UNITED STATES
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| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
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Title of | Trading symbol(s) | Name of | ||||||
Common Stock ($0.10 par value) | HP | New York Stock Exchange | ||||||
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☒
| Large accelerated filer | ☒ | Accelerated filer | ☐ | Non‑accelerated filer | ☐ | ||||||||||||
| Smaller reporting company |
| Emerging Growth Company | ☐ |
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$4.50 billion based on the closing price of such stock on the New York Stock Exchange on such date of $42.78.
DOCUMENTS INCORPORATED BY REFERENCE
9, 2022: 105,394,298
DISCLOSURE REGARDING FORWARD‑LOOKING STATEMENTS
| HELMERICH & PAYNE, INC. |  | |||||||
| INDEX TO FORM 10‑K | ||||||||
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2022 FORM 10-K|2| Cautionary Note Regarding Forward-Looking Statements | ||||||||||||||
2022 FORM 10-K|3| Risk Factors Summary | ||||||||||||||
2022 FORM 10-K|4HELMERICH & PAYNE, INC.
•the impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic;
2022 FORM YEAR ENDED SEPTEMBER 30, 2017
| Overview | ||||||||||||||
Our contract drilling business is composed of three reportable business segments: U.S. Land,North America Solutions, Offshore Gulf of Mexico and International Land. During fiscal 2017, our U.S. LandSolutions. Our North America Solutions operations drilledare primarily located in Texas, but traditionally also operate in other states, depending on demand. Such states include: Colorado, Louisiana, Ohio, Oklahoma, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, Utah, West Virginia and Wyoming. Additionally, Offshore Gulf of Mexico operations wereare conducted in Louisiana and in U.S. federal waters in the Gulf of Mexico. OurMexico and our International Land segment conducted drillingSolutions operations have rigs and/or services primarily located in four international locations during fiscal 2017:locations: Argentina, Bahrain, Colombia and United Arab Emirates (“UAE”).
Emirates.
2022 FORM 10-K|6| Drilling Fleet | ||||||||||||||
| NORTH AMERICA SOLUTIONS FLEET | ||||||||||||||||||||
| Location | Super-Spec FlexRig®1 | Non Super-Spec FlexRig®2 | Total Fleet | |||||||||||||||||
| Total Available | Rigs Contracted | Total Available | Rigs Contracted | Total Available | Rigs Contracted | |||||||||||||||
| TX | 132 | 96 | 3 | — | 135 | 96 | ||||||||||||||
| NM | 40 | 34 | — | — | 40 | 34 | ||||||||||||||
| OK | 21 | 13 | 1 | — | 22 | 13 | ||||||||||||||
| LA | 11 | 9 | — | — | 11 | 9 | ||||||||||||||
| ND | 11 | 10 | — | — | 11 | 10 | ||||||||||||||
| PA | 5 | 4 | — | — | 5 | 4 | ||||||||||||||
| CO | 1 | 1 | 2 | 2 | 3 | 3 | ||||||||||||||
| WV | 3 | 3 | — | — | 3 | 3 | ||||||||||||||
| UT | 3 | 3 | — | — | 3 | 3 | ||||||||||||||
| OH | 2 | — | — | — | 2 | — | ||||||||||||||
| WY | 1 | 1 | — | — | 1 | 1 | ||||||||||||||
| Totals | 230 | 174 | 6 | 2 | 236 | 176 | ||||||||||||||
2022 FORM 10-K|7| OFFSHORE GULF OF MEXICO FLEET | ||||||||||||||||||||
| Location | Shallow Water1 | Deep Water1 | Total Fleet | |||||||||||||||||
| Total Available | Rigs Contracted | Total Available | Rigs Contracted | Total Available | Rigs Contracted | |||||||||||||||
Louisiana2 | 3 | — | — | — | 3 | — | ||||||||||||||
| Gulf of Mexico | 1 | 1 | 3 | 3 | 4 | 4 | ||||||||||||||
| Totals | 4 | 1 | 3 | 3 | 7 | 4 | ||||||||||||||
| INTERNATIONAL SOLUTIONS FLEET | ||||||||||||||||||||||||||||||||
| Location | AC (FlexRig® 3)1 | AC (FlexRig® 4)2 | Other AC | SCR3 | Total Fleet | |||||||||||||||||||||||||||
| Total Available | Rigs Contracted | Total Available | Rigs Contracted | Total Available | Rigs Contracted | Total Available | Rigs Contracted | Total Available | Rigs Contracted | |||||||||||||||||||||||
| Argentina | 12 | 8 | 4 | — | — | — | 4 | — | 20 | 8 | ||||||||||||||||||||||
| Colombia | 2 | — | — | — | 1 | 1 | 2 | 2 | 5 | 3 | ||||||||||||||||||||||
| Bahrain | — | — | 3 | 1 | — | — | — | — | 3 | 1 | ||||||||||||||||||||||
| Totals | 14 | 8 | 7 | 1 | 1 | 1 | 6 | 2 | 28 | 12 | ||||||||||||||||||||||
| Drilling Services and Solutions | ||||||||||||||
CONTRACT DRILLING
General
We believe that we are one of the majorsuper-spec AC drive land and offshore platform drilling contractorsrigs in the western hemisphere.Western Hemisphere. Operating principally in North and South America, we specialize in shallow to deepshale and unconventional resource plays, drilling challenging and complex wells in oil and gas producing basins ofin the United States and in drilling for oil and gas in international locations. In the United States, we drawhave 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 primarily focused on unconventional shale basins. In South America and the Middle East, our customers primarily from the major oil companies and the larger independent oil companies. In South America, our current customers include major international and national oil companies.
2022 FORM 10-K|8| Year Ended September 30, | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| North America Solutions | Offshore Gulf of Mexico | International Solutions | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | 2022 | 2021 | 2020 | 2022 | 2021 | 2020 | |||||||||||||||||||||||||||||||||||||||||||||
Revenue days1 | 59,672 | 39,199 | 49,003 | 1,460 | 1,552 | 1,922 | 3,036 | 1,815 | 4,605 | ||||||||||||||||||||||||||||||||||||||||||||
Average active rigs2 | 163 | 107 | 134 | 4 | 4 | 5 | 8 | 5 | 13 | ||||||||||||||||||||||||||||||||||||||||||||
Number of active rigs at the end of period3 | 176 | 127 | 69 | 4 | 4 | 5 | 12 | 6 | 5 | ||||||||||||||||||||||||||||||||||||||||||||
| Number of available rigs at the end of period | 236 | 236 | 262 | 7 | 7 | 8 | 28 | 30 | 32 | ||||||||||||||||||||||||||||||||||||||||||||
| Our Segments | ||||||||||||||
2022 FORM 10-K|9estimated losses based on the external actuarial analysis. These premiums are currently held in a restricted cash account, resulting in a transfer of risk from our operating subsidiaries to the Captives. The Company self-insures employee health plan exposures in excess of employee deductibles. Starting in the second quarter of fiscal year 2020, the Captives' insurer issued a stop-loss program that will reimburse the Company's health plan for claims that exceed $50,000. This program is reviewed at the end of each policy year by an outside actuary.
2022 FORM 10-K|10We provide drilling rigs, equipment, personnel and related ancillary services on a contract basis. These services are provided so that our customers may explore for and develop oil and gas from onshore areas and from fixed platforms, tension‑leg platforms and spars in offshore areas. Each of the drilling rigs consists of engines, drawworks, a mast, pumps, blowout preventers, a drill string and related equipment. The intended well depth and the drilling site conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job. A land drilling rig may be moved from location to location without modification to the rig. A platform rig is specifically
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designed to perform drilling operations upon a particular platform. While a platform rig may be moved from its original platform, significant expense is incurred to modify a platform rig for operation on each subsequent platform. In addition to traditional platform rigs, we operate self‑moving platform drilling rigs and drilling rigs to be used on tension‑leg platforms and spars. The self‑moving rig is designed to be moved without the use of expensive derrick barges. The tension‑leg platforms and spars allow drilling operations to be conducted in much deeper water than traditional fixed platforms.
Mechanical rigs rely on belts, pulleys and other mechanical devices to control drilling speed and other rig processes. As such, mechanical rigs are not highly efficient or precise in their operation. In contrast to mechanical rigs, SCR rigs rely on direct current for power. This enables motor speed to be controlled by changing electrical voltage. Compared to mechanical rigs, SCR rigs operate with greater efficiency, more power and better control. AC rigs provide for even greater efficiency and flexibility than what can be achieved with mechanical or SCR rigs. AC rigs use a variable frequency drive that allows motor speed to be manipulated via changes to electrical frequency. The variable frequency drive permits greater control of motor speed for more precision. Among other attributes, AC rigs are electrically more efficient, produce more torque, utilize regenerative braking, have digital controls and AC motors require less maintenance.
During the mid‑late 1990’s, we undertook ana strategic initiative to use our land and offshore platform drilling experience to develop a new generation of drilling rigsrig that would be safer, faster‑movingthe safest, fastest-moving and higherhighest performing than mechanical rigs. In 1998, we put to work a new generation of highly mobile/depth flexiblerig in the land drilling rigs (individuallymarket. Our first FlexRig® drilling rig entered the “FlexRig®”). Since the introduction ofmarket in 1998. We continued to innovate and in 2002 introduced our FlexRigs, we have focused on designing, building, and periodically upgrading, high‑performance, high‑efficiency rigs to be used exclusively in our contract drilling business. We believed that over time FlexRigs would displace older less capable rigs. With the advent of unconventional shale plays, ourfirst AC drive FlexRigs have proven to be particularly well suited for more complex horizontal drilling requirements. The FlexRig has been able to significantly reduce average rig move and drilling times compared to similar depth‑rated traditional land rigs. In addition, the FlexRig allows greater depth flexibility and provides greater operating efficiency. The original rigs, were designated as FlexRig1 and FlexRig2 rigs and were designed to drill wells with a depth of between 8,000 and 18,000 feet. In 2001, we announced that we would build the next generation of FlexRigs, known as “FlexRig3”, which incorporated new drilling technology and improved safety and environmental design. These rigs found immediate success by delivering higher value wells to the customer and marked the beginning of the AC land rig revolution.
In 2006, we placed into service our first FlexRig4. While FlexRig4s are similar to our FlexRig3s, the FlexRig4s are designed to efficiently drill more shallow depth wells of between 4,000 and 18,000 feet. The FlexRig4 design includes a trailerized version and a skidding version, which incorporate additional environmental and safety designs. While the FlexRig4 trailerized version provides for more efficient well site to well site rig moves, the skidding version allows for drilling of upmultiple well pads, 7,500 psi mud systems, set back capacity to 22 wells from a single pad which results in reduced environmental impact.
accommodate the pipe that the longer laterals demanded, and additional mud system capacity.
Industry trends toward more complex drilling these longer lateral wells. The industry would later refer to these rigs as super-spec rigs, which have accelerated the retirement of less capable mechanical rigs. Over time our mechanical rigs have been sold or decommissioned as we added newfollowing 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 our fleet. The decommissionsuper-spec, resulting in what we believe to be the largest fleet of super-spec rigs in the world. As a result of these investments, today the vast majority of our remaining seven mechanical rigs in fiscal 2011 marked the endcurrent domestic fleet is comprised of super spec rigs. As of September 30, 2022, we had a multi‑year evolution in the high‑gradingtotal of 234 super-spec rigs.
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Since 1998, we have built 232 FlexRig3s, 88 FlexRig4s, and 53 FlexRig5s with all 373 of those delivered to the field. Of the total 373 AC drive FlexRigs built through September 30, 2017, 110 have been built in the last five fiscal years.
The effective use of technology is important to the maintenance of our competitive positionOur 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 industry. We expectprogram execution and overall drilling performance. The monitoring group and our performance engineers capture our drilling work steps to continue to focus on new technology solutionshelp provide high quality and applications in the future. Our research and development expense totaled $12.0 million in fiscal 2017, $10.3 million in fiscal 2016, and $16.1 million in fiscal 2015.
reliable results for our customers.
Oklahoma is primarily utilized for modular rig component overhauls and repairs.
2022 FORM 10-K|11Industry / Competitive Conditions
Competition
We compete against many drilling companies, and certain competitorssome of whom are present in more than one of our operating regions. In the United States, we compete with Nabors Industries Ltd., Patterson‑UTIPatterson-UTI Energy, Inc., Precision Drilling Corporation, and many other competitors with regional operations. Internationally, we compete directly with various contractors at each location
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where we operate. In the Gulf of Mexico platform rig market, we primarily compete with Nabors Industries Ltd. and Blake International Rigs, LLC.
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.
demobilization of the rig.
2022 FORM 10-K|12Backlog
Our2021, our drilling contract drilling backlog being the expected future revenue from executed contracts with original terms in excess of one year, as of September 30, 2017 and 2016 was $1.3$1.2 billion and $1.8$0.6 billion, respectively. The decrease in backlog at September 30, 2017 from September 30, 2016, is primarily due to the revenue earned since September 30, 2016. Approximately 41.730.8 percent of the total September 30, 20172022 backlog is not reasonably expected to be filledfulfilled in fiscal 2018. Includedyear 2024 and thereafter. See Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations — Contract Backlog" included in backlog is early termination revenue expectedthis Form 10-K for additional information pertaining to be recognized after the periods presented in which early termination notice was received prior to the end of the period.
The following table sets forth the total backlog by reportable segment asbacklog.
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Reportable Segment |
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| Expected to be Filled in Fiscal 2018 |
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U.S. Land |
| $ | 0.9 |
| $ | 1.2 |
| 36.4 | % |
Offshore |
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| 0.1 |
| — | % |
International |
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| 0.4 |
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| 0.5 |
| 58.0 | % |
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| $ | 1.3 |
| $ | 1.8 |
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As noted above, under certain limited circumstances a customer is not required to pay an early termination fee. There may also be instances where a customer is financially unable or refuses to pay an early termination fee. Accordingly, the actual amount of revenue earned may vary from the backlog reported. For further information, see Item 1A—“Risk Factors.”
U.S. Land Drilling
At the end of September 2017, 2016, and 2015,2022, we had 350, 348 and 343, respectively, of our land rigs available for work in the United States. The total number of rigs at the end of fiscal 2017 increased by a net of two rigs from the end of fiscal 2016. The net increase is due to two new FlexRigs completed in 2017. Our U.S. Land operations contributed approximately 80 percent ($1.4 billion) of our consolidated operating revenues during fiscal 2017, compared with approximately 77 percent ($1.2 billion) of consolidated operating revenues during fiscal 2016 and approximately 80 percent ($2.5 billion) of consolidated operating revenues during fiscal 2015. Rig utilization was approximately 45 percent in fiscal 2017, approximately 30 percent in fiscal 2016 and approximately 62 percent in fiscal 2015. A rig is considered to be utilized when it is operated (or otherwise deployed for a customer) or being moved, assembled or dismantled under contract. At the close of fiscal 2017, 197 out of an available 350 land rigs were generating revenue.
Offshore Drilling
Our Offshore operations contributed approximately 8 percent in fiscal year 2017 ($136.3 million) of our consolidated operating revenues compared to approximately 9 percent ($138.6 million) of consolidated operating revenues during fiscal 2016 and 8 percent ($241.7 million) of consolidated operating revenues during fiscal 2015. Rig utilization in fiscal 2017 was approximately 74 percent compared to approximately 82 percent in fiscal 2016 and 93 percent in fiscal 2015. At the end of fiscal 2017, we had five of our eight offshore platform rigs under contract compared to seven of an available nine at the end of fiscal 2016. We continued to work under management contracts for two customer‑owned rigs at the close of fiscal 2017. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 60 percent ($81.1 million) of offshore revenues during fiscal 2017.
International Land Drilling
General
At the end of September 2017, 2016 and 2015, we had 38 land rigs available for work in locations outside of the United States. Our International Land operations contributed approximately 12 percent ($213.0 million) of our consolidated operating revenues during fiscal 2017, compared with approximately 14 percent ($229.9 million) of consolidated operating revenues during fiscal 2016 and 12 percent ($382.3 million) of consolidated operating revenues during fiscal 2015. Rig utilization was 36 percent in fiscal 2017, 39 percent in fiscal 2016 and 51 percent in fiscal 2015. Our international operations are subject to various political, economic and other uncertainties not typically encountered in U.S. operations. For further information on various risks associated with doing business in foreign countries, see Item 1A—“Risk Factors.”
Argentina
At the end of fiscal 2017, we had 19 rigs in Argentina. Our utilization rate was approximately 55 percent during fiscal 2017, approximately 54 percent during fiscal 2016 and approximately 57 percent during fiscal 2015. Revenues generated by Argentine drilling operations contributed approximately 9 percent in fiscal 2017 ($157.3 million) of our consolidated operating revenues compared to approximately 10 percent ($159.4 million) of our consolidated operating revenues during fiscal 2016 and approximately 6 percent ($178.0 million) of our consolidated operating revenues during fiscal 2015. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 8 percent of consolidated operating revenues and approximately 70 percent of international operating revenues during fiscal 2017. The Argentine drilling contracts are primarily with large international or national oil companies.
