended September 30, 2020, we incurred $3.0 million in restructuring charges primarily comprised of one-time severance benefits to employees as a result of headcount reductions that occurred during the third fiscal quarter of 2020. Utilization Our utilization decreased during fiscal year 2020 compared to fiscal year 2019. At September 30, 2020, five out of 32 existing rigs in the International Solutions segment were contracted. Of the five contracted rigs, two were under fixed-term contracts and three were working in the spot market. 42 Other Operations Results of our other operations, excluding corporate selling, general and administrative costs, corporate restructuring, and corporate depreciation, are as follows: (in thousands) Operating revenues Direct operating expenses Depreciation and amortization Research and development Selling, general and administrative expense Restructuring charges Operating income 2020 2019 % Change $ 49,114 $ 41,027 1,241 946 1,237 260 $ 4,403 $ 12,933 5,382 1,523 2,303 350 — 3,375 279.8% 662.3 (18.5) (58.9) 253.4 — 30.5 Operating Income On October 1, 2019, we elected to utilize the Captive to insure the deductibles for our workers’ compensation, general liability and automobile liability claims programs. Direct operating costs include accruals for estimated losses of approximately $16.4 million allocated to the Captive during the fiscal year ended September 30, 2020. Intercompany premium revenues recorded by the Captive during the fiscal year ended September 30, 2020 amounted to $36.9 million, which were eliminated upon consolidation. Results of Operations for the Fiscal Years Ended September 30, 2019 and 2018 A discussion of our results of operations for the fiscal year ended September 30, 2019 compared to the fiscal year ended September 30, 2018 is included in Part II, Item 7— "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2019, filed with the SEC on November 15, 2019, and is incorporated by reference into this Form 10-K. 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 the 2018 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 may utilize cash on hand, borrow from available credit sources, access capital markets or sell our marketable 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 and commercial paper, certificates of deposit and money market funds. Our marketable 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 the 2018 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. The effects of the COVID-19 outbreak and the oil price collapse in 2020 have had significant adverse consequences for general economic, financial and business conditions, as well as for our business and financial position and the business and financial position of our customers, suppliers and vendors and may, among other things, impact our ability to generate cash flows from operations, access the capital markets on acceptable terms or at all and affect our future need or ability to borrow under the 2018 Credit Facility. In addition to our potential sources of funding, the effects of such global events may impact our liquidity or need to alter our allocation or sources of capital, implement additional cost reduction measures and further change our financial strategy. Although the COVID-19 outbreak and the oil price collapse could have a broad range of effects on our sources and uses of liquidity, the ultimate effect thereon, if any, will depend on future developments, which cannot be predicted at this time. 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, all of which was impacted by the COVID-19 outbreak and the oil price collapse in 2020. As our revenues increase, net working capital is typically a use of capital, while conversely, as our revenues decrease, net working capital is typically a source of capital. To date, general inflationary trends have not had a material effect on our operating margins. 43 As of September 30, 2020, we had $487.9 million of cash and cash equivalents on hand and $89.3 million of short-term investments. Our cash flows for the fiscal years ended September 30, 2020, 2019 and 2018 are presented below: (in thousands) Net cash provided (used) by: Operating activities Investing activities Financing activities Net increase (decrease) in cash and cash equivalents and restricted cash Operating Activities Year Ended September 30, 2020 2019 2018 $ $ 538,881 $ 855,751 $ 557,852 (87,885) (297,220) (422,636) (376,329) (472,362) (319,814) 153,776 $ 56,786 $ (234,324) For the purpose of understanding the impact on our Cash Flow from Operations, net working capital is calculated as current assets, excluding cash and short-term investments, less current liabilities, excluding dividends payable, short–term debt and the current portion of long–term debt. Net working capital was $194.2 million as of September 30, 2020 compared to $381.7 million as of September 30, 2019. Included in accounts receivable as of September 30, 2020 were $5.2 million of early termination fees and $42.4 million of income tax receivables. Cash flows provided by operating activities was $538.9 million in fiscal year 2020 compared to $855.8 million fiscal year 2019. The decrease in cash provided by operating activities is primarily driven by lower operating activity and a favorable variance in the use of working capital. Cash flows provided by operating activities in fiscal year 2018 was $557.9 million. The $297.9 million increase compared to fiscal year 2019 was primarily due to a decrease in working capital. Investing Activities Capital Expenditures Our investing activities are primarily related to capital expenditures for our fleet. Our capital expenditures were $140.8 million, $458.4 million and $466.6 million in fiscal years 2020, 2019 and 2018, respectively. The year- over-year decrease in capital expenditures is driven by a decrease in super-spec upgrades and lower maintenance capital expenditure levels as a result of lower activity. Our fiscal year 2021 capital spending is currently estimated to be between $85 and $105 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 We paid $16.2 million and $47.9 million, net of cash acquired, during the 2019 and 2018 fiscal year, respectively, for the acquisition of drilling technology companies. Sale of Assets Our proceeds from asset sales totaled $78.4 million, $50.8 million and $44.4 million in fiscal year 2020, 2019 and 2018, respectively. The current year increase is primarily driven by the sale of a portion of our real estate investment portfolio. During the fiscal year ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including six industrial sites, for total consideration, net of selling related expenses, of $40.7 million. Sale of Subsidiary In December 2019, we closed on the sale of a wholly-owned subsidiary of HPIDC, TerraVici. As a result of the sale, 100% of TerraVici's outstanding capital stock was transferred to the purchaser in exchange for approximately $15.1 million, resulting in a total gain on the sale of TerraVici of approximately $15.0 million. Marketable Securities 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. As of September 30, 2020, our marketable securities consist primarily of common shares in Schlumberger, Ltd. that, at the close of fiscal year 2020, had a fair value of $7.3 million. The value of our securities are subject to fluctuation in the market and may vary considerably over time. Our marketable securities are recorded at fair value on our balance sheet. Our equity investment in Schlumberger Ltd. held as of September 30, 2020 is presented below: (in thousands, except for share amounts) Number of Shares Cost Basis Market Value Schlumberger, Ltd. Financing Activities 467,500 3,713 7,274 Repurchase of Shares During fiscal year 2020, we repurchased 1.5 million shares for $28.5 million compared to one million shares for $42.8 million during fiscal year 2019. 44 Dividends We paid dividends of $2.38, $2.84, and $2.82 per share during fiscal years 2020, 2019 and 2018, respectively. Total dividends paid were $260.3 million, $313.4 million and $308.4 million in fiscal years 2020, 2019 and 2018, respectively. On June 3, 2020, we reduced our quarterly cash dividend to $0.25 per share and on September 9, 2020, declared a cash dividend in that amount for shareholders of record on November 13, 2020, payable on December 1, 2020. The declaration and amount of future dividends is at the discretion of the Board and subject to our financial condition, results of operations, cash flows, and other factors the Board 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, which was amended on November 13, 2019, providing for an unsecured revolving credit facility (the “2018 Credit Facility”) that is set to mature on November 13, 2024. The 2018 Credit Facility has $750.0 million in aggregate availability with a maximum of $75.0 million available for use as letters of credit. The 2018 Credit Facility also permits aggregate commitments under the facility to be increased by $300.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. 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. 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, 2020, the spread over LIBOR would have been 1.125 percent had borrowings been outstanding under the 2018 Credit 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. At September 30, 2020, 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 2021. As of September 30, 2020, there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. As of September 30, 2020, we had two separate outstanding letters of credit with banks, in the amounts of $24.8 million and $2.1 million, respectively. As of September 30, 2020, we also had a $20.0 million unsecured standalone line of credit facility, for the purpose of obtaining the issuance of international letters of credit, bank guarantees, and performance bonds. Of the $20.0 million, $4.3 million of financial guarantees were outstanding as of September 30, 2020. Subsequent to September 30, 2020, $2.6 million in financial guarantees have expired. 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. Senior Notes Exchange Offer, Consent Solicitation and Redemption On December 20, 2018, we settled an offer to exchange (the “Exchange Offer”) any and all outstanding 4.65 percent unsecured senior notes due 2025 of HPIDC (the "HPIDC 2025 Notes") 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, 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. Following the consummation of the Exchange Offer, HPIDC had outstanding approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes. 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 certain proposed amendments pursuant to a consent solicitation conducted concurrently with the Exchange Offer. 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 a result of such release, H&P is the only obligor under the Company 2025 Notes and the 2018 Credit Facility. 45 Repurchase of Common Shares We have an evergreen authorization from the Board for the purchase of up to four million common shares in any calendar year. During the fiscal year ended September 30, 2020, we purchased 1.5 million common shares at an aggregate cost of $28.5 million, which are held as treasury shares. We purchased 1.0 million common shares at an aggregate cost of $42.8 million, which are held as treasury shares, during the fiscal year ended September 30, 2019. We had no purchases of common shares during the fiscal year ended September 30, 2018. Future Cash Requirements Our operating cash requirements, scheduled debt repayments, interest payments, any declared dividends, and estimated capital expenditures for fiscal year 2021 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. On June 3, 2020, we reduced our quarterly cash dividend to $0.25 per share. If needed, we may decide to obtain additional funding from our $750.0 million 2018 Credit Facility. Our indebtedness under our unsecured senior notes totaled $487.1 million at September 30, 2020 and matures on March 19, 2025. As of September 30, 2020, we had a $650.7 million deferred tax liability on our Consolidated Balance Sheets, primarily related to temporary differences between the financial and income tax basis of property, plant and equipment. Our increased levels of capital expenditures over the last several years have been subject to accelerated depreciation methods (including bonus depreciation) available under the Internal Revenue Code of 1986, as amended, enabling us to defer a portion of cash tax payments to future years. Future levels of capital expenditures and results of operations will determine the timing and amount of future cash tax payments. We expect to be able to meet any such obligations utilizing cash and investments on hand, as well as cash generated from ongoing operations. The long term debt to total capitalization ratio was 12.8 percent at September 30, 2020 compared to 10.8 percent at September 30, 2019. For additional information regarding debt agreements, refer to Note 8—Debt to our Consolidated Financial Statements. 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, 2020 are summarized in the table below: (in thousands) Long-term debt Interest (1) Operating leases (2) Purchase obligations (3) Total 2021 2022 2023 2024 2025 Thereafter Payments due by year $ 487,148 $ — $ — $ — $ — $ 487,148 $ 101,934 38,166 2,692 22,652 11,680 2,692 22,652 8,133 — 22,652 7,466 — 22,652 7,018 — 11,326 3,231 — — — 638 — 638 Total contractual obligations $ 629,940 $ 37,024 $ 30,785 $ 30,118 $ 29,670 $ 501,705 $ (1) Interest on fixed rate debt was estimated based on principal maturities. See Note 8—Debt to our Consolidated Financial Statements. (2) See Note 6—Leases to our Consolidated Financial Statements. (3) See Note 17—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 2020 and 2019, we did not make any contributions to the pension plan. Contributions may be made in fiscal year 2021 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond fiscal year 2021 are difficult to estimate due to multiple variables involved. At September 30, 2020, we had $16.3 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 9—Income Taxes to our Consolidated Financial Statements. 46 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 Form 10-K. 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 Form 10-K, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations. Impairment of Long lived Assets, Goodwill and Other Intangible Assets Management assesses the potential impairment of our long lived assets and finite-lived intangibles whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, 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 $10 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. 47 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 Drilling services and solutions 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 revenue. 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. 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 Our financial position is exposed to a variety of risks, including foreign currency exchange risk, commodity price risk, credit and capital market risk, interest rate risk and equity price risk. We have seen an increase in these risks and related uncertainties with increased volatility in oil and gas prices and the financial markets as a result of the COVID-19 pandemic. Foreign Currency Exchange Rate Risk Our drilling contracts in foreign countries generally provide for payment in U.S. dollars. Historically, in Argentina, while the contracts were denominated in the U.S. dollar, we were paid in Argentine pesos. We are currently receiving some customer payments in U.S. dollars, but we will likely receive future payments in Argentine pesos as we have in the past. The Argentine branch of one of our second tier subsidiaries remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars. In the future, other contracts or applicable law may require payments to be made in foreign currencies. 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, 2020, 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 $2.2 million. 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. 48 Commodity Price Risk The demand for drilling services and solutions 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 drilling services and solutions is not always purely a function of the movement of commodity prices. Credit and Capital Market Risk Customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets, as experienced in the past, can make it difficult for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in customer credit defaults or reduced demand for our services, which could have a material adverse effect on our business, financial condition and results of operations. Similarly, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by, among other things, oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health of the drilling and overall oil and gas industry, and the liquidity of the capital markets. Many of the factors that affect our ability to access capital markets are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations. Further, we attempt to secure favorable prices through advanced ordering and purchasing for drilling rig components. While these materials have generally been available at acceptable prices, there is no assurance the prices will not vary significantly in the future. Any fluctuations in market conditions causing increased prices in materials and supplies could have a material adverse effect on future operating costs. Interest Rate Risk Our interest rate risk exposure results primarily from short term rates, mainly LIBOR based, on any borrowings from our revolving credit facility. There were no outstanding borrowings under this facility at September 30, 2020, and our outstanding debt consisted of $487.1 million (face amount) in senior unsecured notes, which have a fixed rate of 4.65 percent. The fair value of the fixed-rate debt was estimated to be $534.5 million and $526.4 million for fiscal years 2020 and 2019, respectively. Equity Price Risk On September 30, 2020, we had marketable equity securities with a total fair value of $7.3 million. The total fair value of our marketable securities was $16.3 million at September 30, 2019. A hypothetical 10 percent decrease in the market price for our marketable equity securities as of September 30, 2020 would decrease the fair value by $0.7 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 12, 2020, the total fair value of our marketable securities increased to approximately $8.1 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. 49 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to Consolidated Financial Statements Management’s Report on Internal Control over Financial Reporting Reports of Independent Registered Public Accounting Firm Consolidated Financial Statements: Consolidated Balance Sheets at September 30, 2020 and 2019 Consolidated Statements of Operations for the Years Ended September 30, 2020, 2019 and 2018 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended September 30, 2020, 2019 and 2018 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2020, 2019 and 2018 Consolidated Statements of Cash Flows for the Years Ended September 30, 2020, 2019 and 2018 Notes to Consolidated Financial Statements Page 51 52 56 57 58 59 60 61 50 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, 2020. 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, 2020. Ernst & Young LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2020, as stated in their report which appears herein. Helmerich & Payne, Inc. by /s/ John W. Lindsay /s/ Mark W. Smith John W. Lindsay Director, President and Chief Executive Officer Mark W. Smith Senior Vice President and Chief Financial Officer November 20, 2020 November 20, 2020 51 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, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2020, 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, 2020, 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 20, 2020 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 The Company's self-insurance liability for workers’ compensation and other casualty claims was Self-Insurance Accruals $73.8 million at September 30, 2020. 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 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. 52 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. 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. Additionally, 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. Description of the Matter Impairment of Long-Lived Assets As more fully described in Note 5 to the consolidated financial statements, the Company recognized a $441.4 million impairment charge in 2020 due to projected low utilization of the domestic non-super spec and all international asset groups. 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 and net proceeds received upon future sale/disposition. How We Addressed the Matter in Our Audit 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 Company’s historical experience and market activity to peer averages. 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. Valuation of Goodwill and Finite-lived Intangibles Description of the Matter As more fully described in Note 7 to the consolidated financial statements, during 2020 the Company performed goodwill and finite-lived intangible impairment analyses, resulting in a $38.3 million goodwill impairment charge. How We Addressed the Matter in Our Audit Auditing the Company’s impairment analyses was complex and highly judgmental due to the significant estimation required to determine the estimated future cash flows. In particular, the fair value estimate was sensitive to significant assumptions, such as changes in the utilization, discount rate, and terminal value, which are affected by expectations about future market and economic conditions. We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s goodwill and finite-lived intangibles impairment review process, including controls over management’s review of the significant assumptions described above. For example, we evaluated controls over the Company’s forecasting process used to develop the estimated future cash flows. We also tested controls over management’s review of the data used in their valuation models and the significant assumptions such as the estimation of utilization, discount rate and terminal value. To test the estimated cash flows of the applicable reporting unit and finite-lived intangibles, we performed audit procedures that included, among others, assessing methodologies and testing the significant assumptions discussed above and the underlying data used by the Company in its analyses. We compared the projected cash flows to available industry and market forecast information. We involved our valuation specialists to assist in testing the discount rate. We assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the reporting unit and finite-lived intangibles that would result from changes in the assumptions. For finite-lived intangibles, we also assessed whether the assumptions used were consistent with those used in the goodwill impairment review process. 53 We have served as the Company’s auditor since 1994. Tulsa, Oklahoma November 20, 2020 /s/Ernst & Young LLP 54 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, 2020, 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, 2020, 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, 2020 and 2019, 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, 2020, and the related notes and our report dated November 20, 2020 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 20, 2020 /s/ Ernst & Young LLP 55 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 $1,820 and $9,927, 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 Operating lease right-of-use asset Other assets Total other noncurrent assets September 30, 2020 2019 $ 487,884 $ 347,943 89,335 192,623 104,180 89,305 963,327 52,960 495,602 149,653 68,928 1,115,086 31,585 31,991 3,646,341 4,502,084 45,653 81,027 44,583 17,105 188,368 82,786 86,716 — 20,852 190,354 Total assets $ 4,829,621 $ 5,839,515 Liabilities and Shareholders’ Equity Current Liabilities: Accounts payable Dividends 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 17) Shareholders' Equity: Common stock, $.10 par value, 160,000,000 shares authorized, 112,151,563 and 112,080,262 shares issued as of September 30, 2020 and 2019, respectively, and 107,488,242 and 108,437,904 shares outstanding as of September 30, 2020 and 2019, respectively Preferred stock, no par value, 1,000,000 shares authorized, no shares issued Additional paid-in capital Retained earnings Accumulated other comprehensive loss Treasury stock, at cost, 4,663,321 shares and 3,642,358 shares as of September 30, 2020 and 2019, respectively Total shareholders’ equity Total liabilities and shareholders' equity $ 36,468 $ 27,226 155,442 219,136 480,727 650,675 147,180 13,389 45,383 77,763 287,092 410,238 479,356 806,611 115,746 15,341 1,291,971 1,417,054 11,215 — 521,628 3,010,012 11,208 — 510,305 3,714,307 (26,188) (28,635) (198,153) (194,962) 3,318,514 4,012,223 $ 4,829,621 $ 5,839,515 The accompanying notes are an integral part of these consolidated financial statements. 56 HELMERICH & PAYNE, INC. Consolidated Statements of Operations Year Ended September 30, 2020 2019 2018 $ 1,761,714 $ 2,785,557 $ 2,474,458 12,213 12,933 12,810 1,773,927 2,798,490 2,487,268 (in thousands, except per share amounts) Operating revenues Drilling services Other Operating costs and expenses Drilling services operating expenses, excluding depreciation and amortization 1,184,788 1,803,204 1,647,557 Other operating expenses Depreciation and amortization Research and development Selling, general and administrative Asset impairment charge Restructuring charges 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 Gain on sale of subsidiary 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 Income (loss) from discontinued operations Net income (loss) Basic earnings (loss) per common share: Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) Diluted earnings (loss) per common share: Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) Weighted average shares outstanding: Basic Diluted 5,777 481,885 21,645 167,513 563,234 16,047 5,382 562,803 27,467 194,416 224,327 — 5,053 583,802 18,167 199,257 23,128 — (46,775) (39,691) (22,660) 2,394,114 2,777,908 2,454,304 (620,187) 20,582 32,964 7,304 (24,474) (8,720) 14,963 (5,384) (16,311) (636,498) (140,106) (496,392) 30,580 28,685 1,895 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) $ $ $ $ $ $ $ (494,497) $ (33,656) $ 482,672 (4.62) $ 0.02 (4.60) $ (4.62) $ 0.02 (4.60) $ (0.33) $ (0.01) (0.34) $ (0.33) $ (0.01) (0.34) $ 4.49 (0.10) 4.39 4.47 (0.10) 4.37 108,009 108,009 109,216 109,216 108,851 109,387 The accompanying notes are an integral part of these consolidated financial statements. 57 HELMERICH & PAYNE, INC. Consolidated Statements of Comprehensive Income (Loss) (in thousands) Net income (loss) Other comprehensive income (loss), net of income taxes: Unrealized appreciation on securities, net of income taxes of $3.3 million at September 30, 2018 Minimum pension liability adjustments, net of income taxes of $0.8 million at September 30, 2020, $(3.5) million at September 30, 2019 and $1.9 million at September 30, 2018 Other comprehensive income (loss) Comprehensive income (loss) Year ended September 30, 2020 2019 2018 $ (494,497) $ (33,656) $ 482,672 — 2,447 2,447 — 9,001 (11,875) (11,875) 5,249 14,250 $ (492,050) $ (45,531) $ 496,922 The accompanying notes are an integral part of these consolidated financial statements. 58 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, 2017 111,957 $ 11,196 $ 487,248 $ 3,855,686 Accumulated Other Comprehensive Income (Loss) $ 2,300 Treasury Stock Shares Amount Total 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 Cumulative effect adjustment for adoption of ASU No. 2016-01 (Note 10) Reclassification of stranded tax effect for adoption of ASU No. 2018-02 — — — — 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 Comprehensive income (loss): Net loss Other comprehensive income Dividends declared ($1.92 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 — — — — 71 — — — — — — 7 — — — — — (494,497) — (209,798) (3,151) (21,855) 36,329 — — — — — — 2,447 — — — — — — — — — — — (494,497) 2,447 (209,798) (110) 7,195 4,044 (329) 18,119 — — (3,729) 36,329 1,460 (28,505) (28,505) Balance at September 30, 2020 112,151 $ 11,215 $ 521,628 $ 3,010,012 $ (26,188) 4,663 $ (198,153) $ 3,318,514 The accompanying notes are an integral part of these consolidated financial statements. 59 HELMERICH & PAYNE, INC. Consolidated Statements of Cash Flows (in thousands) Cash flows from operating activities: Year Ended September 30, 2019 2018 2020 Net income (loss) Adjustment for (income) loss from discontinued operations Income (loss) from continuing operations Adjustments to reconcile net income (loss) to net cash provided by operating activities: $ (494,497) $ (1,895) (496,392) (33,656) $ 1,146 (32,510) 482,672 10,338 493,010 Depreciation and amortization Asset impairment charges Amortization of debt discount and debt issuance costs Provision for bad debt Stock-based compensation Loss (gain) on investment securities Gain on sale of assets Gain on sale of subsidiary Deferred income tax benefit Other Change in assets and liabilities: 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 subsidiary Proceeds from sale of marketable securities Proceeds from asset sales Other 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 repurchases Other 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 Payments for operating leases Changes in accounts payable and accrued liabilities related to purchases of property, plant and equipment 481,885 563,234 1,817 2,203 36,329 8,720 (46,775) (14,963) (157,555) (200) 300,807 7,197 (5,506) 2,820 (9,414) (138,414) 908 2,227 538,928 (47) 538,881 (140,795) (134,641) — 94,646 15,056 — 78,399 (550) (87,885) (260,335) — 4,100 (3,784) (8,250) — (28,505) (446) (297,220) 153,776 382,971 536,747 22,928 46,700 18,646 3,123 $ $ 562,803 224,327 1,732 2,321 34,292 54,488 (39,691) — (44,554) (3,295) 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 (1) (22,660) — (486,758) 7,623 (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 20,502 (38,400) — (2,245) $ $ The accompanying notes are an integral part of these consolidated financial statements. 