Colombia
At the end of fiscal 2017, we had eight rigs in Colombia. Our utilization rate was approximately 25 percent during fiscal 2017, approximately 13 percent during fiscal 2016 and approximately 48 percent during fiscal 2015. Revenues generated by Colombian drilling operations contributed approximately 2 percent in fiscal 2017 ($37.6 million)
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of our consolidated operating revenues compared to approximately 1 percent ($20.5 million) of our consolidated operating revenues during fiscal 2016 and approximately 2 percent ($70.1 million) of our consolidated operating revenues during fiscal 2015. Revenues from drilling services performed for our two customers in Colombia totaled approximately 2 percent of consolidated operating revenues and approximately 18 percent of international operating revenues during fiscal 2017. The Colombian drilling contracts are primarily with large international or national oil companies.
Ecuador
At the end of fiscal 2017, we had six rigs in Ecuador. At the end of fiscal 2017 and 2016, all of our rigs in Ecuador were idle. The utilization rate in Ecuador was 4 percent in fiscal 2016 and 29 percent in fiscal 2015. Revenues generated by Ecuadorian drilling operations were insignificant during fiscal 2017 compared to contributing less than 1 percent during fiscal 2016 ($4.9 million) of our consolidated operating revenues and 1 percent in fiscal 2015 ($31.0 million) of our consolidated operating revenues.
UAE—Abu Dhabi
At the end of fiscal 2017, we had two rigs in the UAE. The utilization rate in the UAE was 8 percent in fiscal 2017, compared to 100 percent in fiscal 2016 and in fiscal 2015. Revenues generated by drilling operations in the UAE contributed less than 1 percent ($8.2 million) during fiscal 2017 of our consolidated operating revenues compared to approximately 2 percent during fiscal 2016 and fiscal 2015 ($34.6 million and $47.7 million, respectively) of our consolidated operating revenues. The UAE drilling contracts are with a single national oil company that contributed approximately 4 percent of international operating revenues during fiscal 2017.
Bahrain
At the end of fiscal 2017, we had three rigs in Bahrain. The utilization rate in Bahrain was 33 percent in fiscal 2017 and fiscal 2016, compared to 56 percent in fiscal 2015. Revenues generated by drilling operations in Bahrain contributed 1 percent during fiscal 2017, fiscal 2016 and fiscal 2015 ($10.0 million, $10.2 million and $41.9 million, respectively) of our consolidated operating revenues. Bahrain drilling contracts are with a single national oil company that contributed approximately 5 percent of international operating revenues during fiscal 2017.
FINANCIAL
For information relating to revenues, total assets and operating income by reportable operating segments, see Note 15—“Segment Information” included in Item 8—“Financial Statements and Supplementary Data” of this Form 10‑K.
EMPLOYEES
We had 7,2707,000 employees within the United States (5 of which were part‑time employees) and 853approximately 1,000 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.
2022 FORM 10-K|13AVAILABLE INFORMATION
New Employment Introduction basics and is intended to provide the technical on-the-job training guided by a mentor.
2022 FORM 10-K|142022 FORM 10-K|152022 FORM 10-K|162022 FORM 10-K|176
| BUSINESS AND OPERATING RISKS | ||||||||||||||
| Our business depends on the level of activity in the oil and natural gas industry, which is significantly impacted by the current and expected price of oil and natural gas as well as the volatility in those prices and other factors. | ||||||||||||||
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 dependsand the rates we are able to charge for such services depend on oil and natural gas industry exploration and production activity and expenditure levels, which are directly affected by trends in oil and natural gas prices and market expectations regarding such prices.
Oil prices declined significantly during the second half of 2014. Volatility and the overall The sharp decline in prices continued through 2015 and into early 2016. For example, in July of 2014 oil prices exceeded $100 per barrel. Oil prices dropped below $30 per barrel in early 2016. In fiscal 2016 oil prices rebounded but nevertheless remained volatile and continued to fluctuate in fiscal 2017 above and below $50 per barrel. The precipitous drop in oil prices resulting from the COVID-19 pandemic and volatility over the last three years significantly affected the capital spending budgetsactivities of our customers, particularly in 2015 and 2016. As such, demand for our drilling services significantly declined from late 2014 through the first half of fiscal 2016. At December 31, 2014, 294 out of an available 337 land rigs were working in the U.S. Land segment. In contrast, at June 30, 2016, 89 out of an available 348 land rigs were contracted in the U.S. Land segment. Due to the modest rebound in oil prices we have experienced an increase in the demand for our drilling services since May of 2016. Nevertheless, our active rig count has remained below the height of drilling activity experienced in 2014 when oil prices were significantly higher. As of November 16, 2017, 200 rigs were contracted in the U.S. Land segment. In the event oil prices remain depressed forOPEC+ caused a sustained period, orsignificant decline again, our U.S. Land, International Land and Offshore segments may again experience significant declines in both drilling activity and spot dayrate pricing which couldprices for our services in fiscal year 2020. While crude oil prices have stabilized and increased and our rig count has continued to recover, our rig activity has still not reached the level it was at prior to these events and these events therefore continue to have a material adverse effect on our business, financial condition and results of operations.
Oil prices are particularly sensitive to actual and perceived threats to geopolitical stability and to changes in production from OPEC+ member states. For example, the ongoing conflict, and the continuation of, or any increase in the severity of, the conflict between Russia and Ukraine, has led and may continue to lead to an increase in the volatility of global oil and gas prices, which could have a corresponding negative impact on the capital expenditure of oil and gas companies as a result of the higher perceived risk.
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2022 FORM 10-K|18•increased focus by the investment community on sustainability practices in the oil and natural gas industry;
| Global economic conditions and volatility in oil and gas prices may adversely affect our business. | ||||||||||||||
| 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. | ||||||||||||||
2022 FORM 10-K|19| 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. | ||||||||||||||
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. | ||||||||||||||
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.
2022 FORM 10-K|20We havealso lease a fabrication facility located near the Houston, Texas ship channel, where we upgrade and repair rigs and perform fabrication work, and our principal fabricator and other vendors are also located in the gulf coast region. Due to their location, these facilities areregion and could be exposed to potentially greater hurricane damage.
Wedamage or disruption by hurricanes and other extreme weather conditions, including coastal flooding, which in turn could result in increased operating costs or decreases in revenues and adversely affect our business, financial condition and results of operations.
With the exception of “named wind storm” risk in the Gulf of Mexico, we
We In addition, we have insurance coverage for comprehensive general liability, automobile liability, worker’sworkers’ 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 worker’sworkers’ compensation, general liability and automobile liability programs. The Company self‑insures a number of other risks, including loss of earnings and business interruption, and most cyber risks.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.
| Our business is subject to cybersecurity risks. | ||||||||||||||
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2022 FORM 10-K|21for any loss in excess of these limits. No assurance can be given that allCybersecurity incidents involving our own systems or a portionthose of our coverage will not be cancelled during fiscal 2018, that insurance coverage will continuethird-party vendors, could:
Global economic conditions may adversely affect our business.
Global economic conditions and volatility in oil and natural gas prices may impact the ability or desire of our customers to maintain or increase spending on exploration and development drilling and whether customers and/or vendors and suppliers will be able to access financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations. In the event the strength of the global economic environment fails to gain momentum or deteriorates in 2018, industry fundamentals may be impacted and result in stagnant or reduced demand for drilling rigs. Furthermore, these factors may result in certain of our customers experiencing bankruptcy or otherwise becoming unable to pay vendors, including us. The global economic environment in the past has experienced significant deterioration in a relatively shortprolonged period of timetime. While various procedures and controls are being utilized to mitigate exposure to such risk, there can be no assurance that the global economic environmentprocedures and controls that we implement, or which we cause third party service providers to implement, will not quickly deteriorate again duebe sufficient to oneprotect our systems, information or more factors. These conditionsother property. Additionally, customers as well as other third parties upon whom we rely on face similar cybersecurity 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.
The contract drilling business is highly competitive 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. | ||||||||||||||
Competition in contract drilling involves such factors asother uses; or
Although many contracts for drilling services are awarded based solely on price, we have been successful in establishing long‑term relationships with certain customers which have allowed us to secure drilling work even though we may not have been the lowest bidder for such work. We have continued to attempt to differentiate our services based upon our FlexRigs and our engineering design expertise, operational efficiency, safety and environmental awareness. However, development of new drilling technology by competitors has increased in recent years and future improvements in operational efficiency and safety by our competitors could further negatively affect our ability to differentiate our services. Also, the strategy of differentiation is less effective during low commodity price environments when lower demand for drilling services intensifies price competition and makes it more difficult or impossible to compete on any basis other than price.
The oil and natural gas services industry in the United States has experienced downturns in demand during the last decade, including a significant downturn that started in 2014 and bottomed out in 2016. Today, as was the case following past downturns, there are substantially more drilling rigs available than necessary to meet the modest rebound in demand observed in 2016 and 2017. As a result of the current excess of available and more competitive drilling rigs, we may continue to experience difficulty in replacing fixed‑term contracts, extending expiring contracts or obtaining new contracts in the spot market, and the day rates (and other material terms) under new contracts may be on substantially less favorable rates and terms. As such, we may have difficulty sustaining or increasing rig utilization and profit margins in the future, we may lose market share and price may be a primary factor in the award of contracts for drilling services.
The loss of one or a number of our large customers could have a material adverse effect on our business financial condition andclimate or our results of operations.
In fiscal 2017,operations such that we received approximately 55 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 25 percent of our consolidated operating revenues from our three largest customers (including their affiliates). We believedetermine that our relationship with all of these customers is good; however, the loss of onegoodwill or more of our larger customers could have a material adverse effect on our business, financial condition and results of operations.
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New technologies may cause our drilling methods and equipment to become less competitive, higher levels of capital expenditures may be necessary to keep pace with the bifurcation of the drilling industry, and growth through the building of new drilling rigs and improvement of existing rigs is not assured.
The market for our services is characterized by continual technological developments that have resulted in, and will likely continue to result in, substantial improvements in the functionality and performance of rigs and equipment. Our customers increasingly demand the services of newer, higher specification drilling rigs. This results in a bifurcation of the drilling fleet and is evidenced by the higher specification drilling rigs (e.g., AC rigs) generally operating at higher overall utilization levels and day rates than the lower specification drilling rigs (e.g., mechanical or SCR rigs). In addition, a significant number of lower specification rigsintangible assets are being stacked and/or removed from service. As a result of this bifurcation, a higher level of capital expendituresimpaired, we will be required to maintain and improve existing rigs and equipment and purchase and construct newer, higher specification drilling rigsrecord impairment charges with respect to meet the increasingly sophisticated needssuch assets.
2022 FORM 10-K|22
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If we are not successful in upgrading existing rigs and equipment or building new rigs in a timely and cost‑effective manner suitable to customer needs, we could lose market share. One or more technologies that we may implement in the future may not work as we expect and we may be adversely affected. Additionally, new technologies, services or standards could render some of our services, drilling rigs or equipment obsolete, which could have a material adverse impact on our business, financial condition and results of operation.
Technology disputes could negatively impact our operations or increase our costs.
Drilling rigs use proprietary technology and equipment which can involve potential infringement of a third party’s rights, 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 thatFrom time to time, we or one of our customers or supplying vendors becomesbecome involved in a disputedisputes over infringement of intellectual property rights relating to equipment or technology owned or used by us,us. As a result, we may lose access to important equipment or we couldtechnology, be required to cease use of some equipment or technology, be forced to modify our drilling rigs. We could alsorigs or technology, or be required to pay license fees or royalties for the use of equipment. Technologyequipment or technology. In addition, we may lose a competitive advantage in the event we are unsuccessful in enforcing our rights against third parties, or third parties are successful in enforcing their rights against us. 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 operation.
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| Unexpected events could disrupt our business and adversely affect our results of operations. | ||||||||||||||
New legislationwhich may increase in frequency and regulatory initiatives relating to hydraulic fracturingseverity as a result of climate change), war or terrorist activities, supply disruptions, failure of equipment, changes in laws and/or regulations impacting our businesses, pandemic illness and other aspects of the oil and gas industryunforeseeable circumstances that may arise from our increasingly connected world or otherwise, could negatively impact the drilling programs ofadversely affect our customers and, consequently, delay, limit or reduce the drilling services we provide.
business. It is a common practice innot possible for us to predict the occurrence or consequence of any such events. However, any such events could create unforeseen liabilities, reduce our industryability to provide drilling and related technology services, reduce demand for our customersservices, or make it more difficult or costly to recover natural gas and oil from shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations using water, sand and other additives pumped under high pressure into the formation. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure, waste disposal and/or well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Members of the U.S. Congress and a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing and the possibility of more stringent regulation. Further, we conduct drilling activities in numerous states, including Oklahoma. In recent years, Oklahoma has experienced an increase in earthquakes. Some parties believe that there is a correlation between hydraulic fracturing related activities and the increased occurrence of seismic activity. The extent of this correlation, ifprovide services, any is the subject of studies of both state and federal agencies the results of which remain uncertain. Depending on the outcome of these or other studies pertaining to the impact of hydraulic fracturing, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing activities. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques, operational delays or increased operating and compliance costs in the production of oil and natural gas from shale plays, added difficulty in performing hydraulic fracturing, and potentially a decline in the completion of new oil and gas wells.
We do not engage in any hydraulic fracturing activities. However, any new laws, regulations or permitting requirements regarding hydraulic fracturing could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the drilling services we provide. Widespread regulation significantly restricting or prohibiting hydraulic fracturing by our customers couldultimately have a material adverse impacteffect on our business, financial condition and results of operation.
operations.
| Reliance on management and competition for experienced personnel may negatively impact our operations or financial results. | ||||||||||||||
We evaluatekey employees to manage our drilling rigsoperations. Similarly, we utilize highly skilled personnel in operating and other assets whenever events or changessupporting our businesses and in circumstances indicate thatdeveloping new technologies. In times of high utilization, it can be difficult to find and retain qualified individuals and, during the carrying amountrecent period of an asset may not be recoverable. An impairment loss may exist when the estimated future cash flows are less than the carrying amount of the asset. Lower utilizationsustained declines in oil and day rates adversely affect our revenues and profitability. Prolonged periods of low utilization and day rates may resultnatural gas prices, there have been reductions in the recognitionoil field services workforce, both of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigswhich have resulted and may not be recoverable. For example, in fiscal 2015, we performed an impairment evaluation of all our long‑lived drilling assets. Our evaluation resulted in $39.2 million of impairment charges to reduce the carrying value of seven SCR land rigs within our International Land segment to their estimated fair value. Similarly, during the third quarter of fiscal 2016 we recorded a $6.3 million impairment charge to reduce the carrying value of certain rig and rig related equipment classified as held for sale in our U.S. Land segment to their estimated fair values. Although we are actively marketing idle drilling rigs in our fleet, there can be no assurance that we will be able to obtain future contracts for all of our rigs. As of September 30, 2017, we assessed our idle drilling rigs and determined no additional impairment charges were necessary. However, drilling rigs in our fleet may become impaired in the future if market conditions deteriorate or if oilresult in higher labor costs. We may also face a loss of workers and gas prices decline further or remain low for a prolonged period.
Department of Interior investigation could adversely affect our business.
On November 8, 2013, the United States District Court for the Eastern District of Louisiana approved the previously disclosed October 30, 2013 plea agreement between our wholly owned subsidiary, Helmerich & Payne International Drilling Co. (“H&PIDC”), and the United States Department of Justice, United States Attorney’s Office for the Eastern District of Louisiana (“DOJ”). The court’s approval of the plea agreement resolved the DOJ’s investigation into certain choke manifold testing irregularities that occurred in 2010 at one of H&PIDC’s offshore platform rigs in the Gulf of Mexico. We also engaged in discussions with the Inspector General’s office of the Department of Interior
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(“DOI”) regarding the same events that were the subject of the DOJ’s investigation. Although we do not presently anticipate any further action by the DOI in this matter, we can provide no assuranceslabor shortages as to the timing or eventual outcome of the DOI’s consideration of the matter. Refer also to Item 3—“Legal Proceedings” and Note 14—“Commitments and Contingencies” included in Item 8—“Financial Statements and Supplementary Data” of this Form 10‑K for discussion of this subject.
Our business and results of operations may be adversely affected by foreign political, economic and social instability risks, foreign currency restrictions and devaluation, and various local laws associated with doing business in certain foreign countries.
We currently have drilling operations in South America and the Middle East. In the future, we may further expand the geographic reach of our operations. As a result of requirements and enforcement of other COVID-19 regulations in jurisdictions where we are exposed to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of social unrest, strikes, terrorism, war, kidnapping of employees, nationalization, forced negotiation or modification of contracts, difficulty resolving disputes and enforcing contract provisions, expropriation of equipment as well as expropriation of oil and gas exploration and drilling rights, taxation policies, foreign exchange restrictions and restrictions on repatriation of income and capital, currency rate fluctuations, increased governmental ownership and regulation of the economy and industry in the markets in which we operate, economic and financial instability of national oil companies, and restrictive governmental regulation, bureaucratic delays and general hazards associated with foreign sovereignty over certain areas in which operations are conducted.