60 HELMERICH & PAYNE, INC. Notes to Consolidated Financial Statements NOTE 1 NATURE OF OPERATIONS 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. During the third quarter of fiscal year 2020, we restructured our operations (see Note 19—Restructuring Charges) to accommodate scale during an industry downturn and to re-organize our operations to align to new marketing and management strategies. This is consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. Operations previously reported within the former U.S. Land and H&P Technologies operating and reportable segments are now managed and presented within the North America Solutions reportable segment. As a result, beginning with the third quarter of fiscal year 2020, our drilling services operations were organized into the following reportable operating business segments: North America Solutions, Offshore Gulf of Mexico and International Solutions. All segment disclosures have been recast for these segment changes. Our real estate operations, our incubator program for new research and development projects and our wholly-owned captive insurance companies are included in "Other." Refer to Note 18—Business Segments and Geographic Information for further details on our reportable segments. Our North America Solutions operations are primarily located in Colorado, Ohio, Oklahoma, New Mexico, North Dakota, Pennsylvania, Texas, West Virginia and Wyoming. Additionally, Offshore Gulf of Mexico operations are conducted in Louisiana and in U.S. federal waters in the Gulf of Mexico and our International Solutions operations have rigs primarily located in four international locations: Argentina, Bahrain, Colombia and United Arab Emirates. 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 and undeveloped real estate. Dispositions In December 2019, we closed on the sale of a wholly-owned subsidiary of Helmerich & Payne International Drilling Co. ("HPIDC"), TerraVici Drilling Solutions, Inc. ("TerraVici"). As a result of the sale, 100% of TerraVici's outstanding capital stock was transferred to the purchaser in exchange for approximately $15.1 million, resulting in a total gain on the sale of TerraVici of approximately $15.0 million. Prior to the sale, TerraVici was a component of the North America Solutions operating segment. This transaction does not represent a strategic shift in our operations and will not have a significant effect on our operations and financial results going forward. 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 operations and comprehensive income (loss) 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. 61 COVID-19 and OPEC+ Production Impacts The outbreak of a novel strain of coronavirus (“COVID-19”) and its development into a pandemic have resulted in significant global economic disruption, including North America and many of the other geographic areas where we operate, or where our customers are located, or suppliers or vendors operate. Actions taken to prevent the spread of COVID-19 by governmental authorities around the world, including imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of such facilities and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions, have significantly reduced global economic activity, thereby resulting in lower demand for crude oil. In particular, the travel restrictions in certain countries where we operate, including the closure of their borders to travel into the country, have resulted in an inability to effectively staff or rotate personnel at, and thereby operate, certain of our rigs and could lead to an inability to fulfill our contractual obligations under contracts with customers. Governmental authorities have also implemented multi-step policies with the goal of re-opening various sectors of the economy. However, certain jurisdictions began re-opening only to return to restrictions in the face of increases in new COVID-19 cases, while other jurisdictions are continuing to re-open or have nearly completed the re-opening process despite increases in COVID-19 cases. The COVID-19 outbreak may significantly worsen during the upcoming months, which may cause governmental authorities to reconsider restrictions on business and social activities. In the event governmental authorities increase restrictions, the re-opening of the economy may be further curtailed. We have experienced, and expect to continue to experience, some resulting in disruptions to our business operations, as these restrictions have significantly impacted, and may continue to impact, many sectors of the economy. In addition, the perceived risk of infection and health risk associated with COVID-19, and the illness of many individuals across the globe, has and will continue to alter behaviors of consumers, and policies of companies around the world, resulting in many of the same effects intended by such governmental authorities to stop the spread of COVID-19, such as self-imposed or voluntary social distancing and quarantining and remote work policies. We are complying with local governmental jurisdiction policies and procedures where our operations reside. In some cases, policies and procedures are more stringent in our foreign operations than in our North America operations and this has resulted in a complete suspension, for a certain period of time, of all drilling operations in at least one foreign jurisdiction. In addition, a customer in one foreign jurisdiction has claimed force majeure resulting in zero chargeable revenues during the suspension period. In early March 2020, the increase in crude oil supply resulting from production escalations from the Organization of the Petroleum Exporting Countries and other oil producing nations (“OPEC+”) combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Consequently, we have seen a significant decrease in customer 2020 capital budgets and a corresponding dramatic decline in the demand for land rigs. In April 2020, OPEC+ finalized an agreement to cut oil production by 9.7 million barrels per day during May and June 2020. On June 6, 2020, OPEC+ agreed to extend such production cuts until the end of July 2020. On July 15, 2020, OPEC+ agreed to ease the production cuts from 9.7 million barrels per day to 7.7 million barrels per day from August to December 2020. Despite the production cuts, prices in the oil and gas market have remained depressed, as the oversupply and lack of demand in the market persist. Oil and natural gas prices are expected to continue to be volatile as a result of the near-term production instability and the ongoing COVID-19 outbreak and as changes in oil and natural gas inventories, industry demand and global and national economic performance are reported. These events have had, and could continue to have, an adverse impact on numerous aspects of our business, financial condition and results of operations. The ultimate extent of the impact of COVID-19 and prolonged excess oil supply on our business, financial condition and results of operations will depend largely on future developments, including the duration and spread of the COVID-19 outbreak within the United States and the parts of the world in which we operate and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the development and availability of effective treatments and vaccines, all of which are highly uncertain and cannot be predicted with certainty at this time. From a financial perspective, we believe the Company is operationally and financially well positioned to continue operating even through a more protracted disruption caused by COVID-19, oil oversupply and low oil prices. At September 30, 2020, the Company had cash and cash equivalents and short-term investments of $577.2 million. The 2018 Credit Facility (as defined within Note 8—Debt) has $750.0 million in aggregate availability with a maximum of $75.0 million available for use as letters of credit. As of September 30, 2020, there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. We currently do not anticipate the need to draw on the 2018 Credit Facility. Furthermore, the Company 2025 Notes (as defined within Note 8—Debt) do not mature until March 19, 2025. 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 $8.8 million, $8.2 million and $4.0 million in fiscal years 2020, 2019 and 2018, respectively, are included in drilling services operating expenses. 62 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. 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 $48.9 million and $35.0 million at September 30, 2020 and 2019, respectively. Of the total at September 30, 2020 and 2019, $3.6 million and $3.0 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 $43.1 million and $30.0 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. 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 Accounts Receivable September 30, 2020 2019 2018 $ 487,884 $ 347,943 $ 284,355 45,577 3,286 31,291 3,737 39,830 2,000 $ 536,747 $ 382,971 $ 326,185 Accounts receivable represents valid claims against our customers for our services rendered, net of allowances for doubtful accounts. 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. Outstanding customer receivables are reviewed regularly for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. Refer to Note 16—Supplemental Balance Sheet Information. Inventories of Materials and Supplies Inventories are primarily replacement parts and supplies held for consumption in our drilling operations. Inventories are valued at the lower of cost or net realizable value. Cost is determined on a weighted average basis and includes the cost of materials, shipping, duties 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 $36.5 million and $11.5 million for fiscal years 2020 and 2019, 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. 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 during fiscal years 2020 and 2019 and $0.4 million of capitalized interest during fiscal year 2018. 63 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 the purchase price over the fair value of assets acquired and liabilities assumed 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 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 2020, 2019 and 2018 were $212.0 million, $322.8 million and $274.7 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 2020, 2019 and 2018 was approximately $73.4 million, $11.3 million and $17.1 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. During the fiscal year ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including six industrial sites. See Note 5—Property, Plant and Equipment for additional details. Our rent revenues are as follows: (in thousands) Minimum rents Overage and percentage rents Year Ended September 30, 2020 2019 2018 $ 9,245 $ 10,168 $ 656 932 9,950 1,040 64 At September 30, 2020, minimum future rental income to be received on noncancelable operating leases was as follows (in thousands): Fiscal Year 2021 2022 2023 2024 2025 Thereafter Total $ Amount 5,512 4,553 3,564 2,975 2,350 5,358 $ 24,312 Leasehold improvement allowances are capitalized and amortized over the lease term. At September 30, 2020 and 2019, the cost and accumulated depreciation for real estate properties were as follows: (in thousands) Real estate properties Accumulated depreciation Income Taxes September 30, 2020 2019 $ $ 43,389 $ (27,588) 15,801 $ 72,507 (43,570) 28,937 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 take tax positions in our tax returns from time to time that may not ultimately be allowed by the relevant taxing authority. When we take such positions, we evaluate the likelihood of sustaining those positions and determine the amount of tax benefit arising from such positions, if any, that should be recognized in our financial statements. We recognize uncertain tax positions we believe have a greater than 50 percent likelihood of being sustained. Tax benefits not recognized by us are recorded as a liability for unrecognized tax benefits, which represents our potential future obligation to various taxing authorities if the tax positions are not sustained. See Note 9—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, nonvested restricted stock and performance share units. 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 Accounting Standards Codification ("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. Beginning in fiscal year 2019, we 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 non-employee director compensation program. The Board of Directors (the "Board") has determined to award stock-based compensation to non-employee directors solely in the form of restricted stock. The fair value of each option granted prior to fiscal year 2019 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 represented management’s best estimates, but these estimates involve inherent uncertainties and the application of management's judgment. 65 The grant date fair value of performance share units is determined through the 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. 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 drilling services operating expenses, research and development expenses and selling, general and administrative expenses in the Consolidated Statements of Operations. See Note 12—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. Treasury stock may be issued under the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan. 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 various offices, warehouses, equipment and vehicles. Rental contracts are typically made for fixed periods of one to 15 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not impose any covenants, but leased assets may not be used as security for borrowing purposes. Up until the end of fiscal year 2019, leases of property, plant and equipment were classified as either capital or operating leases. Payments made under operating leases (net of any incentives received from the lessor) were charged to the income statement on a straight-line basis over the period of the lease (“levelized lease cost”). Beginning October 1, 2019, leases are recognized as a right-of-use asset and a corresponding liability within accrued liabilities and other non-current liabilities at the date at which the leased asset is available for use by the Company. Each lease payment is allocated between the liability and finance cost. The finance cost is recognized over the lease period to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis for finance type leases and as the difference between the levelized lease cost and the finance cost for operating leases. Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments: • • • • • Fixed payments (including in-substance fixed payments), less any lease incentives receivable Variable lease payments that are based on an index or a rate Amounts expected to be payable by the lessee under residual value guarantees The exercise price of a purchase option if the lessee is reasonably certain to exercise that option, and Payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option. The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the lessee’s incremental borrowing rate is used, which is the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions. Right-of-use assets are measured at cost and are comprised of the following: • • • • The amount of the initial measurement of lease liability Any lease payments made at or before the commencement date less any lease incentives received Any initial direct costs, and Asset retirement obligations related to that lease, as applicable. Payments associated with short-term leases and leases of low-value assets are recognized on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less. Low-value assets are comprised of IT- equipment and office furniture. 66 In determining the lease term, management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. Extension options (or periods after termination options) are only included in the lease term if the lease is reasonably certain to be extended (or not terminated). The assessment is reviewed if a significant event or a significant change in circumstances occurs and is within the control of the lessee. Refer to Note 6—Leases for additional information regarding our leases. Recently Issued Accounting Updates Changes to U.S. GAAP are established by the Financial Accounting Standards Board (“FASB”) in the form of Accounting Standards Updates ("ASUs") to the FASB ASC. We consider the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable, clarifications of ASUs listed below, immaterial, or already adopted by the Company. The following table provides a brief description of recent accounting pronouncements and our analysis of the effects on our financial statements: Standard Description Recently Adopted Accounting Pronouncements ASU No. 2016-02, Leases (Topic 842) and related ASUs issued subsequent 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 ASU No. 2016-02 requires 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. 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. The amendments in this update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. Standards that are not yet adopted as of September 30, 2020 ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326) and related ASUs issued subsequent 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. 67 Date of Adoption October 1, 2019 Effect on the Financial Statements or Other Significant Matters We adopted this ASU during the first quarter of fiscal year 2020, as required. Refer to Note 6 —Leases for additional information. October 1, 2019 October 1, 2020 We early adopted this ASU during the first quarter of fiscal year 2020 on a prospective basis. The prospective impact is not material to our consolidated financial statements and disclosures. The guidance will be applied using the modified retrospective method with a cumulative effect adjustment to our beginning retained earnings balance. This update will apply primarily to receivables arising from revenue transactions. We have analyzed our historical credit losses and considered current economic conditions in developing our expected credit loss rate. We are currently finalizing our processes, internal controls and disclosures that are required upon adoption. We do not believe the implementation of this guidance will have a material impact on our consolidated financial statements and disclosures. Description This ASU simplifies the accounting for income taxes by removing certain exceptions related to Topic 740. The ASU also improves consistent application of and simplifies GAAP for other areas of Topic 740 by clarifying and amending existing guidance. This update is effective for annual and interim periods beginning after December 15, 2020. Early adoption of the amendment is permitted, including adoption in any interim period for public entities for periods for which financial statements have not yet been issued. An entity that elects to early adopt the amendments in an interim period should reflect any adjustments as of the beginning of the annual period that includes that interim period. Additionally, an entity that elects early adoption must adopt all the amendments in the same period. Upon adoption, the amendments addressed in this ASU will be applied either prospectively, retrospectively or on a modified retrospective basis through a cumulative-effect adjustment to retained earnings. 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. Upon adoption, the guidance will be applied on a retrospective basis to all periods presented. 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. October 1, 2021 We are currently evaluating the impact the new guidance may have on our consolidated financial statements and disclosures. Standard ASU No. 2019-12, Financial Instruments – Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes 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 Concentration of Credit Risk Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of temporary cash investments, short-term investments and trade receivables. The industry concentration has the potential to impact our overall exposure to market and credit risks, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. We had revenues from individual customers, within our North America Solutions segment, that constituted 10 percent or more of our total revenues as follows: (in thousands) EOG Resources, Inc. 2018 $ 258,194 In fiscal years 2020 and 2019, no individual customers constituted 10 percent or more of our total revenues. We place temporary cash investments in the United States 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. 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 drilling services is not always purely a function of the movement of commodity prices. In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets may cause difficulty for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in a reduction in customer spending and the demand for our services. This reduction in spending could have a material adverse effect on our operations. 68 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 $10 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 as well as losses in our captive insurance companies. 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. On October 1, 2019, we elected to utilize the Captive to insure the deductibles for our workers’ compensation, general liability and automobile liability insurance programs. Casualty claims occurring prior to October 1, 2019 will remain recorded within each of the operating segments and future adjustments to these claims will continue to be reflected within the operating segments. Reserves for legacy claims occurring prior to October 1, 2019, will remain as liabilities in our operating segments until they have been resolved. Changes in those reserves will be reflected in segment earnings as they occur. We will continue to utilize the Captive to finance the risk of loss to equipment and rig property assets. The Company and the Captive maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of significant events covered under these programs. Our operating subsidiaries are paying premiums to the Captive, typically on a monthly basis, for the estimated losses based on an external actuarial analysis. These premiums are currently held in a restricted account, resulting in a transfer of risk from our operating subsidiaries to the Captive. The actuarial estimated underwriting expenses for the fiscal year ended September 30, 2020 were approximately $16.4 million and were recorded within drilling services operating expenses in our Consolidated Statement of Operations. Intercompany premium revenues and expenses during the fiscal year ended September 30, 2020 amounted to $36.9 million, which were eliminated upon consolidation. These intercompany insurance premiums are reflected as segment operating expenses within the North America Solutions, Offshore Gulf of Mexico, and International Solutions reportable operating segments and are reflected as intersegment sales within "Other." The Company self- insures employee health plan exposures in excess of employee deductibles. Starting in the second quarter of fiscal year 2020, the Captive insurer issued a stop-loss program that will reimburse the Company's health plan for claims that exceed $50,000. This program will also be reviewed at the end of each policy year by an outside actuary. One hundred percent of the stop-loss premium is being set aside by the Captive as reserves. The stop-loss program does not have a material impact on a consolidated basis. International Solutions Drilling Risks International Solutions 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 Solutions 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. Many of the countries in which we operate have implemented measures in response to the COVID-19 pandemic. These measures, including imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of such facilities and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions, have significantly reduced global economic activity, thereby, resulting in lower demand for crude oil. In particular, the travel restrictions in certain countries where we operate, including the closure of their borders to travel into the country, have resulted in an inability to effectively staff or rotate personnel at, and thereby operate, certain of our rigs and could lead to an inability to fulfill our contractual obligations under contracts with customers. 69 We have also experienced certain risks related to our Argentine 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 that were implemented in September 2019. In September 2020, Argentina implemented additional currency controls in an effort to preserve Argentina's U.S. dollar reserves. As a result of these currency controls, our ability to remit funds from our Argentine subsidiary to its U.S. parent has been limited. In the past, 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. These price controls and an exchange rate freeze could be instituted again in the future. In addition, in March 2020, the Argentine government introduced labor regulations that prohibit employee dismissals or suspensions without just cause, for lack of (or reduction in) work or due to force majeure, subject to certain exceptions that may result in the payment of compensation to suspended employees and/or increased severance costs to the company. These prohibitions have resulted in significant challenges for our Argentine operations during fiscal year 2020 and it remains uncertain for how long they will be in effect. Further, there are additional concerns regarding Argentina's debt burden, notwithstanding Argentina's recent restructuring deal with international bondholders in August 2020, as Argentina attempts to manage its substantial sovereign debt issues. These concerns could further negatively impact Argentina's economy and adversely affect our Argentine operations. 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 fiscal year ended September 30, 2020, approximately 8.3 percent of our operating revenues were generated from international locations in our drilling services business compared to 7.6 percent during the fiscal year ended September 30, 2019. During the fiscal year ended September 30, 2020, approximately 61.6 percent of operating revenues from international locations were from operations in South America compared to 91.6 percent during the fiscal year ended September 30, 2019. 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. 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, for 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 North America Solutions reportable 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. During the second quarter of fiscal year 2020, as a result of new information identified related to the acquisition of DrillScan®, the acquisition date fair value of the contingent consideration and goodwill increased by approximately $1.2 million. This acquisition's measurement period closed during the quarter ended June 30, 2020 and, as a result, the purchase price accounting was finalized. 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 North America Solutions 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 included goodwill of $3.1 million. 70 NOTE 4 DISCONTINUED OPERATIONS Current and noncurrent liabilities from discontinued operations consist of municipal and income taxes payable and social obligations due within the country of Venezuela. Expenses incurred for in-country obligations are reported as discontinued operations within our Consolidated Statements of Operations. The activity for the fiscal year ended September 30, 2020 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 436,677, 21,028, and 62 Bolivars per United States dollar at September 30, 2020, 2019 and 2018, respectively. The DICOM floating rate might not reflect the barter market exchange rates. NOTE 5 PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment as of September 30, 2020 and 2019 consisted of the following: (in thousands) Drilling services equipment Tubulars Real estate properties Other Construction in progress (1) Accumulated depreciation Property, plant and equipment, net Estimated Useful Lives September 30, 2020 September 30, 2019 4 - 15 years $ 7,313,234 4 years 10 - 45 years 2 - 23 years 615,281 43,389 464,704 49,592 8,486,200 (4,839,859) $ 3,646,341 $ 7,881,323 618,310 72,507 471,803 117,761 9,161,704 (4,659,620) 4,502,084 (1) Included in construction in progress are costs for projects in progress to upgrade or refurbish certain rigs in our existing fleet. Additionally, we include other capital maintenance purchase-orders that are open/in process. As these various projects are completed, the costs are then classified to their appropriate useful life category. Impairments - Fiscal Year 2020 Consistent with our policy, we evaluate our drilling rigs and related equipment for impairment whenever events or changes in circumstances indicate the carrying value of these assets may exceed the estimated undiscounted future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessment on the future marketability of specific rigs’ asset group. During the second quarter of fiscal year 2020, several significant economic events took place that severely impacted the current demand on drilling services, including the significant drop in crude oil prices caused by OPEC+'s price war coupled with the decrease in the demand due to the COVID-19 pandemic. To maintain a competitive edge in a challenging market, the Company’s management introduced a new strategy focused on operating various types of highly capable upgraded rigs and phasing out the older, less capable fleet. This resulted in grouping the super-spec rigs of our legacy Domestic FlexRig® 3 asset group and our FlexRig® 5 asset group creating a new "Domestic super-spec FlexRig®" asset group, while combining the legacy Domestic conventional asset group, FlexRig® 4 asset group and FlexRig® 3 non-super-spec rigs into one asset group (Domestic non-super- spec asset group). Given the current and projected low utilization for our Domestic non-super-spec asset group and all International asset groups, we considered these economic factors to be indicators that these asset groups may be impaired. As a result of these indicators, we performed impairment testing at March 31, 2020 on each of our Domestic non super- spec and International conventional, FlexRig® 3, and FlexRig® 4 asset groups, which had an aggregate net book value of $605.8 million. We concluded that the net book value of each asset group is not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of $441.4 million in the Consolidated Statement of Operations for the fiscal year ended September 30, 2020. Of the $441.4 million total impairment charge recorded, $292.4 million and $149.0 million was recorded in the North America Solutions and International Solutions segments, respectively. No further impairments were recognized in fiscal year 2020. Impairment was measured as the amount by which the net book value of each asset group exceeds its fair value. The most significant assumptions used in our undiscounted cash flow model include timing on awards of future drilling contracts, drilling rig utilization, estimated remaining useful life, and net proceeds received upon future sale/disposition. These assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. 