South American countries, in particular, have historically experienced uneven periods of economic growth, as well as recession, periods of high inflation and general economic and political instability. From time to time these risks have impacted our business. For example, on June 30, 2010, the Venezuelan government expropriated 11 rigs and associated real and personal property owned by our Venezuelan subsidiary. Prior thereto, we also experienced currency devaluation losses in Venezuela and difficulty repatriating U.S. dollars to the United States. Today, our contracts for work in foreign countries generally provide for payment in U.S. dollars. However, in Argentina we are paid in Argentine pesos.operate. The Argentine branch of one of our second-tier subsidiaries then remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars.
Estimates from published sources indicate that Argentina is a highly inflationary country, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period based on inflation data published by the respective governments. Regardless, all of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations.
In December 2015, the Argentine peso experienced a sharp devaluation resulting in a foreign currency loss of $8.4 million for fiscal 2016. Subsequent tomembers of management or the sharp devaluation, the Argentine peso significantly stabilized and the Argentine Foreign Exchange Market controls now place fewer restrictions on repatriating U.S. dollars. For fiscal 2017, we experienced a foreign currency loss of $4.0 million in Argentina. Our aggregate foreign currency losses for fiscal 2016 and 2017 were $9.3 million and $7.1 million, respectively. In the future, other contracts or applicable law may require payments to be made in foreign currencies. As such, there can be no assurance that we will not experience in Argentina or elsewhere a devaluation of foreign currency, foreign exchange restrictions or other difficulties repatriating U.S. dollars even if we are able to negotiate contract provisions designed to mitigate such risks. In the event of future payments in foreign currencies and an inability to timely exchange foreign currencies for U.S. dollars, we may incur currency devaluation losses whichattract and retain qualified personnel could have a material adverse impacteffect 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 In addition, the unexpected loss of members of management, qualified personnel or a significant number of employees due to disease, 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. | ||||||||||||||
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will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable.
Although we attempt to minimize the potential impact of such risks by operating in more than one geographical area, during fiscal 2017, approximately 12 percent of our consolidated operating revenues were generated from the international contract drilling business. During fiscal 2017, approximately 92 percent of the international operating revenues were from operations in South America. Substantially all of the South American operating revenues were from Argentina and Colombia. The future occurrence of one or more international events arising from the types of risks described above could have a material adverse impact on our business, financial condition and results of operation.
Drilling contracts with nationaloperations. Further, consolidation among oil and natural gas exploration and production companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.
We currently own and operate rigs that are contracted with foreign national oil companies. In the future we may expand our international operations and enter into additional, significant contracts with national oil companies. The terms of these contracts may contain non-negotiable provisions and may expose us to greater commercial, political, operational and other risks than we assume in other contracts. Foreign contracts may expose us to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, or under certain conditions that may not provide us with an early termination payment. We can provide no assurance that increased risk exposure will not have an adverse impact on our future operations or that we will not increasereduce the number of rigs contracted to national oil companies with commensurate additional contractual risks. Risks that accompany contracts with national oil companies could ultimately have a material adverse impact on our business, financial condition and results of operation
Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti‑bribery legislation could adversely affect our business.
The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti‑bribery laws in other jurisdictions, including the United Kingdom Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti‑bribery laws may conflict with local customs and practices and impact our business. Although we have programs in place covering compliance with anti‑bribery legislation, any failure to comply with the FCPA or other anti‑bribery legislation could subject us to civil and criminal penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operation. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs or other assets.
Failure to comply with governmental and environmental laws could adversely affect our business.
Many aspects of our operations are subject to government regulation, including those relating to drilling practices, pollution, disposal of hazardous substances and oil field waste. The United States and various other countries have environmental regulations which affect drilling operations. The cost of compliance with these laws could be substantial. A failure to comply with these laws and regulations could expose us to substantial civil and criminal penalties. In addition, environmental laws and regulations in the United States impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of drilling rigs, we may be deemed to be a responsible party under these laws and regulations.
We believe that we are in substantial compliance with all legislation and regulations affecting our operations in the drilling of oil and gas wells and in controlling the discharge of wastes. To date, compliance costs have not materially affected our capital expenditures, earnings, or competitive position, although compliance measures may add to the costs of drilling operations. Additional legislation or regulation may reasonably be anticipated, and the effect thereof on our operations cannot be predicted.
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| Our current backlog of drilling services and solutions revenue may decline and may not be ultimately realized as fixed‑term contracts and may, in certain instances, be terminated without an early termination payment. | ||||||||||||||
Our current backlog of contract drilling revenue may continue to decline and may not be ultimately realized as fixed‑term contracts may in certain instances be terminated without an early termination payment.
Fixed‑term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. Even if an early termination payment is owed to us, a customer may be unable or may refuse to pay the early termination payment. We also may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, such as depressed market conditions. As of September 30, 2017,2022, our contract drilling services backlog was approximately $1.3$1.2 billion for future revenues under firm commitments. Our contract drilling services backlog may continue to 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.
2022 FORM 10-K|23| Our contracts with national oil companies may expose us to greater risks than we normally assume in contracts with non-governmental customers. | ||||||||||||||
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 securities portfoliooperations.
| Shortages of drilling equipment, supplies or other key materials could adversely affect our operations. | ||||||||||||||
At September 30, 2017, we had a portfolio of securities with a total fair value of approximately $70.1 million, consisting of Atwood Oceanics, Inc. (“Atwood”) and Schlumberger, Ltd. The total fair value of the portfolio of securities was $71.5 million at September 30, 2016. In May of 2017, Ensco plc (“Ensco”) announced that it entered into a definitive merger agreement under which Ensco would acquire Atwood in an all-stock transaction. The transaction closed on October 6, 2017. Under the terms of the merger agreement, we received 1.60 shares of Ensco for each share of our Atwood common stock. The securities in our portfolio are subject to a wide variety of market‑related risks that could substantially reducecontractual obligations or increase the fair value of the holdings. In general, the portfolio is recorded at fair value on the balance sheet with changes in unrealized after‑tax value reflectedmarket constraints in the equity sectiondrilling services and solutions business. Further, certain key rig components, parts and equipment are also either purchased from, fabricated or serviced by a limited number of vendors, which, in some cases, may be thinly capitalized and disproportionately affected by any loss of business, downturn in the balance sheet. However, whereenergy industry, supply chain disruptions, or reduction or availability of credit. A number of disruptions and delays across the global supply chain have occurred in recent years, which have created delays in servicing key components, and a declinetightening of supplies and shortages in fair value below our cost basis is considereda number of areas, ranging from basic raw materials to be other than temporary, the change in value is recorded as a charge through earnings. During the fourth quarter of fiscal 2016, we determined that a loss was other‑than‑temporarysemiconductors, and increasing costs, and we recognized a $26.0 million impairment charge. Noexpect such impairment charge was recognized in fiscal 2017. At November 16, 2017, the fair value of the portfolio had decreased to approximately $63.2 million.
We may reduce or suspend our dividenddisruptions and delays could continue in the future.
Wenear term and possibly beyond. To date, as an industry leader, we have paid a quarterly dividend for many years. Our most recent, quarterly dividend was $0.70 per share. Ineffectively managed these delays, disruptions, and shortages by engaging in near and long-term demand planning with multiple vendors who provide and service key rig components, parts and equipment. However, if we are not able to effectively manage these disruptions and delays in the future, our Board of Directors may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position the Company for long‑term success. The declaration and amount of future dividends is at the discretion of our Board of Directors and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board of Directors deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. There can be no assurance that we will continue to pay a dividend in the future.
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Legal proceedings could have a negative impact on our business.
The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. In addition, during periods of depressed market conditions we may be subject to an increased risk of our customers, vendors, former employees and others initiating legal proceedings against us. Lawsuits or claims against usthey could have a material adverse effect on our business, financial condition and results of operations. Any litigation
| Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility. | ||||||||||||||
2022 FORM 10-K|24| The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, could have a material adverse effect on our business, financial condition and results of operations. | ||||||||||||||
We depend on a limited number of vendors, some of which are thinly capitalizednatural gas and the level of demand for our services. Other effects of the pandemic include and may continue to include, significant volatility and disruption of the global financial markets; continued volatility of crude oil prices and related uncertainties around OPEC+ production; disruption of our operations, including suspension of drilling activities; impact to costs; loss of anyworkers; labor shortages; supply chain disruptions 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 which could disrupt our operations.
Certain key rig components, partssecurities and equipment are either purchased from or fabricated by a single or limited number of vendors, and we have no long‑term contractstrading markets 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,respect thereto; our ability to maintain, improve, upgradeaccess capital markets; asset impairments and other accounting changes; certain of our customers experiencing bankruptcy or construct drilling rigs couldotherwise becoming unable to pay vendors, including us; and employee impacts from illness, travel restrictions, including border closures and other community response measures. Such public health crises, pandemics and epidemics are continuously evolving and the extent to which our business operations and financial results continue to be impaired, whichaffected depends on various factors beyond our control, such as the duration, severity and sustained geographic resurgence of the COVID-19 virus; the emergence, severity and spread of new variants of the virus; the impact and effectiveness of governmental actions to contain and treat such outbreaks, including government policies and restrictions; vaccine hesitancy, vaccine mandates, and voluntary or mandatory quarantines; and the global response surrounding such uncertainties.
| Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our 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 are subject toenforcing 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 taxesand capital, currency rate fluctuations, increased governmental ownership and regulation of the economy and industry in the United Statesmarkets in which we operate, economic and numerous other jurisdictions. Significant judgmentfinancial 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.
2022 FORM 10-K|25| FINANCIAL RISKS | ||||||||||||||
| Covenants in our debt agreements restrict our ability to engage in certain activities. | ||||||||||||||
| We may be required to record impairment charges with respect to our drilling rigs and other assets. | ||||||||||||||
A downgradean asset group may not be recoverable. Drilling rigs in our credit ratingfleet may become impaired in the future if oil and gas prices decline or remain low for a prolonged period of time or if market conditions deteriorate or if we restructure our drilling fleet. For example, in fiscal years 2022 and 2021, we recognized impairment charges of $4.4 million and $70.9 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.
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 could be limited.
| Our ability to access capital markets could be limited. | ||||||||||||||
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| Our marketable securities may lose significant value due to credit, market and interest rate risks. | ||||||||||||||
2022 FORM 10-K|26We 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.
| 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. | ||||||||||||||
Regulation
| The replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt. | ||||||||||||||
| 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. | ||||||||||||||
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. worldwide and there are a number of political and technological initiatives aimed at reducing the use of hydrocarbons.
2022 FORM 10-K|272022 FORM 10-K|28| 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. | ||||||||||||||
| Our aspirations, goals and initiatives related to sustainability and emissions reduction, and our public statements and disclosures regarding them, expose us to numerous risks. | ||
2022 FORM 10-K|29| Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti‑bribery legislation could adversely affect our business. | ||||||||||||||
| Our business is subject to complex and evolving laws and regulations regarding privacy and data protection. | ||||||||||||||
2022 FORM 10-K|30| 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. | ||||||||||||||
Reliance 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.
| Legal claims and litigation could have a negative impact on our business. | ||||||||||||||
We greatly depend onincrease our costs
Shortages 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.
2022 FORM 10-K|31| Additional tax liabilities, limitations on our use of net operating losses and tax credits and/or our significant net deferred tax liability could affect our financial condition, income tax provision, net income, and cash flows. | ||||||||||||||
The contract drillingfinancial position, income tax provision, net income, or cash flows in the period or periods challenged. Tax rates in the various jurisdictions in which our subsidiaries are organized and conduct their operations may change significantly as a result of political or economic factors beyond our control. It is also possible that future changes to tax laws (including tax treaties in any of the jurisdictions that we operate in) could impact our ability to realize the tax savings recorded to date. Our ability to benefit from our deferred tax assets depends on us having sufficient future taxable income to utilize our net operating loss and tax credit carryforwards before they expire. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of net operating losses and other pre-change tax attributes (such as tax credits) that may be used to offset taxable income by a corporation that has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more shareholders (or groups of shareholders) that are each deemed to own at least 5 percent of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage during a rolling three-year period. As of September 30, 2022, we have not experienced an ownership change and, therefore, utilization of our applicable tax attributes were not subject to an annual limitation (except for an immaterial portion thereof that we inherited in connection with an acquisition during 2017). However, if we were to experience ownership changes in the future as a result of subsequent shifts in our stock ownership, our ability to use certain pre-change tax attributes could potentially accelerate or permanently increase our future tax liabilities. Additionally, our future effective tax rates could be adversely affected by changes in tax laws (including tax treaties) or their interpretation, such as the proposals by the Biden administration to increase the U.S. corporate income tax rate and increase the U.S. taxation of international business operations. For example, the IRA, passed on August 16, 2022, includes a new 15 percent corporate minimum tax as well as a one percent excise tax on corporate stock repurchases applicable to repurchases after December 31, 2022. We are in the process of evaluating the potential impacts of the IRA. While we do not currently expect the IRA to have a material impact on our effective tax rate, our analysis is highly cyclical. During periods of increased demand for contract drilling services, delays in deliveryongoing and shortages of drilling equipmentincomplete, and supplies can occur. These risks are intensified during periods whenit is possible that the industry experiences significant new drilling rig construction or refurbishment. Any such delays or shortagesIRA could have a material adverse effect on our business, financial conditiontax liability.
Our business isoperations 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 cybersecurity risks.
Threatschange.
| Failure to comply with or changes to governmental and environmental laws could adversely affect our business. | ||||||||||||||
16
compromised, which might not be noticed for some period of time. Although we utilize various procedures and controls to mitigate our exposure to, such risk, cybersecurity attacks are evolvingsolid and unpredictable. The occurrence of such an attack could lead to financial losseshazardous 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.
2022 FORM 10-K|32| RISKS RELATED TO OUR COMMON STOCK AND CORPORATE STRUCTURE | ||||||||||||||
| We may reduce or suspend our dividend in the future. | ||||||||||||||
Unexpected events could disrupt our business and adversely affect our results of operations.
Unexpected and entirely unanticipated events, including, without limitation, computer system disruptions, unplanned power outages, fires or explosionsfuture dividends is at drilling rigs, natural disasters such as hurricanes and tornadoes, war or terrorist activities, supply disruptions, failure of equipment, changes in laws and/or regulations impacting our businesses, pandemic illness and other unforeseeable circumstances that may arise from our increasingly connected world or otherwise could adversely affect our business. It is not possible for us to predict the occurrence or consequence of any such events. However, any such events could reduce our ability to provide drilling services, reduce demand for our services, or make it more difficult or costly to provide services which ultimately may have a material adverse effect on our business, financial condition and results of operations.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Efforts may be made from time to time to unionize portionsdiscretion of our workforce. In addition, we may in the future be subject to strikes or work stoppagesBoard of Directors and other labor disruptions. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.
Any future implementation of price controls on oil and natural gas would affect our operations.
The United States Congress may in the future impose some form of price controls on either oil, natural gas, or both. Any future limits on the price of oil or natural gas could negatively affect the demand for our services and, consequently, have a material adverse effect on our business, financial condition and results of operations.
Covenants in our debt agreements restrict our ability to engage in certain activities.
Our debt agreements pertaining to certain long‑term unsecured debt and our unsecured revolving credit facility contain various covenants that may in certain instances restrict our ability to, among other things, incur, assume or guarantee additional indebtedness, incur liens, sell or otherwise dispose of assets, enter into new lines of business, and merge or consolidate. In addition, our credit facility requires us to maintain a funded leverage ratio (as defined) of less than 50 percent and certain priority debt (as defined) may not exceed 17.5% of our net worth (as defined). Such restrictions may limit our ability to successfully execute our business plans, which may have adverse consequences on our operations.
Improvements in or new discoveries of alternative energy technologies could have a material adverse effectwill depend on our financial condition, and results of operations.