71 In determining the fair value of each asset group, we utilized a combination of income and market approaches. The significant assumptions in the valuation are based on those of a market participant and are classified as Level 2 and Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures. As of March 31, 2020, the Company also recorded an additional non-cash impairment charge related to in-progress drilling equipment and rotational inventory of $44.9 million and $38.6 million, respectively, which had aggregate book values of $68.4 million and $38.6 million, respectively, in the Consolidated Statement of Operations for the fiscal year ended September 30, 2020. Of the $83.5 million total impairment charge recorded for in-progress drilling equipment and rotational inventory, $75.8 million and $7.7 million was recorded in the North America Solutions and International Solutions segments, respectively. Impairment - Fiscal Year 2019 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 FlexRig® 4 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 FlexRig® 4 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 reduced the aggregate net book values of the FlexRig® 4 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, which was recorded in our Consolidated Statement of Operations for the fiscal year ended September 30, 2019. Of the $224.3 million total impairment charge recorded, $216.9 million and $7.4 million was recorded in our North America Solutions and International Solutions segments, 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 FlexRig® 4 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 FlexRig® 4 asset groups as of June 30, 2019, different assumptions and estimates could materially impact the analysis and our resulting conclusion. Impairments - Fiscal Year 2018 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 FlexRig® drilling rigs with high activity and demand. The sales transaction was completed in November 2018. We recorded a non-cash impairment charge within our International Solutions segment of $9.2 million, 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. 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 North America Solutions 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, 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. 72 Decommissioning While the crude oil market imbalance is a global phenomenon, it has more acutely impacted the U.S. market as a result of storage limitations during the last two quarters of fiscal year 2020. The abruptness of and the overall size of the decrease in demand for refined products, such as gasoline and diesel, has created an abundance of supply for such products which has caused the inventory levels of crude oil and its related refined products to become greatly elevated, reaching the high end of storage capabilities. This has greatly reduced the need, or in some cases, entirely eliminated the ability of refineries to use crude oil as a feedstock. As such, exploration and production ("E&P") companies, our customers, may have limited opportunities to offload their production and even then, the selling price could be at very low, uneconomical prices. Consequently, some E&P companies have chosen to shut-in and stop production, not complete additional wells drilled and/or not drill any more wells until the market imbalance corrects and it is economical to resume production and drilling wells. During the fiscal year ended September 30, 2020, we decommissioned two rigs and 35 rigs from our legacy Domestic Conventional asset group and FlexRig® 3 asset group, respectively. The decommissioned rigs were impaired as of March 31, 2020. Depreciation Depreciation in the Consolidated Statements of Operations of $474.7 million, $556.9 million and $578.4 million includes abandonments of $4.0 million, $11.4 million and $27.7 million for fiscal years 2020, 2019 and 2018, respectively. Gain on Sale of Assets We had a gain on sale of assets of $46.8 million, $39.7 million and $22.7 million in fiscal years 2020, 2019 and 2018, respectively. These gains were related to customer reimbursement for the replacement value of drill pipe damaged or lost in drilling operations. Additionally, during the fiscal year ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including six industrial sites, for total consideration, net of selling related expenses, of $40.7 million and an aggregate net book value of $13.5 million, resulting in a gain of $27.2 million, which is included within Gain on Sale of Assets on our Consolidated Statement of Operations. NOTE 6 LEASES ASC 842 Adoption On October 1, 2019, we adopted ASC 842, retrospectively through a cumulative-effect adjustment without restating comparative periods for the 2019 and 2018 fiscal years as permitted under the specific transitional provisions in ASC 842. The reclassifications and the adjustments arising from the new leasing rules are therefore recognized in the opening balance sheet on October 1, 2019. Upon the adoption of ASC 842, we recognized lease liabilities in relation to leases that had previously been classified as operating leases under the principles of ASC 840. These liabilities were measured at the present value of the remaining lease payments, discounted using the lessee’s incremental borrowing rate as of October 1, 2019, as most of our contracts do not provide an implicit rate. The weighted average lessee’s incremental borrowing rate applied to the operating lease liabilities on October 1, 2019 was approximately 2.9%. The change in accounting policy affected the following items in the balance sheet on October 1, 2019: (in thousands) Other Noncurrent Assets: September 30, 2019 Adjustments October 1, 2019 Operating lease right-of-use asset $ — $ 56,071 $ Current Liabilities: Accrued Liabilities Noncurrent Liabilities: Other — — 16,277 39,794 56,071 16,277 39,794 73 As of September 30, 2020, segment assets and liabilities have all increased from September 30, 2019 as a result of the change in accounting policy. All reportable segments were affected by the change in policy. In applying ASC 842 for the first time, we have used the following practical expedients permitted by the topic: The use of a single discount rate to a portfolio of leases with reasonably similar characteristics, • • Not to reassess whether a contract is, or contains a lease at the date of initial application; instead, for contracts entered into before the transition date, we relied on our assessment in which we applied ASC 840 prior to the adoption date, The option to not reassess initial direct cost for existing leases, and The use of hindsight in determining the lease term where the contract contains options to extend or terminate the lease. • • We have made the accounting policy election to not recognize a right-of-use asset and corresponding liability for leases with a term of 12 months or less and leases of low-value. Additionally, ASC 842 provides lessors with a practical expedient, by class of underlying asset, to not separate lease and non-lease components and account for the combined component under ASC 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 ASC 842. With respect to our drilling service contracts that commenced or were amended during the fiscal year ended September 30, 2020, we concluded that our drilling contracts contain a lease component and that the non-lease component is the predominant element of the combined component of such contracts. As such, we elected to apply the practical expedient to not separate the lease and non-lease components and account for the combined component under ASC 606. Therefore, we do not expect any change in our revenue recognition patterns or disclosures as a result of our adoption of ASC 842. Lease Position (in thousands) Operating lease commitments, including probable extensions (1) Discounted using the lessee's incremental borrowing rate at the date of initial application (Less): short-term leases recognized on a straight-line basis as expense Lease liability recognized Of which: Current lease liabilities Non-current lease liabilities $ $ $ $ October 1, 2019 September 30, 2020 62,218 $ 48,695 57,323 $ (1,252) 56,071 $ 16,277 $ 39,794 46,706 (1,456) 45,250 11,364 33,886 (1) Our future minimal rental payments exclude optional extensions that have not been exercised but are probable to be exercised in the future, those probable extensions are included in the operating lease liability balance. The recognized right-of-use assets relate to the following types of assets: (in thousands) Properties Equipment Other Total right-of-use assets October 1, 2019 September 30, 2020 $ $ 52,188 $ 3,652 231 56,071 $ 42,448 1,394 741 44,583 The right-of-use assets were measured at the amount equal to the lease liability, adjusted for the amount of any prepaid or accrued lease payments recognized on the balance sheet at September 30, 2019. Lease Costs The following table presents certain information related to the lease costs for our operating leases: (in thousands) Operating lease cost Short-term lease cost Total lease cost Year Ended September 30, 2020 $ $ 16,953 1,693 18,646 74 Lease Terms and Discount Rates The table below presents certain information related to the weighted average remaining lease terms and weighted average discount rates for our operating leases as of September 30, 2020. Weighted average remaining lease term Weighted average discount rate Lease Obligations September 30, 2020 4.9 2.7% Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of one year at September 30, 2020 (in thousands) are as follows: Fiscal Year 2021 2022 2023 2024 2025 Thereafter Total (1) Amount 11,680 8,133 7,466 7,018 3,231 638 38,166 $ $ (1) Our future minimal rental payments exclude optional extensions that have not been exercised but are probable to be exercised in the future, those probable extensions are included in the operating lease liability balance. Total rent expense was $18.6 million, $15.5 million and $13.7 million for the fiscal years ended September 30, 2020, 2019 and 2018, respectively. The future minimum lease payments for our Tulsa corporate office and our Tulsa industrial facility represent a material portion of the amounts shown in the table above. The lease agreement for our Tulsa corporate office 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 five-year renewal options, which were not recognized as part of our right-of-use assets and lease liabilities. The lease agreement for our Tulsa industrial facility, where we perform maintenance and assembly of FlexRig® components commenced on December 21, 2018 and will expire on June 30, 2025; however, we have two two-year renewal options which were recognized as part of our right-of-use assets and lease liabilities. NOTE 7 GOODWILL AND INTANGIBLE ASSETS Goodwill Goodwill represents the excess of the purchase price over the fair values of the assets acquired and liabilities assumed 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, or when indications of potential impairment exist. All of our goodwill is within our North America Solutions 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 Additions Impairment September 30, 2020 $ $ 51,705 17,791 (4,719) 64,777 18,009 82,786 1,200 (38,333) 45,653 During the second quarter of fiscal year 2020, as a result of new information identified related to the acquisition of DrillScan®, the acquisition date fair value of the contingent consideration and goodwill increased by approximately $1.2 million. 75 Intangible Assets Finite-lived intangible assets are amortized using the straight-line method over the period in which these assets contribute to our cash flows and are evaluated for impairment in accordance with our policies for valuation of long-lived assets. All of our intangible assets are within our North America Solutions reportable segment. Intangible assets consisted of the following: September 30, 2020 September 30, 2019 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 $ 16,222 $ 72,874 $ 89,096 $ 10,256 $ 78,840 Intellectual property Trade name Customer relationships 13 years 20 years 5 years 1,500 5,865 4,000 103 842 2,267 1,397 5,023 1,733 — 5,865 4,000 — 522 1,467 — 5,343 2,533 $ 100,461 $ 19,434 $ 81,027 $ 98,961 $ 12,245 $ 86,716 Amortization expense in the Consolidated Statements of Operations was $7.2 million, $5.8 million and $5.4 million for fiscal years 2020, 2019 and 2018, respectively, and is estimated to be $7.2 million for each of the next two succeeding fiscal years, approximately $6.5 million for fiscal year 2023 and approximately $6.4 million for fiscal years 2024 and 2025. Impairment - Fiscal Year 2020 Consistent with our policy, we test goodwill annually for impairment in the fourth quarter of our fiscal year, or more frequently if there are indicators that goodwill might be impaired. Due to the market conditions described in Note 5—Property, Plant and Equipment, during the second quarter of fiscal year 2020, we concluded that goodwill and intangible assets might be impaired and tested the H&P Technologies reporting unit, where the goodwill balance is allocated and the intangible assets are recorded, for recoverability. This resulted in a goodwill only non-cash impairment charge of $38.3 million recorded in the Consolidated Statement of Operations during the fiscal year ended September 30, 2020. The recoverable amount of the H&P Technologies reporting unit was determined based on a fair value calculation which uses cash flow projections based on the Company's financial projections presented to the Board covering a five-year period, and a discount rate of 14 percent. Cash flows beyond that five-year period were extrapolated using the fifth-year data with no implied growth factor. The reporting unit level is defined as an operating segment or one level below an operating segment. The recoverable amount of the intangible assets tested for impairment within the H&P Technologies reporting unit is determined based on undiscounted cash flow projections using the Company's financial projections presented to the Board covering a five-year period and extrapolated for the remaining weighted average useful lives of the intangible assets. The most significant assumptions used in our cash flow model include timing of awarded future contracts, commercial pricing terms, utilization, discount rate, and the terminal value. These assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. Although we believe the assumptions used in our analysis and the probability-weighted average of expected future cash flows are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and our resulting conclusion. Impairment - Fiscal Year 2018 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. In addition, we recorded an intangible assets impairment loss of $0.9 million. 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. 76 NOTE 8 DEBT We had the following unsecured long-term debt outstanding with maturities shown in the following table: September 30, 2020 September 30, 2019 Face Amount Unamortized Discount and Debt Issuance Cost Book Value Face Amount Unamortized Discount and Debt Issuance Cost Book Value $ 487,148 $ (6,421) $ 480,727 $ 487,148 $ (7,792) $ 479,356 487,148 — (6,421) 480,727 487,148 (7,792) 479,356 — — — — — $ 487,148 $ (6,421) $ 480,727 $ 487,148 $ (7,792) $ 479,356 (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, our subsidiary, HPIDC issued $500.0 million of 4.65 percent unsecured senior notes due 2025 of HPIDC (the "HPIDC 2025 Notes"), which were redeemed in full on September 27, 2019 as described under "––Exchange Offer, Consent Solicitation and Redemption." Interest on the HPIDC 2025 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. Exchange Offer, Consent Solicitation and Redemption On December 20, 2018, we settled an offer to exchange (the “Exchange Offer”) any and all outstanding HPIDC 2025 Notes 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, 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. Following the consummation of the Exchange Offer, HPIDC had outstanding approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes. 