Sinceoperations, 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 recent downturn as a result of the COVID-19 pandemic 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. | ||||||||||||||
2022 FORM 10-K|33| Certain provisions of our corporate governing documents could make an acquisition of our company more difficult. | ||||||||||||||
| Public and investor sentiment towards climate change, fossil fuels and other ESG matters could adversely affect our cost of capital and the price of our common stock. | ||||||||||||||
17
CONTRACT DRILLING
The following table sets forth certain information concerning our U.S. land
| ITEM 2. PROPERTIES | ||||||||||||||
2022 FORM 10-K|34
|
|
|
|
|
|
|
|
|
|
|
|
| Optimum |
|
|
| Drawworks: |
Location |
| Rig |
| Depth (Feet)* |
| Rig Type |
| Horsepower |
FlexRigs |
|
|
|
|
|
|
|
|
Texas |
| 212 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 214 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Utah |
| 215 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 216 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 218 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 220 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 221 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 222 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 223 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Pennsylvania |
| 225 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 226 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 227 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 228 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 231 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 232 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 233 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 236 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 239 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 240 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Pennsylvania |
| 241 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 242 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 244 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 245 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 246 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 247 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 248 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 249 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 250 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 251 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 252 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 253 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 254 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 255 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 256 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Wyoming |
| 257 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 258 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 259 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 260 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
California |
| 261 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 262 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 263 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 264 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 265 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 266 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 267 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 268 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 269 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Colorado |
| 271 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
18
|
|
|
| Optimum |
|
|
| Drawworks: |
Location |
| Rig |
| Depth (Feet)* |
| Rig Type |
| Horsepower |
North Dakota |
| 272 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 273 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 274 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 275 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 276 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 277 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 278 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 279 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 280 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 281 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 282 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 283 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Pennsylvania |
| 284 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Pennsylvania |
| 285 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 286 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Pennsylvania |
| 287 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 288 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 289 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 290 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 293 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 294 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 295 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 296 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Oklahoma |
| 297 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 298 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 299 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 300 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 302 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 303 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 304 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 305 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 306 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Colorado |
| 307 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 308 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 309 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 310 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 311 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 312 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 313 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 314 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 315 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 316 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 317 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 318 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 319 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 320 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 321 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 322 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 323 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 324 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
North Dakota |
| 325 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 326 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 327 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 328 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 329 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 330 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
19
|
|
|
| Optimum |
|
|
| Drawworks: |
Location |
| Rig |
| Depth (Feet)* |
| Rig Type |
| Horsepower |
Texas |
| 331 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 332 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 340 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 341 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 342 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Colorado |
| 343 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 344 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 345 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 346 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 347 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 348 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 349 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 351 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 352 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
North Dakota |
| 353 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Pennsylvania |
| 354 |
| 18,000 |
| AC (FlexRig4) |
| 1,500 |
Texas |
| 355 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 356 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 360 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 361 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 362 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Texas |
| 370 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
West Virginia |
| 371 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 372 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 373 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 374 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 375 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 376 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 377 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 378 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 379 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 380 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 381 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 382 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Louisiana |
| 383 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 384 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Pennsylvania |
| 385 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 386 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 387 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 388 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 389 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 390 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 391 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 392 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 393 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 394 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 395 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 396 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Louisiana |
| 397 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 398 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 399 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 415 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 416 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 417 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Louisiana |
| 418 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 419 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
20
|
|
|
| Optimum |
|
|
| Drawworks: |
Location |
| Rig |
| Depth (Feet)* |
| Rig Type |
| Horsepower |
Texas |
| 420 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 421 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 422 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 423 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
California |
| 424 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 425 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
California |
| 426 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 427 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 428 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 429 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 430 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 431 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 432 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 433 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 434 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 435 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 436 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 437 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Wyoming |
| 438 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 439 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
California |
| 440 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 441 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 442 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 443 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
California |
| 444 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 445 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 446 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 447 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Colorado |
| 448 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 449 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 450 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 451 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Louisiana |
| 452 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 453 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 454 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 455 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 456 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 457 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 458 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 459 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 460 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 461 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 462 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 463 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 464 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 465 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 466 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 467 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 468 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 469 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 470 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Ohio |
| 471 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 472 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 473 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 474 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 475 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
21
|
|
|
| Optimum |
|
|
| Drawworks: |
Location |
| Rig |
| Depth (Feet)* |
| Rig Type |
| Horsepower |
Texas |
| 477 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 478 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 479 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 480 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 481 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 482 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 483 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 485 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 486 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 487 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 488 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 489 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 490 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Louisiana |
| 491 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 492 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 493 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 494 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 495 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 496 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 497 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 498 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 499 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Pennsylvania |
| 500 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 501 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 502 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 503 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 504 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 505 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 506 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 507 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 508 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 509 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 510 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 511 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 512 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Pennsylvania |
| 513 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 514 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
North Dakota |
| 515 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
North Dakota |
| 516 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Colorado |
| 517 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 518 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Ohio |
| 519 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Wyoming |
| 520 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Ohio |
| 521 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Colorado |
| 522 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 523 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Colorado |
| 524 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 525 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 526 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 527 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Louisiana |
| 528 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 529 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 530 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Ohio |
| 531 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 532 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Louisiana |
| 533 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
22
|
|
|
| Optimum |
|
|
| Drawworks: |
Location |
| Rig |
| Depth (Feet)* |
| Rig Type |
| Horsepower |
Louisiana |
| 534 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
North Dakota |
| 535 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 536 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 537 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 538 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 539 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 540 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 541 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 542 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 543 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 544 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 545 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 546 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 547 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Oklahoma |
| 548 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 551 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 552 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 553 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 556 |
| 25,000 |
| AC (FlexRig5) |
| 1,500 |
Texas |
| 600 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 601 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 602 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 603 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 604 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 605 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 606 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 607 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Ohio |
| 608 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 609 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 610 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Ohio |
| 611 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 612 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 613 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 614 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 615 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 616 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 617 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 618 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 619 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 620 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 621 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 622 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 623 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 624 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 625 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 626 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 627 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Ohio |
| 628 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 629 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 630 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Oklahoma |
| 631 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 632 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 633 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 634 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 635 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 636 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
23
|
|
|
| Optimum |
|
|
| Drawworks: |
Location |
| Rig |
| Depth (Feet)* |
| Rig Type |
| Horsepower |
Texas |
| 637 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 638 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 639 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
North Dakota |
| 640 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 641 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 642 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 643 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 644 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 645 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 646 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 647 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 648 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 649 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 650 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 651 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 652 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 653 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 656 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
New Mexico |
| 657 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Texas |
| 659 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
|
|
|
|
|
|
|
|
|
Conventional Rigs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
| 139 |
| 30,000 |
| SCR |
| 3,000 |
Louisiana |
| 161 |
| 30,000 |
| SCR |
| 3,000 |
|
|
|
|
|
|
|
|
|
Offshore Platform Rigs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana |
| 100 |
| 30,000 |
| Conventional |
| 3,000 |
Louisiana |
| 105 |
| 30,000 |
| Conventional |
| 3,000 |
Gulf of Mexico |
| 107 |
| 30,000 |
| Conventional |
| 3,000 |
Gulf of Mexico |
| 201 |
| 30,000 |
| Tension-leg |
| 3,000 |
Gulf of Mexico |
| 203 |
| 20,000 |
| Self-Erecting |
| 2,500 |
Gulf of Mexico |
| 204 |
| 30,000 |
| Tension-leg |
| 3,000 |
Gulf of Mexico |
| 205 |
| 20,000 |
| Self-Erecting |
| 2,000 |
Louisiana |
| 206 |
| 20,000 |
| Self-Erecting |
| 2,000 |
|
|
|
|
|
|
|
|
|
* From time to time we may modify certain FlexRigs to increase the setback capacity of a rig. As such, the stated “optimum depth” as listed above may be higher in certain instances depending on modifications to certain rigs.
The following table sets forth information with respect to the utilization of our U.S. land and offshore drilling rigs for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year ended September 30, |
| ||||||||
|
| 2013 |
| 2014 |
| 2015 |
| 2016 |
| 2017 |
|
U.S. Land Rigs |
|
|
|
|
|
|
|
|
|
|
|
Number of rigs at end of period |
| 302 |
| 329 |
| 343 |
| 348 |
| 350 |
|
Average rig utilization rate during period (1) |
| 82 | % | 86 | % | 62 | % | 30 | % | 45 | % |
U.S. Offshore Platform Rigs |
|
|
|
|
|
|
|
|
|
|
|
Number of rigs at end of period |
| 9 |
| 9 |
| 9 |
| 9 |
| 8 |
|
Average rig utilization rate during period (1) |
| 89 | % | 89 | % | 93 | % | 82 | % | 74 | % |
|
|
24
The following table sets forth certain information concerning our international drilling rigs as of September 30, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
| Optimum |
|
|
| Drawworks: |
Location |
| Rig |
| Depth (Feet)* |
| RigType |
| Horsepower |
Argentina |
| 123 |
| 26,000 |
| SCR |
| 2,100 |
Argentina |
| 151 |
| 30,000 + |
| SCR |
| 3,000 |
Argentina |
| 175 |
| 30,000 |
| SCR |
| 3,000 |
Argentina |
| 177 |
| 30,000 |
| SCR |
| 3,000 |
Argentina |
| 210 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 211 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 213 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 217 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 219 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 224 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 229 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 230 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 234 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 235 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 238 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Argentina |
| 335 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Argentina |
| 336 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Argentina |
| 337 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Argentina |
| 338 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Bahrain |
| 292 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Bahrain |
| 301 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Bahrain |
| 339 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Colombia |
| 133 |
| 30,000 |
| SCR |
| 3,000 |
Colombia |
| 152 |
| 30,000 + |
| SCR |
| 3,000 |
Colombia |
| 237 |
| 18,000 |
| AC (FlexRig3) |
| 1,500 |
Colombia |
| 243 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
Colombia |
| 291 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Colombia |
| 333 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Colombia |
| 334 |
| 8,000 |
| AC (FlexRig4) |
| 1,150 |
Colombia |
| 900 |
| 30,000 + |
| AC Drive |
| 3,000 |
Ecuador |
| 117 |
| 26,000 |
| SCR |
| 2,500 |
Ecuador |
| 121 |
| 20,000 |
| SCR |
| 1,700 |
Ecuador |
| 132 |
| 18,000 |
| SCR |
| 1,500 |
Ecuador |
| 138 |
| 26,000 |
| SCR |
| 2,500 |
Ecuador |
| 176 |
| 18,000 |
| SCR |
| 1,500 |
Ecuador |
| 190 |
| 26,000 |
| SCR |
| 2,000 |
UAE |
| 476 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
UAE |
| 484 |
| 22,000 |
| AC (FlexRig3) |
| 1,500 |
* From time to time we may modify certain FlexRigs to increase the setback capacity of a rig. As such, the stated “optimum depth” as listed above may be higher in certain instances depending on modifications to certain rigs.
The following table sets forth information with respect to the utilization of our international drilling rigs for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
| Years ended September 30, |
| ||||||||
|
| 2013 |
| 2014 |
| 2015 |
| 2016 |
| 2017 |
|
Number of rigs at end of period |
| 29 |
| 36 |
| 38 |
| 38 |
| 38 |
|
Average rig utilization rate during period (1)(2) |
| 82 | % | 74 | % | 51 | % | 39 | % | 36 | % |
|
|
|
|
25
STOCK PORTFOLIO
Information required by this item regarding our stock portfolio may be found in, and is incorporated by reference to, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Stock Portfolio Held” included in this Form 10‑K.
1.Investigation by the Department of the Interior.
On November 8, 2013, the United States District Court
| ITEM 3. LEGAL PROCEEDINGS | ||||||||||||||
2.Venezuela Expropriation.
Our wholly‑owned subsidiaries, H&PIDC 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.
26
2022 FORM 10-K|35EXECUTIVE OFFICERS OF THE COMPANY
The following table sets forth the names and ages of our executive officers, together with all positions and offices held by such executive officers with the Company or the Company’s wholly‑owned subsidiary, Helmerich & Payne International Drilling Co. Except as noted below, all positions and offices held are with the Company. Officers are elected to serve until the meeting of the Board of Directors following the next Annual Meeting of Stockholders and until their successors have been duly elected and have qualified or until their earlier resignation or removal.
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27
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
| ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | ||||||||||||||
and Dividends
|
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|
|
|
| 2016 |
| 2017 |
| ||||||||
Quarter |
| High |
| Low |
| High |
| Low |
| ||||
First |
| $ | 61.70 |
| $ | 46.32 |
| $ | 85.78 |
| $ | 60.39 |
|
Second |
|
| 64.06 |
|
| 40.02 |
|
| 81.30 |
|
| 63.66 |
|
Third |
|
| 69.20 |
|
| 55.75 |
|
| 69.97 |
|
| 49.46 |
|
Fourth |
|
| 70.28 |
|
| 56.19 |
|
| 58.64 |
|
| 42.16 |
|
Dividends
We paid quarterly cash dividends during the past two fiscal years as shown in the table below.years. Payment of future dividends will depend on earnings and other factors.
|
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|
|
| Paid per Share |
| Total Payment |
| ||||||||
|
| Fiscal |
| Fiscal |
| ||||||||
Quarter |
| 2016 |
| 2017 |
| 2016 |
| 2017 |
| ||||
First |
| $ | 0.6875 |
| $ | 0.7000 |
| $ | 74,560,506 |
| $ | 76,176,075 |
|
Second |
|
| 0.6875 |
|
| 0.7000 |
|
| 74,739,803 |
|
| 76,441,828 |
|
Third |
|
| 0.6875 |
|
| 0.7000 |
|
| 74,740,993 |
|
| 76,443,228 |
|
Fourth |
|
| 0.7000 |
|
| 0.7000 |
|
| 76,111,240 |
|
| 76,453,820 |
|
28
Performance Graph
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
| INDEXED RETURNS |
| ||||||||
|
| Base Period |
| Years Ending |
| ||||||||
Company / Index |
| Sep 12 |
| Sep 13 |
| Sep 14 |
| Sep 15 |
| Sep 16 |
| Sep 17 |
|
Helmerich & Payne, Inc. |
| 100 |
| 146.85 |
| 213.72 |
| 107.52 |
| 160.53 |
| 130.54 |
|
S&P 500 Index |
| 100 |
| 119.34 |
| 142.89 |
| 142.02 |
| 163.93 |
| 194.44 |
|
S&P 500 Oil & Gas Drilling Index |
| 100 |
| 110.74 |
| 97.25 |
| 43.87 |
| 47.72 |
| 38.09 |
|
S&P 1500 Oil & Gas Drilling Index |
| 100 |
| 112.55 |
| 103.39 |
| 44.91 |
| 47.75 |
| 40.37 |
|
| Indexed Returns | |||||||||||||||||||||||||||||||||||
| Base Period | Years Ending | ||||||||||||||||||||||||||||||||||
| Company / Index | Sep 2017 | Sep 2018 | Sep 2019 | Sep 2020 | Sep 2021 | Sep 2022 | |||||||||||||||||||||||||||||
| Helmerich & Payne, Inc. | $ | 100.00 | $ | 137.00 | $ | 88.00 | $ | 43.00 | $ | 70.00 | $ | 90.00 | |||||||||||||||||||||||
| S&P 600 Index | 100.00 | 120.00 | 108.00 | 100.00 | 157.00 | 127.00 | |||||||||||||||||||||||||||||
| Dow Jones U.S. Select Oil Equipment & Services Index | 100.00 | 102.00 | 52.00 | 22.00 | 42.00 | 45.00 | |||||||||||||||||||||||||||||
| Philadelphia Stock Exchange Oil Service Sector Index | 100.00 | 107.00 | 48.00 | 21.00 | 43.00 | 46.00 | |||||||||||||||||||||||||||||
2022 FORM 10-K|36
29
| ITEM 6. (RESERVED) | ||||||||||||||
Item 6. SELECTED FINANCIAL DATA
The following table summarizes selected financial information and should be read in conjunction with Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8—“Financial Statements and Supplementary Data” included in this Form 10‑K.
Five‑year Summary of Selected Financial Data
|
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|
|
|
|
|
|
|
|
| 2017 |
| 2016 |
| 2015 |
| 2014 |
| 2013 |
| |||||
|
| (in thousands except per share amounts) |
| |||||||||||||
Operating revenues |
| $ | 1,804,741 |
| $ | 1,624,232 |
| $ | 3,161,702 |
| $ | 3,715,968 |
| $ | 3,392,932 |
|
Income (loss) from continuing operations |
|
| (127,863) |
|
| (52,990) |
|
| 420,474 |
|
| 706,610 |
|
| 720,653 |
|
Income (loss) from discontinued operations |
|
| (349) |
|
| (3,838) |
|
| (47) |
|
| (47) |
|
| 15,186 |
|
Net income (loss) |
|
| (128,212) |
|
| (56,828) |
|
| 420,427 |
|
| 706,563 |
|
| 735,839 |
|
Basic earnings (loss) per share from continuing operations |
|
| (1.20) |
|
| (0.50) |
|
| 3.88 |
|
| 6.52 |
|
| 6.74 |
|
Basic earnings (loss) per share from discontinued operations |
|
| — |
|
| (0.04) |
|
| — |
|
| — |
|
| 0.14 |
|
Basic (loss) earnings per share |
|
| (1.20) |
|
| (0.54) |
|
| 3.88 |
|
| 6.52 |
|
| 6.88 |
|
Diluted earnings (loss) per share from continuing operations |
|
| (1.20) |
|
| (0.50) |
|
| 3.85 |
|
| 6.44 |
|
| 6.65 |
|
Diluted earnings (loss) per share from discontinued operations |
|
| — |
|
| (0.04) |
|
| — |
|
| — |
|
| 0.14 |
|
Diluted earnings (loss) per share |
|
| (1.20) |
|
| (0.54) |
|
| 3.85 |
|
| 6.44 |
|
| 6.79 |
|
Total assets* |
|
| 6,439,988 |
|
| 6,832,019 |
|
| 7,147,242 |
|
| 6,725,316 |
|
| 6,265,923 |
|
Long‑term debt |
|
| 492,902 |
|
| 491,847 |
|
| 492,443 |
|
| 39,502 |
|
| 79,137 |
|
Cash dividends declared per common share |
|
| 2.800 |
|
| 2.775 |
|
| 2.750 |
|
| 2.625 |
|
| 1.300 |
|
*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.