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 certain proposed amendments pursuant to a consent solicitation conducted concurrently with the Exchange Offer. 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 a result of such release, H&P is the only obligor under the Company 2025 Notes and the 2018 Credit Facility. 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, which was amended on November 13, 2019, providing for an unsecured revolving credit facility (the “2018 Credit Facility”) that is set to mature on November 13, 2024. The 2018 Credit Facility has $750.0 million in aggregate availability with a maximum of $75.0 million available for use as letters of credit. The 2018 Credit Facility also permits aggregate commitments under the facility to be increased by $300.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. 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. 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, 2020, the spread over LIBOR would have been 1.125 percent had borrowings been outstanding under the 2018 Credit 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, 2020, there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. 77 As of September 30, 2020, we had two separate outstanding letters of credit with banks, in the amounts of $24.8 million and $2.1 million. As of September 30, 2020, we also had a $20.0 million unsecured standalone line of credit facility, for the purpose of obtaining the issuance of international letters of credit, bank guarantees, and performance bonds. Of the $20.0 million, $4.3 million of financial guarantees were outstanding as of September 30, 2020. Subsequent to September 30, 2020, $2.6 million in financial guarantees have expired. 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, 2020, we were in compliance with all debt covenants. At September 30, 2020, aggregate maturities of long-term debt are as follows (in thousands): Year ending September 30, 2021 2022 2023 2024 2025 Thereafter NOTE 9 INCOME TAXES Income Tax Benefit and Rate The components of the benefit for income taxes are as follows: (in thousands) Current: Federal Foreign State Deferred: Federal Foreign State Total benefit $ $ — — — — 487,148 — 487,148 Year Ended September 30, 2019 2018 2020 $ $ $ 15,431 1,495 523 17,449 (127,096) (12,390) (18,069) (157,555) (140,106) $ $ 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) The amounts of domestic and foreign income (loss) before income taxes are as follows: (in thousands) Domestic Foreign Year Ended September 30, 2020 2019 2018 $ $ (458,364) $ (45,118) $ (178,134) (6,104) (636,498) $ (51,222) $ 27,436 (11,595) 15,841 78 Effective income tax rates as compared to the U.S. Federal income tax rate are as follows: U.S. Federal income tax rate Effect of foreign taxes State income taxes, net of federal tax benefit Remeasurement of deferred tax related to Tax Cuts and Jobs Act Other impact of foreign operations Non-deductible meals and entertainment Equity compensation Excess officer's compensation Contingent consideration adjustment Other Effective income tax rate Year Ended September 30, 2020 2019 2018 21.0% (0.2) 2.8 — (0.5) (0.2) (0.3) (0.2) — (0.4) 21.0% (0.6) 17.2 — 0.9 (2.5) 2.7 (1.9) 4.5 (4.8) 24.5 % 87.8 68.8 (3,169.4) (43.4) 8.2 (5.3) 1.7 10.7 4.1 22.0% 36.5% (3,012.3)% 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. 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. 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, 2020 2019 $ 685,389 $ 867,909 1,957 26,138 713,484 — 7,369 10,360 33,747 32,481 15,632 99,589 (36,780) 62,809 — 15,681 883,590 771 7,324 14,294 41,126 54,511 2,531 120,557 (43,578) 76,979 $ 650,675 $ 806,611 The change in our net deferred tax assets and liabilities is impacted by foreign currency remeasurement. As of September 30, 2020, we had federal, state and foreign tax net operating loss carryforwards of $7.3 million, $25.7 million and $39.9 million, respectively, and foreign tax credit carryforwards of approximately $23.9 million (of which $19.1 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 2021 through 2040. The valuation allowance is primarily attributable to foreign net operating loss carryforwards of $11.3 million, foreign tax credit carryforwards of $19.1 million, equity compensation of $4.9 million, and foreign minimum tax credit carryforwards of $1.4 million which more likely than not will not be utilized. 79 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, 2020, and 2019, we had accrued interest and penalties of $2.8 million and $2.1 million, respectively. A reconciliation of the change in our gross unrecognized tax benefits for the fiscal years ended September 30, 2020 and 2019 is as follows: (in thousands) Unrecognized tax benefits at October 1, 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, 2020 2019 15,759 $ 14,905 (2,338) 20 (1) (28) 1,067 (185) 13,440 $ 15,759 $ $ As of September 30, 2020, and 2019, our liability for unrecognized tax benefits includes $13.0 million and $15.3 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 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. 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 2016 through 2019, with exception of certain state jurisdictions currently under audit. The tax years remaining open to examination by foreign jurisdictions include 2003 through 2019. NOTE 10 SHAREHOLDERS’ EQUITY The Company has an evergreen authorization from the Board 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 the fiscal year ended September 30, 2020, we purchased 1.5 million common shares at an aggregate cost of $28.5 million, which are held as treasury shares. We purchased 1.0 million common shares at an aggregate cost of $42.8 million, which are held as treasury shares, during the fiscal year ended September 30, 2019. We had no purchases of common shares during the fiscal year ended September 30, 2018. As of September 30, 2020, we declared $209.8 million in cash dividends. A cash dividend of $0.25 per share was declared on September 9, 2020 for shareholders of record on November 13, 2020, payable on December 1, 2020. As a result, we recorded a Dividend Payable of $27.2 million on our Consolidated Balance Sheets as of September 30, 2020. 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, 2020 2019 2018 $ $ $ $ — $ — $ (33,923) (37,084) (33,923) $ (37,084) $ — $ — $ (26,188) (28,635) (26,188) $ (28,635) $ 44,023 (21,693) 22,330 29,071 (12,521) 16,550 (1) 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 loss, net of tax, by component for the fiscal year ended September 30, 2020: 80 (in thousands) Balance at September 30, 2019 Activity during the period Amounts reclassified from accumulated other comprehensive loss Net current-period other comprehensive loss Balance at September 30, 2020 NOTE 11 REVENUE FROM CONTRACTS WITH CUSTOMERS Drilling Services Revenue Defined Benefit Pension Plan $ $ (28,635) 2,447 2,447 (26,188) The majority 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 drilling services, including our technology solutions, 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 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 fiscal years ended September 30, 2020, 2019 and 2018, early termination revenue associated with term contracts was approximately $73.4 million, $11.3 million and $17.1 million, respectively. During the fiscal years ended September 30, 2020, 2019 and 2018, notification fee revenue related to well-to-well contracts was approximately $2.9 million, $1.2 million and $0.2 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, 2020, and 2019, we had capitalized fulfillment costs of $6.2 million and $13.9 million, respectively. 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. 81 Remaining Performance Obligations The total aggregate transaction price allocated to the unsatisfied performance obligations, commonly referred to as backlog, as of September 30, 2020 was approximately $670.1 million, of which $446.7 million is expected to be recognized during fiscal year 2021, and approximately $223.4 million in fiscal year 2022 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. However, the impact of the COVID-19 pandemic is inherently uncertain, and, as a result, the Company is unable to reasonably estimate the duration and ultimate impacts of the pandemic, including the effect it may have on our contractual obligations with our customers. 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 Contract liabilities balance at September 30, 2019 Payment received/accrued and deferred Revenue recognized during the period Contract liabilities balance at September 30, 2020 NOTE 12 STOCK-BASED COMPENSATION September 30, 2020 September 30, 2019 $ 2,367 $ 2,151 September 30, 2020 $ $ 38,472 30,863 (45,981) 23,354 19,312 (34,030) 8,636 On March 3, 2020, the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan (the “2020 Plan”) was approved by our stockholders. The 2020 Plan replaces our stockholder-approved Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan (the "2016 Plan"). The 2020 Plan is a stock and cash-based incentive plan that, among other things, authorizes the Board or Human Resources Committee of the Board to grant executive officers, employees and non-employee directors stock options, stock appreciation rights, restricted shares and restricted share units (including performance share units), share bonuses, other share- based awards and cash awards. 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 ten years after the grant date. Awards outstanding under the Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan, the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan and the 2016 Plan remain subject to the terms and conditions of those plans. Beginning with fiscal year 2019, we replaced stock options with performance share units as a component of our executives' long-term equity incentive compensation. As a result, there were no stock options granted during the fiscal years ended September 30, 2020 and 2019. We have also eliminated stock options as an element of our non-employee director compensation program. The Board has determined to award stock-based compensation to non-employee directors solely in the form of restricted stock. During the fiscal year ended September 30, 2020, 727,009 shares of restricted stock awards and 258,857 performance share units were granted under the 2016 Plan and 54,118 shares of restricted stock awards were granted under the 2020 Plan. 82 A summary of compensation cost for stock-based payment arrangements recognized in drilling services operating expense, research and development expense and selling, general and administrative expense in fiscal years 2020, 2019 and 2018 is as follows: (in thousands) Stock-based compensation expense Stock options Restricted stock Performance share units Stock-based compensation benefit included in restructuring charges September 30, 2020 2019 2018 $ $ 1,753 $ 3,721 $ 30,605 7,454 (3,483) 26,149 4,422 — 7,913 23,774 — — 36,329 $ 34,292 $ 31,687 Of the total stock-based compensation expense, $9.1 million was recorded in drilling services operating expense, $0.8 million was recorded in research and development expense, $29.9 million in selling, general and administrative expense and $(3.5) million was recorded in restructuring charges during the year ended September 30, 2020 on our Consolidated Statements of Operations. Stock Options Vesting requirements for stock options are determined by the Human Resources Committee of the Board. 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 2.2% 36.1% 4.7% 6.0 (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 per share for fiscal year 2018. The following summary reflects the stock option activity for our common stock and related information for fiscal years 2020, 2019 and 2018: (shares in thousands) Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, 2020 Weighted- Average Exercise Price Shares 2019 Weighted- Average Exercise Price Shares 2018 Weighted- Average Exercise Price 60.86 — 38.02 61.76 62.41 62.38 3,499 $ — (217) (44) 3,238 2,482 $ $ 58.62 — 24.46 62.14 60.86 60.38 3,278 $ 694 (375) (98) 3,499 2,193 $ $ 56.41 59.03 36.88 70.77 58.62 56.31 Shares 3,238 $ — (201) (174) 2,863 2,516 $ $ 83 The following table summarizes information about stock options at September 30, 2020 (shares in thousands): Range of Exercise Prices $40.00 to $55.00 $55.00 to $70.00 $70.00 to $85.00 Outstanding Stock Options Exercisable Stock Options Shares Weighted-Average Remaining Life Weighted-Average Exercise Price Shares Weighted-Average Exercise Price 472 1,918 473 2,863 $ 1.82 5.07 4.92 51.86 60.56 80.47 462 $ 1,641 412 2,515 51.83 60.82 80.43 At September 30, 2020, the weighted-average remaining life of exercisable stock options was 4.16 years and the aggregate intrinsic value was zero with a weighted-average exercise price of $62.38 per share. The number of options vested or expected to vest at September 30, 2020 was 347,093 with an aggregate intrinsic value of zero and a weighted-average exercise price of $62.63 per share. As of September 30, 2020, the unrecognized compensation cost related to the stock options was $1.2 million. That cost is expected to be recognized over a weighted-average period of 1.22 years. The total intrinsic value of options exercised during fiscal years 2020, 2019 and 2018 was $0.3 million, $7.9 million and $9.9 million, respectively. The grant date fair value of shares vested during fiscal years 2020, 2019 and 2018 was $6.0 million, $8.0 million and $8.8 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, 2020, there was $31.4 million of total unrecognized compensation cost related to unvested restricted stock awards. That cost is expected to be recognized over a weighted-average period of 2.4 years. A summary of the status of our restricted stock awards as of September 30, 2020, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2020, 2019 and 2018, is as follows: (shares in thousands) Shares 2020 2019 2018 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 Non-vested restricted stock outstanding at October 1, 1,085 $ 61.28 1,001 $ Granted (1) Vested (2) Forfeited 781 (501) (85) 39.99 59.46 48.98 475 (371) (20) 63.74 58.45 64.32 60.85 $ 659 626 (258) (26) Non-vested restricted stock outstanding at September 30, 1,280 $ 49.81 1,085 $ 61.28 1,001 $ 70.76 59.53 70.60 66.73 63.74 (1) The number of restricted stock awards granted includes phantom shares that confer the benefits of owning company stock without the actual ownership or transfer of any shares. There were 20,616 phantom shares granted during fiscal year 2020. (2) The number of restricted stock awards vested includes shares that we withheld on behalf of our employees to satisfy the statutory tax withholding requirements. 84 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. 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 percent 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 companies' stock, risk free rate of return and cross-correlations between the Company and our Peer Group companies. The valuation model assumes dividends are immediately reinvested. As of September 30, 2020, there was $6.6 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 September 30, 2020 and changes in non-vested performance share units outstanding during the fiscal year ended September 30, 2020 is presented below: (in thousands, except per share amounts) Shares 2020 Weighted- Average Grant Date Fair Value per Share 2019 Weighted- Average Grant Date Fair Value per Share Shares Non-vested performance share units outstanding at September 30, 2019 Granted Forfeited $ 145 259 (67) Non-vested performance share units outstanding at September 30, 2020 337 $ 62.66 43.40 46.35 51.09 — $ 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) 2020 2019 1.6% 34.8% 3.2 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 13 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. 