30
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Risk Factors and Forward‑Looking Statements
| ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | ||||||||||||||
With the exception of historical information, the matters discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward‑looking statements. These forward‑looking statements are based on various assumptions. We caution that, while we believe such assumptions to be reasonable and make them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. We are including this cautionary statement to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 for any forward‑looking statements made by us or persons acting on our behalf. The factors identified in this cautionary statement and those factors discussed under Item 1A—“Risk Factors” of this Form 10‑K are important factors (but not necessarily inclusive of all important factors) that could cause actual results to differ materially from those expressed in any forward‑looking statement made by us or persons acting on our behalf. Except as required by law, we undertake no duty to update or revise our forward‑looking statements based on changes of internal estimates or expectations or otherwise.
Executive Summary
| Executive Summary | ||||||||||||||
Except
2022 FORM 10-K|37| Market Outlook | ||||||||||||||
2022 FORM 10-K|38| Recent Developments | ||||||||||||||
2022 FORM 10-K|39| Contract Backlog | ||||||||||||||
| (in millions) | September 30, 2022 | September 30, 2021 | Percentage Reasonably Expected to be Fulfilled in Fiscal Year 2024 and Thereafter | ||||||||||||||
| North America Solutions | $ | 863.6 | $ | 429.6 | 26.0 | % | |||||||||||
| Offshore Gulf of Mexico | 7.6 | 17.2 | — | ||||||||||||||
| International Solutions | 301.2 | 125.2 | 45.3 | ||||||||||||||
| $ | 1,172.4 | $ | 572.0 | ||||||||||||||
results of operations"
within this Form 10-K.Results of Operations for the Fiscal Years Ended September 30, 2022 and 2021 | ||||||||||||||
All
31
loss of $12.0 million ($0.11 loss per share) from the settlement of litigation and a $3.8 million loss ($0.04 loss per share) from discontinued operations.
Operating Revenue Consolidated operating revenues were $1.8$2.1 billion in 2017, $1.6fiscal year 2022 and $1.2 billion in 2016 and $3.2 billion in 2015,fiscal year 2021, including early termination revenue of $29.4 million, $219.0$0.7 million and $222.3$7.7 million in each respective fiscal year. Excluding early termination revenue, operating revenue increased $370.1 million$0.8 billion in 2017fiscal year 2022 compared to 2016. Oil prices steeply declinedfiscal year 2021. The increase in fiscal year 2022 from over $106 per barrelfiscal year 2021 was primarily driven by an increase in June 2014 to below $30 per barrel in early 2016. During the second half of calendar 2016, oil prices increasedaverage rig pricing and have since been mostly fluctuating within a $45 to $55 per barrel price range. Primarily as a result of the impact of oil prices on drilling activity by exploration and production companies during that time frame, the number of revenue dayslevels in our U.S. LandNorth America Solutions segment totaled 57,120 in 2017, compared to 36,984 in 2016 and 75,866 in 2015. Our U.S. land rig utilization was 45 percent in 2017, 30 percent in 2016 and 62 percent in 2015. The average number of U.S. land rigs available was 349 rigs in 2017, 339 rigs in 2016 and 336 rigs in 2015. Rig utilization for offshore rigs was 74 percent in 2017, compared to 82 percent in 2016 and 93 percent in 2015. The International Land segment has been subject to a more prolonged impact so far from the decline in oil prices, causing revenue days to decline to 4,951 in 2017 from 5,364 in 2016 and 7,284 in 2015. Rig utilizationincreased activity levels in our International LandSolutions segment. Refer to segment was 36 percent in 2017, 39 percent in 2016results below for further details.
In 2016, we recorded a $26.0 million other‑than‑temporary impairment charge as our marketable equity security position in Atwood remained in a loss position during most of the fiscal year. Atwood is in the offshore drilling industry which was severely impacted by the downturn in the energy sector. In May 2017, Ensco plc (“Ensco”) announced that it entered into a definitive merger agreement under which Ensco would acquire Atwood in an all-stock transaction. The transaction closed on October 6, 2017. Under the terms of the merger agreement, we received 1.60 shares of Ensco for each share of our Atwood common stock.
Interest and dividend income was $5.9 million, $3.2 million and $5.8 million in 2017, 2016 and 2015, respectively. The higher income in 2017 was primarily due to higher earnings on available cash equivalents and short-term investments. The higher income in 2015 was primarily the result of Atwood declaring dividends during 2015. Those dividends ceased in early 2016.
Amortization
Direct operating2022 FORM 10-K|40Management monitors industry market conditions impacting its long‑livedreclassified as assets intangible assets and goodwill. When required, an impairment analysis is performed to determine if any impairment exists. We did not record any impairment in 2017. In 2016, we recorded a $6.3 million impairment charge to reduce the carryingheld-for-sale on our Consolidated Balance Sheets. The combined net book value of used drilling equipment from rigs thatthese assets was $5.4 million and were decommissioned from service in prior fiscal periods and written down to their estimated recoverablefair value atless cost to sell of $1.0 million, resulting in a non-cash impairment charge of $4.4 million, within our North America Solutions and International Solutions segments. The impairment charge was recorded in the timeConsolidated Statement of decommissioning. In 2015,Operations for the fiscal year ended September 30, 2022. Comparatively, during the fiscal year ended September 30, 2021, the Company developed a plan to sell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the majority of which were previously decommissioned, written down and/or held as capital spares, which resulted in an impairment charge of $56.4 million. Also, during the fiscal year ended September 30, 2021, we recorded $39.2formalized a plan to sell assets related to two of our lower margin service offerings, trucking and casing running services, all within our North America Solutions segment, which resulted in a non-cash impairment charge of $14.4 million.
GeneralSchlumberger, Ltd. and administrative expenses totaled $151.0 million in 2017, $146.2 million in 2016 and $134.7 million in 2015. During 2017, we incurred transaction costsreceived proceeds of $3.2approximately $22.0 million. We recognized an aggregate gain of $8.2 million related to this investment, which included a $0.5 million gain recognized upon the sale and a $7.7 million gain as a result of the change in the fair value of the investment during the fiscal year ended September 30, 2022.
32
Interest Expense Interest expense net of amounts capitalized totaled $19.7$19.2 million in 2017, $22.9fiscal year 2022 and $24.0 million in 2016 and $15.0 millionfiscal year 2021. The decrease in 2015. Interestinterest expense is primarily attributable to fixed‑a lower interest rate debt outstanding. There was a favorable adjustment to interest expense of $5.2 millionon our 2.90% Senior Notes due 2031 (issued in 2017 related to the reversal of previously booked uncertain tax positions where the statute of limitations has expired. Interest expense increased in 2016 from 2015 primarily due to the issuance of $500 million unsecured senior notes in March 2015. Capitalized interest was $0.3 million, $2.8 million and $7.0 million in 2017, 2016 and 2015, respectively. All of the capitalized interest is attributableSeptember 2021) as compared to our rig construction program.
4.65% Senior Notes due 2025, which was fully redeemed in October 2021.
During 2017, 2016 and 2015, we incurred $12.0 million, $10.3
2022 FORM 10-K|41On June 2, 2017, we completed a merger transaction (“MOTIVE Merger”) pursuant to which an unaffiliated drilling technology company, MOTIVE Drilling Technologies, Inc., a Delaware corporation (“MOTIVE”), was merged with and into our wholly owned subsidiary Spring Merger Sub, Inc., a Delaware corporation. MOTIVE survived the transaction and is now a wholly owned subsidiary of the Company. The operations for MOTIVE are included with all other non-reportable business segments. The MOTIVE Merger was accounted for as a business combination in accordance with Accounting Standards Codification (“ASC”) 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values.
MOTIVE has a proprietary Bit Guidance System that is an algorithm-driven system that considers the total economic consequences of directional drilling decisions and has proven to consistently lower drilling costs through more efficient drilling and increase hydrocarbon production through smoother wellbores and more accurate well placement. Given our strong and longstanding technology and innovation focus, we believe the technology will continue to advance and provide further benefits for the industry.
At the effective time of the MOTIVE Merger, MOTIVE shareholders received aggregate cash consideration of $74.3 million, net of customary closing adjustments, and may receive up to an additional $25.0$11.3 million in potential earnout payments based on future performance. Transaction costs related to the MOTIVE Merger incurred during fiscal 2017 were $3.2 million. We recorded revenue of $3.3 millionyears 2022 and a net loss of $2.2 million related to the MOTIVE Merger during fiscal 2017. Additional information regarding the MOTIVE acquisition is described in Note 2 “Business Combinations” to our consolidated financial statements.
2021, respectively. Expenses incurred within the country of Venezuela are reported as discontinued operations. In March 2016, the Venezuelan government implemented the previously announced plans for a new foreign currency exchange system. The implementation of this system resulted in a reported loss from discontinued operations of $3.8 million in fiscal 2016, all of which corresponds to the Company’s former operations in Venezuela.
Our wholly‑ownedwholly-owned subsidiaries, Helmerich & Payne International Drilling Co. ("HPIDC") and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. and PDVSA Petroleo, S.A. We are seeking damages for the takingseizure 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.
33
The following tables summarize operationstable presents certain information with respect to our North America Solutions reportable segment:
| (in thousands, except operating statistics) | 2022 | 2021 | % Change | ||||||||||||||
| Operating revenues | $ | 1,788,167 | $ | 1,026,364 | 74.2 | % | |||||||||||
| Direct operating expenses | 1,218,134 | 773,507 | 57.5 | ||||||||||||||
| Depreciation and amortization | 375,250 | 392,415 | (4.4) | ||||||||||||||
| Research and development | 26,728 | 21,811 | 22.5 | ||||||||||||||
| Selling, general and administrative expense | 43,796 | 51,089 | (14.3) | ||||||||||||||
| Asset impairment charges | 1,868 | 70,850 | (97.4) | ||||||||||||||
| Restructuring charges | 498 | 3,868 | (87.1) | ||||||||||||||
| Segment operating income (loss) | $ | 121,893 | $ | (287,176) | (142.4) | ||||||||||||
Financial Data and Other Operating Statistics1: | |||||||||||||||||
Direct margin (Non-GAAP)2 | $ | 570,033 | $ | 252,857 | 125.4 | ||||||||||||
Revenue days3 | 59,672 | 39,199 | 52.2 | ||||||||||||||
Average active rigs4 | 163 | 107 | 52.3 | ||||||||||||||
Number of active rigs at the end of period5 | 176 | 127 | 38.6 | ||||||||||||||
| Number of available rigs at the end of period | 236 | 236 | — | ||||||||||||||
| Reimbursements of "out-of-pocket" expenses | $ | 232,092 | $ | 113,897 | 103.8 | ||||||||||||
Comparisondividing revenue days by total days in the applicable period (i.e., 365 days).
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|
|
| |
|
| 2017 |
| 2016 |
| % Change |
| ||
|
| (in thousands, except operating statistics) |
| ||||||
U.S. LAND OPERATIONS |
|
|
|
|
|
|
|
|
|
Operating revenues |
| $ | 1,439,523 |
| $ | 1,242,462 |
| 15.9 | % |
Direct operating expenses |
|
| 984,205 |
|
| 603,800 |
| 63.0 |
|
General and administrative expense |
|
| 50,712 |
|
| 50,057 |
| 1.3 |
|
Depreciation |
|
| 499,486 |
|
| 508,237 |
| (1.7) |
|
Asset impairment charge |
|
| — |
|
| 6,250 |
| (100.0) |
|
Segment operating income (loss) |
| $ | (94,880) |
| $ | 74,118 |
| (228.0) |
|
Operating Statistics: |
|
|
|
|
|
|
|
|
|
Revenue days |
|
| 57,120 |
|
| 36,984 |
| 54.4 | % |
Average rig revenue per day |
| $ | 22,607 |
| $ | 31,369 |
| (27.9) |
|
Average rig expense per day |
| $ | 14,623 |
| $ | 14,117 |
| 3.6 |
|
Average rig margin per day |
| $ | 7,984 |
| $ | 17,252 |
| (53.7) |
|
Number of rigs at end of period |
|
| 350 |
|
| 348 |
| 0.6 |
|
Rig utilization |
|
| 45 | % |
| 30 | % | 50.0 |
|
Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $148,218 and $82,337 for 2017 and 2016, respectively.
In 2017, the U.S. Land segment had an operating loss of $94.9 million2022 as compared to operating income of $74.1 million in 2016. Included in U.S. land revenues for 2017 and 2016 is approximately $24.5 million and $219.0 million, respectively, from early termination of fixed‑term contracts. Fixed‑term contracts customarily provide for termination at$0.8 billion during 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).
Excluding early termination revenue of $428 and $5,921 per day for 2017 and 2016, respectively, average revenue per day for 2017 decreased by $3,269 to $22,179 from $25,448 in 2016. Our activity has increased year-over-year in response to higher commodity prices resulting in a 54 percent increase in revenue days when comparing 2017 to 2016. However, legacy term contracts at high dayrates make up a lower proportion of our 2017 activity due to continued contract expirations. Further, newly contracted rigs which made up the majority of our 2017 activity were priced at relatively lower levels which reflected 2017 market conditions.
Average rig expense increased $506 per day to $14,623 in 2017 from $14,117 in 2016.fiscal year ended September 30, 2021. This increase was primarily driven by an increase of $241.0 million in labor expense and an increase of $87.0 million in materials and supplies as we experienced higher activity levels and had an increase in field wages beginning in December 2021.
Depreciation includes charges for abandoned equipment of $42.2 million and $38.8 million in 2017 and 2016, respectively. Included in abandonments in 2017 are older rig components that were replaced by upgrades to our rig fleet to meet customer demands for additional capabilities. Included in abandonments in 2016 is the retirement of used drilling equipment. During fiscal 2016, we recorded an asset impairment chargelocated in the U.S. Land segmentthat were included in the ADNOC sale during the fourth quarter of $6.3 million to reduce the carrying value of rig and rig related equipment classified as held for sale to their estimated fair values, based on expected sales prices. Excluding the abandonments, depreciation in 2017 decreased from 2016, primarily due to lowerfiscal year 2021 coupled with ongoing relatively low levels of capital expenditures during 2017the 2022 fiscal year.
Rig utilization increased to 45 percent in 2017 from 30 percent in 2016. The total number of rigs atfiscal year ended September 30, 2017 was 3502022 compared to 348 rigs atthe fiscal year ended September 30, 2016. The net increase is due to two new FlexRigs completed2021. This decrease was primarily driven by a $5.3 million decrease in 2017 and included in our operating statistics.
At September 30, 2017, 197 out of 350 existing rigs in the U.S. Land segment were generating revenue. Of the 197 rigs generating revenue, 100 were under fixed‑term contracts, and 97 were working in the spot market. At
34
2022 FORM 10-K|42November 16, 2017,Asset Impairment ChargesDuring the number of existing rigs under fixed‑term contracts in the segment was 103 and the number of rigs working in the spot market was 97.
Comparison of the yearsfiscal year ended September 30, 20172022, we identified two partial rig substructures that met the asset held-for-sale criteria and 2016
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| |
|
| 2017 |
| 2016 |
| % Change |
| ||
|
| (in thousands, except operating statistics) |
| ||||||
OFFSHORE OPERATIONS |
|
|
|
|
|
|
|
|
|
Operating revenues |
| $ | 136,263 |
| $ | 138,601 |
| (1.7) | % |
Direct operating expenses |
|
| 96,593 |
|
| 106,983 |
| (9.7) |
|
General and administrative expense |
|
| 3,705 |
|
| 3,464 |
| 7.0 |
|
Depreciation |
|
| 11,764 |
|
| 12,495 |
| (5.9) |
|
Segment operating income |
| $ | 24,201 |
| $ | 15,659 |
| 54.6 |
|
Operating Statistics: |
|
|
|
|
|
|
|
|
|
Revenue days |
|
| 2,277 |
|
| 2,708 |
| (15.9) | % |
Average rig revenue per day |
| $ | 34,332 |
| $ | 26,973 |
| 27.3 |
|
Average rig expense per day |
| $ | 23,172 |
| $ | 19,381 |
| 19.6 |
|
Average rig margin per day |
| $ | 11,160 |
| $ | 7,592 |
| 47.0 |
|
Number of rigs at end of period |
|
| 8 |
|
| 9 |
| (11.1) |
|
Rig utilization |
|
| 74 | % |
| 82 | % | (9.8) |
|
Operating statistics for per day revenue, expense and margin do not include reimbursementswere reclassified as assets held-for-sale on our Consolidated Balance Sheets. The combined net book value of “out‑of‑pocket” expensesthese assets of $21,578 and $23,138 for 2017 and 2016, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.
Average rig revenue per day and average rig margin per day increased in 2017 compared to 2016 primarily due to several rigs moving to higher pricing from previous standby or other special dayrates.
During the second quarter of fiscal 2017, we sold one of our offshore rigs. At September 30, 2017, five of our eight platform rigs$2.0 million were contracted compared to seven of nine available rigs at September 30, 2016.
35
Comparison of the years ended September 30, 2017 and 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| 2017 |
| 2016 |
| % Change |
| ||
|
| (in thousands, except operating statistics) |
| ||||||
INTERNATIONAL LAND OPERATIONS |
|
|
|
|
|
|
|
|
|
Operating revenues |
| $ | 212,972 |
| $ | 229,894 |
| (7.4) | % |
Direct operating expenses |
|
| 163,486 |
|
| 183,969 |
| (11.1) |
|
General and administrative expense |
|
| 3,088 |
|
| 2,909 |
| 6.2 |
|
Depreciation |
|
| 53,622 |
|
| 57,102 |
| (6.1) |
|
Segment operating loss |
| $ | (7,224) |
| $ | (14,086) |
| 48.7 |
|
Operating Statistics: |
|
|
|
|
|
|
|
|
|
Revenue days |
|
| 4,951 |
|
| 5,364 |
| (7.7) | % |
Average rig revenue per day |
| $ | 40,979 |
| $ | 39,044 |
| 5.0 |
|
Average rig expense per day |
| $ | 29,761 |
| $ | 28,638 |
| 3.9 |
|
Average rig margin per day |
| $ | 11,218 |
| $ | 10,406 |
| 7.8 |
|
Number of rigs at end of period |
|
| 38 |
|
| 38 |
| — |
|
Rig utilization |
|
| 36 | % |
| 39 | % | (7.7) |
|
Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $10,074 and $20,458 for 2017 and 2016, respectively. Also excluded are the effects of currency revaluation income and expense.
The International Land segment had an operating loss of $7.2 million for 2017 compared to $14.1 million for 2016.
Excluding early termination revenue of $955 per day in 2017, the average rig margin per day for 2017 compared to 2016 decreased by $143 to $10,263. Low oil prices during 2016 and 2017 continue to have a negative effect on customer spending. We experienced an 8 percent decrease in revenue days when comparing 2017 to 2016. The average number of active rigs was 13.6 during 2017 compared to 14.7 during 2016.
Although direct operating expenses decreased in 2017 to $163.5 million from $184.0 million in 2016, the average rig expense per day increased $1,123 or 4 percent as compared to the 2016 average rig expense.
Included in direct operating expenses are foreign currency transaction losses of $6.0 million and $9.8 million for 2017 and 2016, respectively. The 2016 losses were primarily due to a devaluation of the Argentine peso in December 2015.
36
Comparison of the years ended September 30, 2016 and 2015
|
|
|
|
|
|
|
|
|
|
|
| 2016 |
| 2015 |
| % Change |
| ||
|
| (in thousands, except operating statistics) |
| ||||||
U.S. LAND OPERATIONS |
|
|
|
|
|
|
|
|
|
Operating revenues |
| $ | 1,242,462 |
| $ | 2,523,518 |
| (50.8) | % |
Direct operating expenses |
|
| 603,800 |
|
| 1,254,424 |
| (51.9) |
|
General and administrative expense |
|
| 50,057 |
|
| 50,769 |
| (1.4) |
|
Depreciation |
|
| 508,237 |
|
| 519,950 |
| (2.3) |
|
Asset impairment charge |
|
| 6,250 |
|
| — |
| 100.0 |
|
Segment operating income |
| $ | 74,118 |
| $ | 698,375 |
| (89.4) |
|
Operating Statistics: |
|
|
|
|
|
|
|
|
|
Revenue days |
|
| 36,984 |
|
| 75,866 |
| (51.3) | % |
Average rig revenue per day |
| $ | 31,369 |
| $ | 30,211 |
| 3.8 |
|
Average rig expense per day |
| $ | 14,117 |
| $ | 13,483 |
| 4.7 |
|
Average rig margin per day |
| $ | 17,252 |
| $ | 16,728 |
| 3.1 |
|
Number of rigs at end of period |
|
| 348 |
|
| 343 |
| 1.5 |
|
Rig utilization |
|
| 30 | % |
| 62 | % | (51.6) |
|
Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $82,337 and $231,528 for 2016 and 2015, respectively.
Rig utilization in 2016 excludes four FlexRigs completed and ready for delivery at September 30, 2016.
Operating income in the U.S. Land segment decreased to $74.1 million in 2016 from $698.4 million in 2015. Included in U.S. land revenues for 2016 and 2015 is approximately $219.0 million and $203.6 million, respectively, from early termination of fixed-term contracts.
Excluding early termination related revenue, the average revenue per day for 2016 decreased by $2,080 to $25,448 from $27,528 in 2015. Low oil prices had a negative effect on customer spending. Some customers did not renew expiring contracts while others elected to terminate fixed-term contracts early. As a result, we experienced a 51 percent decrease in revenue days when comparing 2016 to 2015. 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).
The average rig expense per day increased to $14,117 in 2016 from $13,483 in 2015. In September 2016, we entered into a settlement agreement, subsequently approved by the court, regarding a lawsuit filed by an employee who was injured while working on a U.S. land rig. After taking into account amounts to be paid by our various insurers, we recorded an $18.8 million expense which reduced operating income and negatively impacted the 2016 average rig expense per day by $508.
Depreciation includes charges for abandoned equipment of $38.8 million and $42.6 million in 2016 and 2015, respectively. Included in abandonments in 2016 is the retirement of used drilling equipment. Included in abandonments in 2015 is the decommissioning of 23 SCR rigs, including six conventional rigs, six FlexRig1s and 11 FlexRig2s, and spare equipment for drilling rigs. We recorded in fiscal 2016 a $6.3 million impairment charge to reduce the carrying value in rig and rig related equipment classified as held for sale to their estimated fair values, based on expected sales prices. The used drilling equipment is from rigs that were decommissioned from service in prior fiscal periods and written down to their estimated recoverablescrap value atof $0.1 million, resulting in a non-cash impairment charge of $1.9 million during the time of decommissioning. Excluding the abandonment, depreciation in 2016 decreased from 2015, primarily due to low levels of capital expenditures in 2016 and the decommissioning of rigs in 2015.
Rig utilization decreased to 30 percent in 2016 from 62 percent in 2015. The total number of rigs atfiscal year ended September 30, 2016 was 348 compared to 343 rigs at2022 in the Consolidated Statement of Operations. Comparatively, during the fiscal year ended September 30, 2015. The net increase is due2021, the Company developed a plan to five new FlexRigs completedsell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the majority of which were previously decommissioned, written down and/or held as capital spares. This resulted in 2016 and included in our operating statistics.
37
At$56.4 million during the year ended September 30, 2016, 95 out2021. During the same period, we also formalized a plan to sell assets related to two of 348 existing rigsour lower margin service offerings, trucking and casing running services, all within our North America Solutions segment, which resulted in a non-cash impairment charge of $14.4 million during the U.S. Land segment were generating revenue. Ofyear ended September 30, 2021.
Comparison of thefiscal years ended September 30, 2022 and 2021, we incurred $0.5 million and $3.9 million, respectively, in restructuring charges. The charges incurred during the fiscal year ended September 30, 2021 primarily included charges of $3.8 million related to the relocation of the Houston assembly facility and the downsizing of storage yards used for idle rigs.
| (in thousands, except operating statistics) | 2022 | 2021 | % Change | ||||||||||||||
| Operating revenues | $ | 125,465 | $ | 126,399 | (0.7) | % | |||||||||||
| Direct operating expenses | 90,415 | 97,249 | (7.0) | ||||||||||||||
| Depreciation | 9,175 | 10,557 | (13.1) | ||||||||||||||
| Selling, general and administrative expense | 2,661 | 2,624 | 1.4 | ||||||||||||||
| Segment operating income | $ | 23,214 | $ | 15,969 | 45.4 | ||||||||||||
Financial Data and Other Operating Statistics1: | |||||||||||||||||
Direct margin (Non-GAAP)2 | $ | 35,050 | $ | 29,150 | 20.2 | ||||||||||||
Revenue days3 | 1,460 | 1,552 | (5.9) | ||||||||||||||
Average active rigs4 | 4 | 4 | — | ||||||||||||||
Number of active rigs at the end of period5 | 4 | 4 | — | ||||||||||||||
| Number of available rigs at the end of period | 7 | 7 | — | ||||||||||||||
| Reimbursements of "out-of-pocket" expenses | $ | 26,077 | $ | 27,388 | (4.8) | ||||||||||||
2022 FORM 10-K|43| (in thousands, except operating statistics) | 2022 | 2021 | % Change | ||||||||||||||
| Operating revenues | $ | 136,072 | $ | 57,917 | 134.9 | % | |||||||||||
| Direct operating expenses | 120,780 | 68,672 | 75.9 | ||||||||||||||
| Depreciation | 4,156 | 2,013 | 106.5 | ||||||||||||||
| Selling, general and administrative expense | 8,779 | 8,028 | 9.4 | ||||||||||||||
| Asset impairment charges | 2,495 | — | — | ||||||||||||||
| Restructuring charges | — | 207 | (100.0) | ||||||||||||||
| Segment operating loss | $ | (138) | $ | (21,003) | (99.3) | ||||||||||||
Financial Data and Other Operating Statistics1: | |||||||||||||||||
Direct margin (Non-GAAP)2 | $ | 15,292 | $ | (10,755) | (242.2) | ||||||||||||
Revenue days3 | 3,036 | 1,815 | 67.3 | ||||||||||||||
Average active rigs4 | 8 | 5 | 60.0 | ||||||||||||||
Number of active rigs at the end of period5 | 12 | 6 | 100.0 | ||||||||||||||
| Number of available rigs at the end of period | 28 | 30 | (6.7) | ||||||||||||||
| Reimbursements of "out-of-pocket" expenses | $ | 4,910 | $ | 6,693 | (26.6) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| 2016 |
| 2015 |
| % Change |
| ||
|
| (in thousands, except operating statistics) |
| ||||||
OFFSHORE OPERATIONS |
|
|
|
|
|
|
|
|
|
Operating revenues |
| $ | 138,601 |
| $ | 241,666 |
| (42.6) | % |
Direct operating expenses |
|
| 106,983 |
|
| 158,488 |
| (32.5) |
|
General and administrative expense |
|
| 3,464 |
|
| 3,517 |
| (1.5) |
|
Depreciation |
|
| 12,495 |
|
| 11,659 |
| 7.2 |
|
Segment operating income |
| $ | 15,659 |
| $ | 68,002 |
| (77.0) |
|
Operating Statistics: |
|
|
|
|
|
|
|
|
|
Revenue days |
|
| 2,708 |
|
| 3,067 |
| (11.7) | % |
Average rig revenue per day |
| $ | 26,973 |
| $ | 44,125 |
| (38.9) |
|
Average rig expense per day |
| $ | 19,381 |
| $ | 27,246 |
| (28.9) |
|
Average rig margin per day |
| $ | 7,592 |
| $ | 16,879 |
| (55.0) |
|
Number of rigs at end of period |
|
| 9 |
|
| 9 |
| — |
|
Rig utilization |
|
| 82 | % |
| 93 | % | (11.8) |
|
Operating statistics for per day revenue,Expenses Direct operating expenses increased to $120.8 million during the fiscal year ended September 30, 2022 as compared to $68.7 million during the fiscal year ended September 30, 2021. This increase was primarily driven by an increase of $25.9 million in labor expense and margin do not include reimbursementsan increase of “out‑of‑pocket” expenses of $23,138$25.4 million in materials and $33,254 for 2016 and 2015, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.
Average rig revenue per day, average rig expense per day and average rig margin per day decreased in 2016 compared to 2015 primarily due to several rigs moving to lower pricing while on standby or other special dayrates.
Atsupplies as we experienced higher activity levels.
2022 FORM 10-K|44| (in thousands) | 2022 | 2021 | % Change | ||||||||||||||
| Operating revenues | $ | 66,287 | $ | 43,304 | 53.1 | % | |||||||||||
| Direct operating expenses | 50,683 | 50,064 | 1.2 | ||||||||||||||
| Depreciation | 1,701 | 1,426 | 19.3 | ||||||||||||||
| Research and development | — | 127 | (100.0) | ||||||||||||||
| Selling, general and administrative expense | 1,183 | 1,205 | (1.8) | ||||||||||||||
| Restructuring charges | — | 186 | (100.0) | ||||||||||||||
| Operating income (loss) | $ | 12,720 | $ | (9,704) | (231.1) | ||||||||||||
Comparison ofuse our Captive insurance companies to insure the deductibles for our domestic workers’ compensation, general liability, automobile liability claims programs, and medical stop-loss program and to insure the deductibles from the Company's international casualty and rig property programs. Intercompany premium revenues recorded by the Captives during the fiscal years ended September 30, 20162022 and 2015
|
|
|
|
|
|
|
|
|
|
|
| 2016 |
| 2015 |
| % Change |
| ||
|
| (in thousands, except operating statistics) |
| ||||||
INTERNATIONAL LAND OPERATIONS |
|
|
|
|
|
|
|
|
|
Operating revenues |
| $ | 229,894 |
| $ | 382,331 |
| (39.9) | % |
Direct operating expenses |
|
| 183,969 |
|
| 289,700 |
| (36.5) |
|
General and administrative expense |
|
| 2,909 |
|
| 3,148 |
| (7.6) |
|
Depreciation |
|
| 57,102 |
|
| 57,334 |
| (0.4) |
|
Asset impairment charge |
|
| — |
|
| 39,242 |
| (100.0) |
|
Segment operating loss |
| $ | (14,086) |
| $ | (7,093) |
| (98.6) |
|
Operating Statistics: |
|
|
|
|
|
|
|
|
|
Revenue days |
|
| 5,364 |
|
| 7,284 |
| (26.4) | % |
Average rig revenue per day |
| $ | 39,044 |
| $ | 47,352 |
| (17.5) |
|
Average rig expense per day |
| $ | 28,638 |
| $ | 34,848 |
| (17.8) |
|
Average rig margin per day |
| $ | 10,406 |
| $ | 12,504 |
| (16.8) |
|
Number of rigs at end of period |
|
| 38 |
|
| 38 |
| — |
|
Rig utilization |
|
| 39 | % |
| 51 | % | (23.5) |
|
Direct Operating statisticsExpensesDirect operating expenses consisted primarily of $7.0 million and $12.6 million in adjustments to accruals for per day revenue, expenseestimated losses allocated to the Captives and margin do not include reimbursementsrig and casualty insurance premiums of “out‑of‑pocket” expenses$35.6 million and $21.9 million during the fiscal years ended September 30, 2022 and 2021, respectively. The change to accruals for estimated losses is primarily due to actuarial valuation adjustments by our third-party actuary.
Results of Operations for the Fiscal Years Ended September 30, 2021 and 2020 | ||||||||||||||
The International Land segment had an operating loss of $14.1 million for 2016 compared to $7.1 million for 2015. Included in International land revenues in 2015 is approximately $18.7 million related to early termination of fixed-term contracts.
38
Excluding early termination revenue of $2,566 per day in 2015, the average rig margin per day for 2016 compared to 2015 increased by $468 to $10,406. Low oil prices continued to have a negative effect on customer spending. As a result, we experienced a 26 percent decrease in revenue days when comparing 2016 to 2015. The average number of active rigs was 14.7 during 2016 compared to 20.0 during 2015.
The average rig expense per day decreased $6,210 or 18 percent asfiscal year ended September 30, 2021 compared to the 2015 average rig expense that was impacted by expensesfiscal year ended September 30, 2020 is included in Part II, Item 7— "Management's Discussion and Analysis of Financial Condition and Results of Operations" of ourAnnual Report on rigs that had become idleForm 10-K for the fiscal year ended September 30, 2021, filed with the Securities and other costs associated with rigs transitioning between locations.
DuringExchange Commission ("SEC") on November 18, 2021.
| Liquidity and Capital Resources | ||||||||||||||
Included in direct operating expenses for 2016 is $9.8 million of foreign currency transaction losses, primarily due to a devaluation of the Argentine peso in December 2015.
LIQUIDITY AND CAPITAL RESOURCES
Our capital spending was $397.6 million in 2017, $257.2 million in 2016expenditure projects, paying dividends declared, and $1.1 billion in 2015. Net cash provided from operating activities was $357.2 million in 2017, $753.6 million in 2016 and $1.4 billion in 2015. Our 2018 capital spending is currently estimated to be between $250 million and $300 million. This estimate includes capital maintenance requirements, tubulars and other special projects primarily related to upgradingrepaying our existing rig fleet.
outstanding indebtedness. Historically, we have financed operations primarily through internally generated cash flows. InDuring periods when internally generated cash flows are not sufficient to meet liquidity needs, we will eithermay utilize cash on hand, borrow from available credit sources, access capital markets or we may sell portfolio securities.our investments. Likewise, if we are generating excess cash flows or have cash balances on hand beyond our near-term needs, we may invest in highly rated short‑term money market securities or short‑term marketableand debt securities. Starting in 2015, we began investing in short‑termThese investments classified as trading securities. We have reinvested maturities and earnings during 2017 and 2016. The investmentscan include U.S. Treasury securities, U.S. Agency issued debt securities, highly rated corporate bonds and commercial paper, certificates of deposit and money market funds. The securitiesHowever, in some international locations we may make short-term investments that are all veryless conservative, as equivalent highly rated investments are unavailable. See—Note 2—Summary of Significant Accounting Policies, Risks and recorded at fair value.