85 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. 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 Income (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, 2020 2019 2018 $ (496,392) $ (32,510) $ 493,010 1,895 (494,497) (1,146) (33,656) (10,338) 482,672 (2,647) (3,102) (4,346) (499,039) 1,895 (497,144) (35,612) (1,146) (36,758) 488,664 (10,338) 478,326 Effect of reallocating undistributed earnings of unvested shareholders — — 7 Numerator for diluted earnings (loss) per share: From continuing operations From discontinued operations Denominator: (499,039) 1,895 (35,612) (1,146) 488,671 (10,338) $ (497,144) $ (36,758) $ 478,340 Denominator for basic earnings (loss) per share - weighted-average shares 108,009 109,216 Effect of dilutive shares from stock options, restricted stock and performance share units — — Denominator for diluted earnings (loss) per share - adjusted weighted-average shares 108,009 109,216 Basic earnings (loss) per common share: Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) Diluted earnings (loss) per common share: Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) $ $ $ $ (4.62) $ 0.02 (4.60) $ (4.62) $ 0.02 (4.60) $ (0.33) $ (0.01) (0.34) $ (0.33) $ (0.01) (0.34) $ 108,851 536 109,387 4.49 (0.10) 4.39 4.47 (0.10) 4.37 We had a net loss for fiscal years 2020 and 2019. 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 potentially dilutive average shares attributable to outstanding equity awards were excluded from the calculation of diluted earnings (losses) per share because their inclusion would have been anti-dilutive: (in thousands, except per share amounts) Potentially dilutive shares excluded as anti-dilutive Weighted-average price per share 2020 2019 2018 4,004 3,031 $ 60.72 $ 63.33 $ 1,559 68.28 86 NOTE 14 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 $19.8 million and $15.7 million at September 30, 2020 and 2019, 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 and in federally insured deposit accounts. 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, 2020 and 2019. The following table summarizes our assets and liabilities 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 Other Total short-term investments Cash and cash equivalents Investments Other current assets Other assets September 30, 2020 Fair Value Level 1 Level 2 Level 3 $ $ $ $ $ $ 1,370 78,156 7,817 1,992 89,335 487,884 11,766 45,577 3,286 — $ — $ 1,370 78,156 $ $ 7,817 $ 1,992 9,809 487,884 7,274 45,577 3,286 — $ — 79,526 — 3,992 — — — — — — — — 500 — — 500 Total assets measured at fair value $ 637,848 $ 553,830 $ 83,518 $ Liabilities: Contingent earnout liability $ 9,123 $ — $ — $ 9,123 At September 30, 2020, 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, 2020, 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. 87 Our financial instruments measured using Level 3 unobservable inputs primarily consist of potential earnout payments primarily associated with our business acquisitions in fiscal year 2019. The following table presents a reconciliation of changes in the fair value of our financial liabilities classified as Level 3 fair value measurements in the fair value hierarchy for fiscal years 2020 and 2019: (in thousands) Net liabilities at beginning of period Additions Total gains or losses: Included in earnings Settlements (1) Net liabilities at end of period 2020 2019 $ 18,373 $ 1,500 (2,500) (8,250) 11,160 18,373 (11,160) — $ 9,123 $ 18,373 (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 related to our financial liabilities at September 30, 2020: Fair Value Valuation Technique Unobservable Input Unobservable Input Range Weighted Average (1) $1,000 Monte Carlo simulation Discount rate $8,123 Probability Analysis Revenue Volatility Risk free rate Discount rate Payment amounts Probabilities 1.6% 46.2% 1.2% 1.0% $5,250 - $7,000 $ 40% - 60% 6,400 53% (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. 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, 2020 and 2019: (in millions) Carrying value of long-term fixed-rate debt Fair value of long-term fixed-rate debt September 30, 2020 2019 $ $ 480.7 534.5 $ $ 479.4 526.4 The fair value for the $534.5 million fixed-rate debt was based on broker quotes at September 30, 2020. The notes are classified within Level 2 of the fair value hierarchy as they are not actively traded in markets. The estimated fair value of our investments, reflected on our Consolidated Balance Sheets as Investments, is primarily based on Level 1 inputs. As a result of the change in the fair value of our investments, we recorded a loss of $8.7 million for the fiscal year ended September 30, 2020. 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. 88 NOTE 15 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, 2020 and a statement of the funded status as of September 30, 2020 and 2019: (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 2020 2019 116,146 $ 119,845 119,845 $ 106,205 3,598 4,310 (11,607) 4,389 16,914 (7,663) 116,146 $ 119,845 91,142 $ 6,535 33 (11,607) 86,103 $ 94,897 3,865 43 (7,663) 91,142 (30,043) $ (28,703) $ $ $ $ $ $ The amounts recognized in the Consolidated Balance Sheets at September 30, 2020 and 2019 are as follows (in thousands): Accrued liabilities Noncurrent liabilities-other Net amount recognized $ $ (18) $ (30,025) (30,043) $ (50) (28,653) (28,703) The amounts recognized in Accumulated Other Comprehensive Income (Loss) at September 30, 2020 and 2019, and not yet reflected in net periodic benefit cost, are as follows (in thousands): Net actuarial loss $ (33,923) $ (37,084) 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 $2.4 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, 2020 2019 2018 3.16% 2.66% 4.65% 4.27% 3.16% 5.60% 3.79% 4.27% 6.06% The mortality table issued by the Society of Actuaries in October 2019 was used for the September 30, 2020 pension calculation. We did not make any contributions to the Pension Plan in fiscal year 2020. In fiscal year 2021, we do not expect minimum contributions required by law to be needed. However, we may make contributions in fiscal year 2021 if needed to fund unexpected distributions in lieu of liquidating pension assets. 89 Components of the net periodic pension expense were as follows: (in thousands) Interest cost Expected return on plan assets Recognized net actuarial loss Settlement Net pension expense Year Ended September 30, 2020 2019 2018 $ $ 3,598 $ 4,389 $ (4,784) 2,718 3,001 (5,523) 1,229 1,953 4,533 $ 2,048 $ 4,077 (5,555) 1,926 913 1,361 We record settlement expense when benefit payments exceed the total annual 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). 2021 2022 2023 2024 2025 2026 – 2030 Total $ 5,931 $ 6,910 $ 6,980 $ 7,023 $ 7,141 $ 33,599 $ 67,584 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 2021 and the asset allocation for the Pension Plan at the end of fiscal years 2020 and 2019, by asset category, follows: Asset Category U.S. equities International equities Fixed income Total Plan Assets Target Allocation September 30, 2021 2020 2019 45% 20 35 100% 42% 22 36 100% 47% 16 37 100% The fair value of Pension Plan assets at September 30, 2020 and 2019, summarized by level within the fair value hierarchy described in Note 14—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 Oil and gas properties Total September 30, 2020 Total Level 1 Level 2 Level 3 $ 1,541 $ 1,541 $ — $ 35,660 17,328 17,447 14,044 84,479 83 35,660 17,328 17,447 14,044 84,479 — — — — — — — $ 86,103 $ 86,020 $ — $ — — — — — — 83 83 90 (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 As of September 30, 2020, and 2019, the Pension Plan’s financial assets utilizing Level 1 inputs are valued based on quoted prices in active markets for identical securities. As of September 30, 2019, the Pension Plan’s Level 2 financial assets include domestic common stock. As of September 30, 2020, and 2019, 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, 2020 and 2019: (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, 2020 2019 $ $ 161 $ (78) 83 $ 116 45 161 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 $23.8 million, $30.5 million and $26.6 million in fiscal years 2020, 2019 and 2018, respectively. NOTE 16 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in our reserve for bad debt for fiscal years 2020, 2019 and 2018: (in thousands) Reserve for bad debt: Balance at October 1, Provision for bad debt (Write-off) recovery of bad debt Balance at September 30, 2020 2019 2018 $ $ 9,927 $ 6,217 $ 2,203 (10,310) 2,321 1,389 1,820 $ 9,927 $ 5,721 2,193 (1,697) 6,217 91 Accounts receivable, prepaid expenses and other current assets, accrued liabilities and long-term liabilities at September 30, 2020 and 2019 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 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 mobilization revenue Accrued income taxes Escrow Litigation and claims Contingent earnout liability Operating lease 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 Operating lease liability Payroll tax deferral(1) Other $ $ $ $ $ $ $ September 30, 2020 2019 150,249 $ 461,774 42,374 33,828 192,623 $ 495,602 45,577 $ 4,528 8,655 7,484 7,273 2,367 13,421 31,291 10,571 5,556 5,209 9,113 2,151 5,037 89,305 $ 68,928 10,942 $ 27,068 39,762 36,518 9,266 5,705 — 138 393 4,926 11,364 9,360 34,992 79,465 50,566 37,117 25,426 14,737 19,277 1,388 9,990 5,535 — 8,599 155,442 $ 287,092 54,043 $ 37,369 4,197 2,955 2,895 33,886 10,205 1,630 51,768 37,118 12,838 9,471 2,544 — — 2,007 Total noncurrent liabilities — other $ 147,180 $ 115,746 (1) Deferral related to the provisions within the Coronavirus Aid, Relief, and Economic Security Act, passed on March 27, 2020, which allows for the deferral of the employer share of Social Security tax. NOTE 17 COMMITMENTS AND CONTINGENCIES Purchase Commitments Equipment, parts and supplies are ordered in advance to promote efficient construction and capital improvement progress. At September 30, 2020, we had purchase commitments for equipment, parts and supplies of approximately $2.7 million. Lease Obligations Refer to Note 6—Leases for additional information on our lease obligations. 92 Guarantee Arrangements We are contingently liable to sureties in respect of bonds issued by the sureties in connection with certain commitments entered into by us in the normal course of business. We have agreed to indemnify the sureties for any payments made by them in respect of such bonds. Contingencies 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. Our wholly-owned subsidiaries, HPIDC, and Helmerich & Payne de Venezuela, C.A. filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. and PDVSA Petroleo, S.A., seeking damages for the taking of their Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. 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 fiscal 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. 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. A settlement agreement was reached with the operator. As of September 30, 2019, we accrued $9.5 million for this lawsuit, which was subsequently paid out during the fiscal year ended September 30, 2020. The Company and its subsidiaries are parties to various other pending legal actions arising in the ordinary course of our business. We maintain insurance against certain business risks subject to certain deductibles. 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. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed. NOTE 18 BUSINESS SEGMENTS AND GEOGRAPHIC INFORMATION Description of the Business We are a performance-driven drilling solutions and technologies company based in Tulsa, Oklahoma with operations in all major U.S. onshore basins as well as South America and the Middle East. Our drilling operations consist mainly of contracting Company-owned drilling equipment primarily to large oil and gas exploration companies. We believe we are the recognized industry leader in drilling as well as technological innovation. During the third quarter of fiscal year 2020, as part of our restructuring efforts (see Note 19—Restructuring Charges) and consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, we implemented organizational changes. We are moving from a product-based offering, such as a rig or separate technology package, to an integrated solution-based approach by combining proprietary rig technology, automation software, and digital expertise into our rig operations. Operations previously reported within the former U.S. Land and H&P Technologies operating and reportable segments are now managed and presented within the North America Solutions reportable segment. As a result, beginning with the third quarter of fiscal year 2020, our drilling services operations are organized into the following reportable operating business segments: North America Solutions, Offshore Gulf of Mexico and International Solutions. All prior period segment disclosures have been recast for these segment changes. Our real estate operations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are included in "Other." Consolidated revenues and expenses reflect the elimination of intercompany transactions. 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. External revenues included in "Other" primarily consist of rental income. 93 Segment Performance We evaluate segment performance based on income or loss from continuing operations (segment operating income (loss)) 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 • Restructuring charges but excludes gain on sale of assets and corporate selling, general and administrative costs, corporate depreciation, and corporate restructuring charges. 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. Summarized financial information of our reportable segments for the fiscal years ended September 30, 2020, 2019 and 2018 is shown in the following tables: Segment operating income (loss) Depreciation and amortization (393,902) 438,039 7,478 11,681 (in thousands) External sales Intersegment Total sales (in thousands) External sales Intersegment Total sales (in thousands) External sales Intersegment Total sales September 30, 2020 North America Solutions Offshore Gulf of Mexico International Solutions Other Eliminations Total $ 1,474,380 $ 143,149 $ 144,185 $ 12,213 $ — $ 1,773,927 — — 1,474,380 143,149 — 144,185 (162,368) 17,531 36,901 49,114 4,403 1,241 (36,901) (36,901) — 1,773,927 — — (544,389) 468,492 September 30, 2019 North America Solutions (1) Offshore Gulf of Mexico International Solutions Other Eliminations Total $ 2,426,191 $ 147,635 $ 211,731 $ 12,933 $ — $ 2,798,490 — — — — 2,426,191 147,635 211,731 12,933 Segment operating income Depreciation and amortization 80,898 504,466 19,594 10,010 5,366 35,466 3,375 1,523 (1) Operations previously reported within the H&P Technologies reportable segment are now managed and presented within the North America Solutions reportable segment. September 30, 2018 North America Solutions (1) Offshore Gulf of Mexico International Solutions Other Eliminations Total $ 2,093,601 $ 142,500 $ 238,356 $ 12,811 $ — $ 2,487,268 — — — — 2,093,601 142,500 238,356 12,811 Segment operating income (loss) Depreciation and amortization 108,697 511,958 26,124 10,392 (683) 46,826 5,883 1,486 (1) Operations previously reported within the H&P Technologies reportable segment are now managed and presented within the North America Solutions reportable segment. 