Uncertainties—International Solutions Drilling Risks.
2022 FORM 10-K|45| Year Ended September 30, | |||||||||||||||||
| (in thousands) | 2022 | 2021 | 2020 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | $ | 233,913 | $ | 136,440 | $ | 538,881 | |||||||||||
| Investing activities | (167,315) | (161,994) | (87,885) | ||||||||||||||
| Financing activities | (734,305) | 425,523 | (297,220) | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents and restricted cash | $ | (667,707) | $ | 399,969 | $ | 153,776 | |||||||||||
| Year Ended September 30, | |||||||||||||||||
| (in thousands) | 2022 | 2021 | 2020 | ||||||||||||||
| Total current assets | $ | 1,002,944 | $ | 1,586,566 | $ | 963,327 | |||||||||||
| Less: | |||||||||||||||||
| Cash and cash equivalents | 232,131 | 917,534 | 487,884 | ||||||||||||||
| Short-term investments | 117,101 | 198,700 | 89,335 | ||||||||||||||
| Assets held-for-sale | 4,333 | 71,453 | — | ||||||||||||||
| 649,379 | 398,879 | 386,108 | |||||||||||||||
| Total current liabilities | 394,810 | 866,306 | 219,136 | ||||||||||||||
| Less: | |||||||||||||||||
| Dividends payable | 26,693 | 27,332 | 27,226 | ||||||||||||||
| Current portion of long-term debt, net | — | 483,486 | — | ||||||||||||||
| Advance payment for sale of property, plant and equipment | 600 | 86,524 | — | ||||||||||||||
| $ | 367,517 | $ | 268,964 | $ | 191,910 | ||||||||||||
| Operating net working capital (non-GAAP) | $ | 281,862 | $ | 129,915 | $ | 194,198 | |||||||||||
2022 FORM 10-K|46limited number of rigs and plans to reactivate several super-spec rigs.
During 2017, we paid dividends of $2.80 per share, or a total of $305.5 million. During 2016, we paid dividends of $2.763 per share, or a total of $300.2 million. 2021.
shareholders of record on November 15, 2022, payable on December 1, 2022.
2022 FORM 10-K|47We have a $300 millionwas amended on November 13, 2019, providing for an unsecured revolving credit facility which will(as amended, the “2018 Credit Facility”), that was set to mature on JulyNovember 13, 2021.2024. On April 16, 2021, lenders with $680.0 million of commitments under the 2018 Credit Facility exercised their option to extend the maturity of the 2018 Credit Facility from November 13, 2024 to November 12, 2025. No other terms of the 2018 Credit Facility were amended in connection with this extension. Additionally, on March 8, 2022, we entered into the second amendment to the 2018 Credit Facility, which, among other things, raised the number of potential future extensions of the maturity date applicable to extending lenders from one to two such potential extensions and replaced provisions in respect of interest rate determinations that were based on the London Interbank Offered Rate with provisions based on the Secured Overnight Financing Rate. Lenders with $680.0 million of commitments under the 2018 Credit Facility also exercised their option to extend the maturity of the 2018 Credit Facility from November 12, 2025 to November 11, 2026. The credit facilityremaining $70.0 million of commitments under the 2018 Credit Facility will expire on November 13, 2024, unless extended by the applicable lender before such date.
39
capitalization on September 30, 2017, the spread over LIBOR and commitment fees would be 1.125 percent and .15 percent, respectively. There is one financial covenant in the facility which requires us to maintain a funded leverage ratio (as defined) of less than 50 percent. The 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 agreement) may not exceed 17.5% of the net worth of the Company. As of September 30, 2017,2022, there were no borrowings but there were threeor letters of credit outstanding, in the amount of $38.8 million. At September 30, 2017, we had $261.2leaving $750.0 million available to borrow under our $300 million unsecured credit facility. Subsequentthe 2018 Credit Facility. For a full description of the 2018 Credit Facility, see Note 7—Debt to the Consolidated Financial Statements.
Subsequent to September 30, 2017, the Company entered into a $12 million unsecured standalone line of credit facility, which is purposed for the issuance of bid and performance bonds, as needed, for international operations. The Company currently has two bonds issued under this line for a total value of approximately $5.4 million.
Atcovenants and we anticipate that we will continue to be in compliance during the next quarter of fiscal year 2023.
2022 FORM 10-K|482022.
The current ratio was 3.6 If needed, we may decide to obtain additional funding from our $750.0 million 2018 Credit Facility. We currently do not anticipate the need to draw on the 2018 Credit Facility. Our indebtedness under our unsecured senior notes totaled $550.0 million at September 30, 20172022 and 4.8 atmatures on September 30, 2016. The long‑term debt to total capitalization ratio was 10.6 percent at September 30, 2017 compared to 9.7 percent at September 30, 2016.
Stock Portfolio Held
|
|
|
|
|
|
|
|
|
|
|
| Number |
|
|
|
|
|
|
|
September 30, 2017 |
| of Shares |
| Cost Basis |
| Market Value |
| ||
|
| (in thousands, except share amounts) |
| ||||||
Atwood Oceanics, Inc. |
| 4,000,000 |
| $ | 34,760 |
| $ | 37,560 |
|
Schlumberger, Ltd. |
| 467,500 |
|
| 3,713 |
|
| 32,613 |
|
Total |
|
|
| $ | 38,473 |
| $ | 70,173 |
|
Material Commitments
We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations asAs of September 30, 2017, are summarized in2022, we had a $537.7 million deferred tax liability on our Consolidated Balance Sheets, primarily related to temporary differences between the table below in thousands:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Payments due by year |
| |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| After |
| |
Contractual Obligations |
| Total |
| 2018 |
| 2019 |
| 2020 |
| 2021 |
| 2022 |
| 2022 |
| |||||||
Long‑term debt and estimated interest (a) |
| $ | 673,406 |
| $ | 23,250 |
| $ | 23,250 |
| $ | 23,250 |
| $ | 23,250 |
| $ | 23,250 |
| $ | 557,156 |
|
Operating leases (b) |
|
| 29,959 |
|
| 8,015 |
|
| 5,454 |
|
| 3,795 |
|
| 2,944 |
|
| 2,926 |
|
| 6,825 |
|
Purchase obligations (b) |
|
| 56,219 |
|
| 56,219 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total contractual obligations |
| $ | 759,584 |
| $ | 87,484 |
| $ | 28,704 |
| $ | 27,045 |
| $ | 26,194 |
| $ | 26,176 |
| $ | 563,981 |
|
40
|
|
|
|
The above table does not include obligations for our pension plan or amounts recorded for uncertain tax positions.
In 2017 and 2016, we did not make any contributions to the pension plan. Contributions may be made in fiscal 2018 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond fiscal 2018 are difficult to estimate due to multiple variables involved.
At September 30, 2017,2022, we had $7.5$3.9 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The
| Material Commitments | ||||||||||||||
| Obligations due by year | |||||||||||||||||||||||||||||||||||||||||
| (in thousands) | Total | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | ||||||||||||||||||||||||||||||||||
| Long-term debt | 550,000 | — | — | — | — | — | 550,000 | ||||||||||||||||||||||||||||||||||
Interest1 | 144,724 | 16,066 | 16,069 | 16,073 | 16,076 | 16,080 | 64,360 | ||||||||||||||||||||||||||||||||||
Operating leases2 | 31,613 | 9,767 | 7,801 | 4,501 | 2,033 | 2,046 | 5,465 | ||||||||||||||||||||||||||||||||||
Purchase obligations3 | 148,600 | 148,600 | — | ��� | — | — | — | ||||||||||||||||||||||||||||||||||
| Total contractual obligations | $ | 874,937 | $ | 174,433 | $ | 23,870 | $ | 20,574 | $ | 18,109 | $ | 18,126 | $ | 619,825 | |||||||||||||||||||||||||||
| Critical Accounting Policies and Estimates | ||||||||||||||
2022 FORM 10-K|49During
41
Self‑Insurance AccrualsWe self‑insure a significant portion of expected losses relating to worker’sworkers’ compensation, general liability, employer’s liability and automobile liability. Generally, deductibles range from $1 million to $5$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 respondapply or be adequate in all circumstances. Estimates are recorded for incurred outstanding liabilities for worker’sworkers’ 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.
Our wholly‑owned captive insurance company financescompanies finance a significant portion of the physical damage risk on company‑owned drilling rigs as well as international casualty deductibles. WithAn actuary reviews the exception of “named wind storm” risk inloss reserves retained by the Gulf of Mexico, we insure rigs and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self‑insure a number of other risks including loss of earnings and business interruption, and most cyber risks.
Pension Costs and Obligations Our pension benefit costs and obligations are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan assets. Our discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was increased to 3.79 percent from 3.64 percent as of September 30, 2017 to reflect changes in the market conditions for high‑quality fixed‑income investments. The expected return on plan assets is determined based on historical portfolio results and future expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated from future periods. We anticipate pension expense to decrease by approximately $3.1 million in 2018 from 2017.
Stock‑Based Compensation Historically, we have granted stock‑based awards to key employees and non‑employee directors as part of their compensation. We estimate the fair value of all stock option awards as of the date of grant by applying the Black‑Scholes option‑pricing model. The application of this valuation model involves assumptions, some of which are judgmental and highly sensitive. These assumptions include, among others, the expected stock price volatility, the expected life of the stock optionsCompany and the risk‑free interest rate. Expected volatilities were estimated using the historical volatilitycaptives on an annual basis.
2022 FORM 10-K|50The fair value of restricted stock awards is determined based on the closing price of our common stock on the date of grant. We amortize the fair value of restricted stock awards to compensation expense on a straight‑line basis over the vesting period. At September 30, 2017, unrecognized compensation cost related to unvested restricted stock was $21.4 million. The cost is expected to be recognized over a weighted‑average period of 2.2 years.
Revenue Recognition Contract drilling revenues areprimarily comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certainWith most drilling contracts, we receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenue associated with the mobilization and demobilization of our drilling equipment. Mobilization payments received,rigs to and directfrom 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. 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. Direct costs incurred for the mobilization, are deferred and recognized overon a straight-line basis as the term of the related drilling contract. Costsservice is provided. While 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
42
NEW ACCOUNTING STANDARDS
| New Accounting Standards | ||||||||||||||
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Foreign Currency Exchange Rate Risk Our contracts for work
| Non-GAAP Measurements | ||||||||||||||
Estimates from published sources indicate that Argentina is a highly inflationary country, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three‑year period based on inflation data published by the respective governments. Regardless, all of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations.
Commodity Price Risk The demand for contract drilling services is derived from exploration and production companies spending money to explore and develop drilling prospects in search of crude oil and natural gas. Their spending is driven by their cash flow and financial strength, which is affected by trends in crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including global supply and demand, the establishment of and compliance with production quotas by oil exporting countries, worldwide economic conditions and geopolitical factors. Crude oil and natural gas prices have historically been volatile and very difficult to predict with any degree of certainty. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining future spending levels. This volatility can lead many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling servicesmaking comparisons over time. Direct margin is not always purely a function of the movement of commodity prices.
Creditsubstitute for financial measures prepared in accordance with GAAP 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,should therefore be considered only as experienced in the past, can make it difficult for customerssupplemental 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 drilling services which could have a material adverse effect on our business,such GAAP 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
43
2022 FORM 10-K|51will 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 borrowings from our commercial banks. Because all of our debt at September 30, 2017 has fixed‑rate interest obligations, there is no current risk due to interest rate fluctuation.
The following tables provide information as of September 30, 2017table reconciles direct margin to segment operating income (loss), which we believe is the financial measure calculated and 2016 about our interest rate risk sensitive instruments:
INTEREST RATE RISK AS OF SEPTEMBER 30, 2017 (dollarspresented in thousands)
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| 9/30/2017 |
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Fixed‑Rate Debt |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 500,000 |
| $ | 500,000 |
| $ | 528,960 |
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Average Interest Rate |
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| — | % |
| — | % |
| — | % |
| — | % |
| — | % |
| 4.65 | % |
| 4.65 | % |
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Variable Rate Debt |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
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Average Interest Rate |
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INTEREST RATE RISK AS OF SEPTEMBER 30, 2016 (dollars in thousands)
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| 2017 |
| 2018 |
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| Total |
| 9/30/2016 |
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Fixed‑Rate Debt |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 500,000 |
| $ | 500,000 |
| $ | 529,550 |
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Average Interest Rate |
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| — | % |
| — | % |
| — | % |
| — | % |
| — | % |
| 4.65 | % |
| 4.65 | % |
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Variable Rate Debt |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
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Average Interest Rate |
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Equity Price Risk On September 30, 2017, we had a portfolio of securitiesaccordance with a total fair value of $70.2 million. The total fair value of the portfolio of securities was $71.5 million at September 30, 2016. A hypothetical 10% decrease in the market prices for all securities in our portfolio as of September 30, 2017 would decrease the fair value of our available‑for‑sale securities by $7.2 million. We make no specific plansGAAP that is most directly comparable to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market‑related risks that could substantially reduce or increase the fair value of our holdings. The portfolio is recorded at fair value on the balance sheet with changes in unrealized after‑tax value reflected in the equity section of the balance sheet unless a decline in fair value below our cost basis is considered to be other than temporary in which case the change is recorded through earnings. Subsequent to September 30, 2017, the Atwood shares were converted to Ensco shares under a merger agreement whereby we received 1.60 shares of Ensco plc for each share of our Atwood common stock. At November 16, 2017, the total fair value of our securities had decreased to approximately $63.2 million. Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements.
44
| Year Ended September 30, 2022 | |||||||||||||||||
| (in thousands) | North America Solutions | Offshore Gulf of Mexico | International Solutions | ||||||||||||||
| Segment operating income (loss) | $ | 121,893 | $ | 23,214 | $ | (138) | |||||||||||
| Add back: | |||||||||||||||||
| Depreciation and amortization | 375,250 | 9,175 | 4,156 | ||||||||||||||
| Research and development | 26,728 | — | — | ||||||||||||||
| Selling, general and administrative expense | 43,796 | 2,661 | 8,779 | ||||||||||||||
| Asset impairment charges | 1,868 | — | 2,495 | ||||||||||||||
| Restructuring charges | 498 | — | — | ||||||||||||||
| Direct margin (Non-GAAP) | $ | 570,033 | $ | 35,050 | $ | 15,292 | |||||||||||
| Year Ended September 30, 2021 | |||||||||||||||||
| (in thousands) | North America Solutions | Offshore Gulf of Mexico | International Solutions | ||||||||||||||
| Segment operating income (loss) | $ | (287,176) | $ | 15,969 | $ | (21,003) | |||||||||||
| Add back: | |||||||||||||||||
| Depreciation and amortization | 392,415 | 10,557 | 2,013 | ||||||||||||||
| Research and development | 21,811 | — | — | ||||||||||||||
| Selling, general and administrative expense | 51,089 | 2,624 | 8,028 | ||||||||||||||
| Asset impairment charges | 70,850 | — | — | ||||||||||||||
| Restructuring charges | 3,868 | — | 207 | ||||||||||||||
| Direct margin (Non-GAAP) | $ | 252,857 | $ | 29,150 | $ | (10,755) | |||||||||||
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information required
| ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | ||||||||||||||
45
2022 FORM 10-K|522022 FORM 10-K|53Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
| ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | ||||||||||||||
| |||||
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS |  | ||||
| PAGE | |||||
| |||||
| Consolidated Financial Statements: | |||||
Consolidated Balance Sheets at September 30, 2022 and 2021 | |||||
Consolidated Statements of Operations for the Years Ended September 30, |
| ||||
Consolidated Statements of Comprehensive Income |
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Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, |
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Consolidated Statements of Cash Flows for the Years Ended September 30, |
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46
2022 FORM 10-K|54Management’s Report on Internal Control over Financial Reporting
| 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 16, 2022 | November 16, 2022 | |||||||
2022 FORM 10-K|55| Report of Independent Registered Public Accounting Firm | ||||||||||||||
| Self-Insurance Accruals | |||||
Description of the Matter | The Company's self-insurance liability for workers’ compensation and other casualty claims was $72.3 million at September 30, 2022. As described in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties 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. | ||||
2022 FORM 10-K|56How 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, including management’s review controls over the significant assumptions used in the calculation and the completeness and accuracy of the data underlying the reserve. To test 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 estimates to ranges of estimates independently developed by our actuarial specialists. | ||||
| /s/ Ernst & Young LLP | ||||||||
| We have served as the Company’s auditor since 1994. | ||||||||
| Tulsa, Oklahoma | ||||||||
| November 16, 2022 | ||||||||
2022 FORM 10-K|57| Report of Independent Registered Public Accounting Firm | ||||||||||||||
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.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helmerich & Payne, Inc.’sInternal Control Over Financial Reporting
| /s/Ernst & Young LLP | ||||||||
| Tulsa, Oklahoma | ||||||||
| November 16, 2022 | ||||||||
Tulsa, Oklahoma
November 22, 2017
47
2022 FORM 10-K|58Consolidated Statements of Operations
HELMERICH & PAYNE, INC.