94 — — — — — 2,798,490 109,233 551,465 — — — — — 2,487,268 140,021 570,662 The following table reconciles segment operating income (loss) per the tables above to income (loss) 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 selling, general and administrative costs, corporate depreciation and corporate restructuring charges Operating income (loss) from continuing operations Other income (expense) Interest and dividend income Interest expense Gain (loss) on investment securities Gain on sale of subsidiary Other Total unallocated amounts Year Ended September 30, 2020 2019 2018 $ (544,389) $ 109,233 $ 140,021 46,775 39,691 22,660 (122,573) (620,187) (128,342) (129,717) 20,582 32,964 7,304 (24,474) (8,720) 14,963 (5,384) (16,311) 9,468 (25,188) (54,488) — (1,596) (71,804) 8,017 (24,265) 1 — (876) (17,123) Income (loss) from continuing operations before income taxes $ (636,498) $ (51,222) $ 15,841 The following table reconciles segment total assets to total assets as reported on the Consolidated Balance Sheets: (in thousands) Total assets (1) North America Solutions (2) Offshore Gulf of Mexico International Solutions Other Investments and corporate operations Total assets from continuing operations Discontinued operations Year Ended September 30, 2020 2019 $ 3,812,718 $ 5,284,141 93,501 181,181 22,144 4,109,544 720,077 4,829,621 — 102,442 217,094 32,532 5,636,209 203,306 5,839,515 — $ 4,829,621 $ 5,839,515 (1) Assets by segment exclude investments in subsidiaries and intersegment activity. (2) Operations previously reported within the H&P Technologies reportable segment are now managed and presented within the North America Solutions reportable segment. The following table presents revenues from external customers by country based on the location of service provided: (in thousands) Operating revenues United States Argentina Bahrain United Arab Emirates Colombia Other Foreign Total Year Ended September 30, 2020 2019 2018 $ 1,626,407 $ 2,585,008 $ 2,247,400 84,402 28,653 24,716 6,414 3,335 165,718 190,038 11,528 4,728 29,757 1,751 9,525 — 38,793 1,512 $ 1,773,927 $ 2,798,490 $ 2,487,268 95 The following table presents property, plant and equipment by country based on the location of service provided: (in thousands) Property, plant and equipment, net United States Argentina Colombia Other Foreign Total NOTE 19 RESTRUCTURING CHARGES Year Ended September 30, 2020 2019 $ 3,562,525 $ 4,269,405 49,419 21,740 12,657 132,321 61,757 38,601 $ 3,646,341 $ 4,502,084 Beginning in the third quarter of fiscal year 2020, we implemented cost controls and began evaluating further measures to respond to the combination of weakened commodity prices, uncertainties related to the COVID-19 pandemic, and the resulting market volatility. We restructured our operations to accommodate scale during an industry downturn and to re-organize our operations to align to new marketing and management strategies. We commenced a number of restructuring efforts as a result of this evaluation, which included, among other things a reduction in our capital allocation plans, changes to our organizational structure, and a reduction of staffing levels. Costs incurred, as of September 30, 2020, in connection with the restructuring are comprised of one-time severance benefits to employees who were voluntarily or involuntarily terminated, benefits related to forfeitures and costs related to modification of stock-based compensation awards. The following table summarizes the Company's restructuring charges incurred during the fiscal year ended September 30, 2020: (in thousands) Employee termination benefits Stock-based compensation benefit Total restructuring charges $ $ North America Solutions Offshore Gulf of Mexico International Solutions Other Corporate G&A Total 10,041 $ 1,432 $ 2,991 $ 321 $ 4,745 $ (3,036) (178) (11) (61) (197) 7,005 $ 1,254 $ 2,980 $ 260 $ 4,548 $ 19,530 (3,483) 16,047 The following table summarizes the Company's accrual for restructuring charges for the fiscal year ended September 30, 2020: (in thousands) Accrued restructuring charges at September 30, 2019 Charges Cash payments Accrued restructuring charges at September 30, 2020 Employee Termination Benefits $ $ — 19,530 (18,979) 551 These expenses are recorded within restructuring charges on our Consolidated Statements of Operations for the fiscal year ended September 30, 2020 and the related liability is recorded within accounts payable on our Consolidated Balance Sheets at September 30, 2020. 96 NOTE 20 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Total (1) Fiscal Year 2020 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) $ 614,657 $ 633,639 $ 317,364 $ 208,267 $ 1,773,927 31,368 30,729 30,605 0.27 0.27 0.27 0.27 (518,541) (420,468) (420,540) (3.88) (3.88) (3.88) (3.88) (57,584) (46,007) (45,599) (0.43) (0.43) (0.43) (0.43) (75,430) (60,646) (58,963) (0.57) (0.55) (0.57) (0.55) (620,187) (496,392) (494,497) (4.62) (4.60) (4.62) (4.60) (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 thousands, except per share amounts) Included within net income (loss): Gain from the sale of assets, after tax Asset impairment charges, after tax Restructuring charges, after tax Effect on diluted earnings per common share: Gain from the sale of assets, after tax Asset impairment charges, after tax Restructuring charges, after tax Fiscal Year 2020 Quarters Ended First Quarter Second Quarter Third Quarter Fourth Quarter 3,314 — — 0.03 — — 7,985 (436,225) 3,254 — — (12,001) 21,674 — (428) 0.07 (4.02) — 0.03 — (0.11) 0.2 — — (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 year due to changes in the average number of common shares outstanding. (in thousands, except per share amounts) Included within net income (loss): Gain from the sale of assets, after tax Asset impairment charges, after tax Effect on diluted earnings per common share: Gain from the sale of assets, after tax Asset impairment charges, after tax Fiscal Year 2019 Quarters Ended First Quarter Second Quarter Third Quarter Fourth Quarter 8,886 — 0.08 — 7,718 (173,227) 0.07 (1.58) 9,752 — 0.09 — 4,268 — 0.04 — 97 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. Our assessment of our system of internal controls included the consideration of a high proportion of our control owners and control performers working remotely due to Federal and State social distancing guidelines. 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” and “Delinquent Section 16(a) Reports” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2021, to be filed with the SEC not later than 120 days after September 30, 2020. 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 Year 2020” and “Corporate Governance— Compensation Committee Interlocks and Insider Participation” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2021, to be filed with the SEC not later than 120 days after September 30, 2020. 98 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 Directors and Management” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 2, 2021, to be filed with the SEC not later than 120 days after September 30, 2020. 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 2, 2021, to be filed with the SEC not later than 120 days after September 30, 2020. 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 2, 2021, to be filed with the SEC not later than 120 days after September 30, 2020. 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 20, 2020, 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, 2020 and 2019 Consolidated Statements of Operations for the Years Ended September 30, 2020, 2019 and 2018 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended September 30, 2020, 2019 and 2018 Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2020, 2019 and 2018 Consolidated Statements of Cash Flows for the Years Ended September 30, 2020, 2019 and 2018 Notes to Consolidated Financial Statements Page 52 56 57 58 59 60 61 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 4.1 4.2 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). Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated herein by reference to Exhibit 4.1 of the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2019, SEC File No. 001-04221). 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). 99 4.3 4.4 4.5 4.6 4.7 10.1 10.2 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). 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). 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). Amendment No. 1 to Credit Agreement, dated November 13, 2019, among Helmerich & Payne, Inc., the lenders 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, 2019, SEC File No. 001-04221). *10.3 Form of Change of Control Agreement applicable to executive officers and certain other employees of Helmerich & Payne, Inc., adopted September 9, 2020 (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on September 14, 2020, SEC File No. 001-04221). *10.4 Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan (incorporated herein by reference to Appendix “A” of the Company’s Proxy Statement on Schedule 14A filed on January 26, 2006, SEC File No. 001-04221). *10.5 2012-1 Amendment to Helmerich & Payne, Inc. 2005 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, SEC File No. 001-04221). *10.6 *10.7 *10.8 *10.9 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). 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). *10.10 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). *10.11 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). 100 *10.12 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). *10.13 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). *10.14 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). *10.15 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). *10.16 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). *10.17 *10.18 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). *10.19 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). *10.20 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). *10.21 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). *10.22 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). *10.23 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). *10.24 Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan (incorporated herein by reference to Appendix “A” of the Company’s Proxy Statement on Schedule 14A filed on January 21, 2020, SEC File No. 001-04221). *10.25 Helmerich & Payne, Inc. Director Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, SEC File No. 001-04221). *10.26 Form of Restricted Stock Award Agreement for the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan applicable to Directors (incorporated herein by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, SEC File No. 001-04221). *10.27 Form of Annual Three-Year Performance-Vested Restricted Share Unit Award Agreement for the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan. *10.28 Form of Standard Three-Year Performance-Vested Restricted Share Unit Award Agreement for the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan. *10.29 Form of Restricted Stock Award Agreement for the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan applicable to employees. *10.30 Agreement and Release, dated July 17, 2020, between Rob Stauder and Helmerich & Payne International Drilling Co. 101 21 List of Subsidiaries of the Company. 23.1 Consent of Independent Registered Public Accounting Firm. 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. 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. 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. 31.1 31.2 32 101 Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income (Loss), (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. 102 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, Director, President and Chief Executive Officer Date: November 20, 2020 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) November 20, 2020 Senior Vice President and Chief Financial Officer (Principal Financial Officer) November 20, 2020 Vice President and Chief Accounting Officer (Principal Accounting Officer) November 20, 2020 Director and Chairman of the Board November 20, 2020 Director Director Director Director Director Director Director Director Director 103 November 20, 2020 November 20, 2020 November 20, 2020 November 20, 2020 November 20, 2020 November 20, 2020 November 20, 2020 November 20, 2020 November 20, 2020 (This page has been left blank intentionally.) DIRECTORS THE H&P WAY THE H&P WAY IS A CORE SET OF PILLARS THAT LAY THE FOUNDATION OF HOW WE CREATE, INTERACT AND COMMUNICATE. OUR PURPOSE Improving lives through efficient and responsible energy WHAT WE DO We safely provide performance-driven drilling solutions OUR VALUES Our values reflect who we are and the way we interact with one another, our customers, partners and shareholders Actively C.A.R.E. Teamwork We treat one another with respect. We We listen to one another and work care about each other. We are committed across teams toward a common goal. to Controlling and Removing Exposures We collaborate to achieve results and for ourselves and others. focus on success with our customers and shareholders. Do the Right Thing We are honest and transparent. We tackle tough situations, make decisions and speak up when needed. Service Attitude We do our part and more for those around us. We consider the needs of others and provide solutions to meet their needs. Innovative Spirit We constantly work to improve and try new approaches. We make decisions based on our clients’ challenges and goals with the long-term view in mind. Randy A. Foutch **(***) Lead Director Chairman, Retired, Laredo Petroleum, Inc. Director since 2007 Delaney Bellinger *(***) Vice President and Chief Information Officer, Retired, Huntsman Corporation Director since 2018 Kevin G. Cramton *(***) Operating Partner, HCI Equity Partners Director since 2017 Hans Helmerich Chairman of the Board Director since 1987  John W. Lindsay President and Chief Executive Officer Director since 2012 José R. Mas **(***) Chief Executive Officer, MasTec, Inc. Director since 2017 Thomas A. Petrie **(***) Chairman, Petrie Partners, LLC Director since 2012 Donald F. Robillard, Jr. *(***) Executive Vice President, Chief Financial Officer and Chief Risk Officer, Retired, Hunt Consolidated, Inc. Director since 2012 Edward B. Rust, Jr. *(***) Chairman and Chief Executive Officer, Retired, State Farm Mutual Automobile Insurance Company Director since 1997 Mary M. VanDeWeghe **(***) President and Chief Executive Officer, Forte Consulting, Inc. Director since 2019 John D. Zeglis *(***) Chairman and Chief Executive Officer, Retired, AT&T Wireless Services, Inc. Director since 1989  * Member Audit Committee ** Member Human Resources Committee *** Nominating & Corporate Governance Committee 2020 ANNUAL REPORT Stockholders’ Meeting Helmerich & Payne shareholders are invited to attend our annual meeting which will be held on March 2, 2021. Stock Transfer Agent and Registrar Computershare Trust Company, N.A. First Class/Registered/Certified Mail PO Box 505000 Louisville, KY 40233-5022 Courier Services 462 South 4th Street Suite 1600 Louisville, KY 40202 Shareholder Services 781.575.2879 800.884.4225 (Toll Free) Independent Registered Public Accounting Firm Ernst & Young LLP Tulsa, Oklahoma Direct Inquiries To David T. Wilson Vice President, Investor Relations Helmerich & Payne, Inc. 1437 South Boulder Avenue Tulsa, Oklahoma 74119 918.742.5531 NYSE : HP helmerichpayne.com 

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