| HELMERICH & PAYNE, INC. | |||||||||||
| CONSOLIDATED BALANCE SHEETS | |||||||||||
| September 30, | |||||||||||
| (in thousands except share data and per share amounts) | 2022 | 2021 | |||||||||
| ASSETS | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 232,131 | $ | 917,534 | |||||||
| Restricted cash | 36,246 | 18,350 | |||||||||
| Short-term investments | 117,101 | 198,700 | |||||||||
| Accounts receivable, net of allowance of $2,975 and $2,068, respectively | 458,713 | 228,894 | |||||||||
| Inventories of materials and supplies, net | 87,957 | 84,057 | |||||||||
| Prepaid expenses and other, net | 66,463 | 67,578 | |||||||||
| Assets held-for-sale | 4,333 | 71,453 | |||||||||
| Total current assets | 1,002,944 | 1,586,566 | |||||||||
| Investments | 218,981 | 135,444 | |||||||||
| Property, plant and equipment, net | 2,960,809 | 3,127,287 | |||||||||
| Other Noncurrent Assets: | |||||||||||
| Goodwill | 45,653 | 45,653 | |||||||||
| Intangible assets, net | 67,154 | 73,838 | |||||||||
| Operating lease right-of-use assets | 39,064 | 49,187 | |||||||||
| Other assets, net | 20,926 | 16,153 | |||||||||
| Total other noncurrent assets | 172,797 | 184,831 | |||||||||
| Total assets | $ | 4,355,531 | $ | 5,034,128 | |||||||
| LIABILITIES & SHAREHOLDERS' EQUITY | |||||||||||
| Current Liabilities: | |||||||||||
| Accounts payable | $ | 126,966 | $ | 71,996 | |||||||
| Dividends payable | 26,693 | 27,332 | |||||||||
| Current portion of long-term debt, net | — | 483,486 | |||||||||
| Accrued liabilities | 241,151 | 283,492 | |||||||||
| Total current liabilities | 394,810 | 866,306 | |||||||||
| Noncurrent Liabilities: | |||||||||||
| Long-term debt, net | 542,610 | 541,997 | |||||||||
| Deferred income taxes | 537,712 | 563,437 | |||||||||
| Other | 113,387 | 147,757 | |||||||||
| Noncurrent liabilities - discontinued operations | 1,540 | 2,013 | |||||||||
| Total noncurrent liabilities | 1,195,249 | 1,255,204 | |||||||||
| Commitments and Contingencies (Note 16) | |||||||||||
| Shareholders' Equity: | |||||||||||
| Common stock, $0.10 par value, 160,000,000 shares authorized, 112,222,865 shares issued as of September 30, 2022 and 2021, and 105,293,662 and 107,898,859 shares outstanding as of September 30, 2022 and 2021, respectively | 11,222 | 11,222 | |||||||||
| Preferred stock, no par value, 1,000,000 shares authorized, no shares issued | — | — | |||||||||
| Additional paid-in capital | 528,278 | 529,903 | |||||||||
| Retained earnings | 2,473,572 | 2,573,375 | |||||||||
| Accumulated other comprehensive loss | (12,072) | (20,244) | |||||||||
| Treasury stock, at cost, 6,929,203 shares and 4,324,006 shares as of September 30, 2022 and 2021, respectively | (235,528) | (181,638) | |||||||||
| Total shareholders’ equity | 2,765,472 | 2,912,618 | |||||||||
| Total liabilities and shareholders' equity | $ | 4,355,531 | $ | 5,034,128 | |||||||
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| Year Ended September 30, |
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| 2017 |
| 2016 |
| 2015 |
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| (in thousands, except per share amounts) |
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Operating revenues |
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Drilling - U.S. Land |
| $ | 1,439,523 |
| $ | 1,242,462 |
| $ | 2,523,518 |
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Drilling - Offshore |
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| 136,263 |
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| 138,601 |
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| 241,666 |
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Drilling - International Land |
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| 212,972 |
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| 229,894 |
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| 382,331 |
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Other |
|
| 15,983 |
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| 13,275 |
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| 14,187 |
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| 1,804,741 |
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| 1,624,232 |
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| 3,161,702 |
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Operating costs and expenses |
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Operating costs, excluding depreciation and amortization |
|
| 1,249,317 |
|
| 898,805 |
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| 1,703,476 |
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Depreciation and amortization |
|
| 585,543 |
|
| 598,587 |
|
| 608,039 |
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Asset impairment charge |
|
| — |
|
| 6,250 |
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| 39,242 |
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Research and development |
|
| 12,047 |
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| 10,269 |
|
| 16,104 |
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General and administrative |
|
| 151,002 |
|
| 146,183 |
|
| 134,712 |
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Income from asset sales |
|
| (20,627) |
|
| (9,896) |
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| (11,834) |
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| 1,977,282 |
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| 1,650,198 |
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| 2,489,739 |
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Operating income (loss) from continuing operations |
|
| (172,541) |
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| (25,966) |
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| 671,963 |
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Other income (expense) |
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Interest and dividend income |
|
| 5,915 |
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| 3,166 |
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| 5,840 |
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Interest expense |
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| (19,747) |
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| (22,913) |
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| (15,023) |
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Loss on investment securities |
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| — |
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| (25,989) |
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| — |
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Other |
|
| 1,775 |
|
| (965) |
|
| (901) |
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|
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| (12,057) |
|
| (46,701) |
|
| (10,084) |
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Income (loss) from continuing operations before income taxes |
|
| (184,598) |
|
| (72,667) |
|
| 661,879 |
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Income tax provision (benefit) |
|
| (56,735) |
|
| (19,677) |
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| 241,405 |
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Income (loss) from continuing operations |
|
| (127,863) |
|
| (52,990) |
|
| 420,474 |
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Income (loss) from discontinued operations before income taxes |
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| 3,285 |
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| 2,360 |
|
| (124) |
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Income tax provision (benefit) |
|
| 3,634 |
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| 6,198 |
|
| (77) |
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Loss from discontinued operations |
|
| (349) |
|
| (3,838) |
|
| (47) |
|
NET INCOME (LOSS) |
| $ | (128,212) |
| $ | (56,828) |
| $ | 420,427 |
|
Basic earnings per common share: |
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Income (loss) from continuing operations |
| $ | (1.20) |
| $ | (0.50) |
| $ | 3.88 |
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Loss from discontinued operations |
| $ | — |
| $ | (0.04) |
| $ | — |
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Net income (loss) |
| $ | (1.20) |
| $ | (0.54) |
| $ | 3.88 |
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Diluted earnings per common share: |
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|
Income (loss) from continuing operations |
| $ | (1.20) |
| $ | (0.50) |
| $ | 3.85 |
|
Loss from discontinued operations |
| $ | — |
| $ | (0.04) |
| $ | — |
|
Net income (loss) |
| $ | (1.20) |
| $ | (0.54) |
| $ | 3.85 |
|
Weighted average shares outstanding (in thousands): |
|
|
|
|
|
|
|
|
|
|
Basic |
|
| 108,500 |
|
| 107,996 |
|
| 107,754 |
|
Diluted |
|
| 108,500 |
|
| 107,996 |
|
| 108,570 |
|
The accompanying notes are an integral part of these consolidated financial statements.
48
2022 FORM 10-K|59
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended September 30, |
| |||||||
|
| 2017 |
| 2016 |
| 2015 |
| |||
|
| (in thousands) |
| |||||||
Net income (loss) |
| $ | (128,212) |
| $ | (56,828) |
| $ | 420,427 |
|
Other comprehensive income (loss), net of income taxes: |
|
|
|
|
|
|
|
|
|
|
Unrealized appreciation (depreciation) on securities, net of income taxes of ($0.5) million at September 30, 2017, $1.7 million at September 30, 2016 and ($50.6) million at September 30, 2015 |
|
| (829) |
|
| 2,772 |
|
| (80,217) |
|
Reclassification of realized losses in net income, net of income taxes of $0.6 million at September 30, 2016 |
|
| — |
|
| 926 |
|
| — |
|
Minimum pension liability adjustments, net of income taxes of $1.9 million at September 30, 2017, ($1.4) million at September 30, 2016 and ($2.5) million at September 30, 2015 |
|
| 3,333 |
|
| (2,525) |
|
| (4,286) |
|
Other comprehensive income (loss) |
|
| 2,504 |
|
| 1,173 |
|
| (84,503) |
|
Comprehensive income (loss) |
| $ | (125,708) |
| $ | (55,655) |
| $ | 335,924 |
|
| HELMERICH & PAYNE, INC. | |||||||||||||||||
| CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||||
| Year Ended September 30, | |||||||||||||||||
| (in thousands, except per share amounts) | 2022 | 2021 | 2020 | ||||||||||||||
| OPERATING REVENUES | |||||||||||||||||
| Drilling services | $ | 2,049,841 | $ | 1,210,800 | $ | 1,761,714 | |||||||||||
| Other | 9,103 | 7,768 | 12,213 | ||||||||||||||
| 2,058,944 | 1,218,568 | 1,773,927 | |||||||||||||||
| OPERATING COSTS AND EXPENSES | |||||||||||||||||
| Drilling services operating expenses, excluding depreciation and amortization | 1,426,589 | 952,600 | 1,184,788 | ||||||||||||||
| Other operating expenses | 4,638 | 5,138 | 5,777 | ||||||||||||||
| Depreciation and amortization | 403,170 | 419,726 | 481,885 | ||||||||||||||
| Research and development | 26,563 | 21,724 | 21,645 | ||||||||||||||
| Selling, general and administrative | 182,366 | 172,195 | 167,513 | ||||||||||||||
| Asset impairment charges | 4,363 | 70,850 | 563,234 | ||||||||||||||
| Restructuring charges | 838 | 5,926 | 16,047 | ||||||||||||||
| Gain on reimbursement of drilling equipment | (29,443) | (12,322) | (26,959) | ||||||||||||||
| Other (gain) loss on sale of assets | (5,432) | 11,280 | (19,816) | ||||||||||||||
| 2,013,652 | 1,647,117 | 2,394,114 | |||||||||||||||
| OPERATING INCOME (LOSS) FROM CONTINUING OPERATIONS | 45,292 | (428,549) | (620,187) | ||||||||||||||
| Other income (expense) | |||||||||||||||||
| Interest and dividend income | 18,090 | 10,254 | 7,304 | ||||||||||||||
| Interest expense | (19,203) | (23,955) | (24,474) | ||||||||||||||
| Gain (loss) on investment securities | 57,937 | 6,727 | (8,720) | ||||||||||||||
| Gain on sale of subsidiary | — | — | 14,963 | ||||||||||||||
| Loss on extinguishment of debt | (60,083) | — | — | ||||||||||||||
| Other | (11,115) | (5,657) | (5,384) | ||||||||||||||
| (14,374) | (12,631) | (16,311) | |||||||||||||||
| Income (loss) from continuing operations before income taxes | 30,918 | (441,180) | (636,498) | ||||||||||||||
| Income tax expense (benefit) | 24,366 | (103,721) | (140,106) | ||||||||||||||
| Income (loss) from continuing operations | 6,552 | (337,459) | (496,392) | ||||||||||||||
| Income from discontinued operations before income taxes | 401 | 11,309 | 30,580 | ||||||||||||||
| Income tax provision | — | — | 28,685 | ||||||||||||||
| Income from discontinued operations | 401 | 11,309 | 1,895 | ||||||||||||||
| NET INCOME (LOSS) | $ | 6,953 | $ | (326,150) | $ | (494,497) | |||||||||||
| Basic earnings (loss) per common share: | |||||||||||||||||
| Income (loss) from continuing operations | $ | 0.05 | $ | (3.14) | $ | (4.62) | |||||||||||
| Income from discontinued operations | — | 0.10 | 0.02 | ||||||||||||||
| Net income (loss) | $ | 0.05 | $ | (3.04) | $ | (4.60) | |||||||||||
| Diluted earnings (loss) per common share: | |||||||||||||||||
| Income (loss) from continuing operations | $ | 0.05 | $ | (3.14) | $ | (4.62) | |||||||||||
| Income from discontinued operations | — | 0.10 | 0.02 | ||||||||||||||
| Net income (loss) | $ | 0.05 | $ | (3.04) | $ | (4.60) | |||||||||||
| Weighted average shares outstanding: | |||||||||||||||||
| Basic | 105,891 | 107,818 | 108,009 | ||||||||||||||
| Diluted | 106,555 | 107,818 | 108,009 | ||||||||||||||
49
2022 FORM 10-K|60
|
|
|
|
|
|
|
|
|
| September 30, |
| ||||
|
| 2017 |
| 2016 |
| ||
|
| (in thousands) |
| ||||
Assets |
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 521,375 |
| $ | 905,561 |
|
Short-term investments |
|
| 44,491 |
|
| 44,148 |
|
Accounts receivable, less reserve of $5,721 in 2017 and $2,696 in 2016 |
|
| 477,074 |
|
| 375,169 |
|
Inventories |
|
| 137,204 |
|
| 124,325 |
|
Prepaid expenses and other |
|
| 55,120 |
|
| 78,067 |
|
Assets held for sale |
|
| — |
|
| 45,352 |
|
Current assets of discontinued operations |
|
| 3 |
|
| 64 |
|
Total current assets |
|
| 1,235,267 |
|
| 1,572,686 |
|
INVESTMENTS |
|
| 84,026 |
|
| 84,955 |
|
PROPERTY, PLANT AND EQUIPMENT, at cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling equipment |
|
| 8,197,572 |
|
| 7,881,544 |
|
Construction in progress |
|
| 169,326 |
|
| 98,313 |
|
Real estate properties |
|
| 66,005 |
|
| 62,929 |
|
Other |
|
| 450,031 |
|
| 444,843 |
|
|
|
| 8,882,934 |
|
| 8,487,629 |
|
Less-Accumulated depreciation |
|
| 3,881,883 |
|
| 3,342,896 |
|
Net property, plant and equipment |
|
| 5,001,051 |
|
| 5,144,733 |
|
NONCURRENT ASSETS: |
|
|
|
|
|
|
|
Goodwill |
|
| 51,705 |
|
| 4,718 |
|
Intangible assets, net of amortization |
|
| 50,785 |
|
| 919 |
|
Other assets |
|
| 17,154 |
|
| 24,008 |
|
Total noncurrent assets |
|
| 119,644 |
|
| 29,645 |
|
|
|
|
|
|
|
|
|
TOTAL ASSETS |
| $ | 6,439,988 |
| $ | 6,832,019 |
|
| HELMERICH & PAYNE, INC. | |||||||||||||||||
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | |||||||||||||||||
| Year ended September 30, | |||||||||||||||||
| (in thousands) | 2022 | 2021 | 2020 | ||||||||||||||
| Net income (loss) | $ | 6,953 | $ | (326,150) | $ | (494,497) | |||||||||||
| Other comprehensive income, net of income taxes: | |||||||||||||||||
| Net change related to employee benefit plans, net of income taxes of $2.3 million at September 30, 2022, $1.8 million at September 30, 2021 and $0.8 million at September 30, 2020 | 8,172 | 5,944 | 2,447 | ||||||||||||||
| Other comprehensive income | 8,172 | 5,944 | 2,447 | ||||||||||||||
| Comprehensive income (loss) | $ | 15,125 | $ | (320,206) | $ | (492,050) | |||||||||||
50
2022 FORM 10-K|61Consolidated Balance Sheets (Continued)
HELMERICH & PAYNE, INC.
|
|
|
|
|
|
|
|
|
| September 30, |
| ||||
|
| 2017 |
| 2016 |
| ||
|
| (in thousands, except share |
| ||||
|
| data and per share amounts) |
| ||||
Liabilities and Shareholders’ Equity |
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
Accounts payable |
| $ | 135,628 |
| $ | 95,422 |
|
Accrued liabilities |
|
| 208,683 |
|
| 234,639 |
|
Current liabilities of discontinued operations |
|
| 74 |
|
| 59 |
|
Total current liabilities |
|
| 344,385 |
|
| 330,120 |
|
NONCURRENT LIABILITIES: |
|
|
|
|
|
|
|
Long-term debt |
|
| 492,902 |
|
| 491,847 |
|
Deferred income taxes |
|
| 1,332,689 |
|
| 1,342,456 |
|
Other |
|
| 101,409 |
|
| 102,781 |
|
Noncurrent liabilities of discontinued operations |
|
| 4,012 |
|
| 3,890 |
|
Total noncurrent liabilities |
|
| 1,931,012 |
|
| 1,940,974 |
|
SHAREHOLDERS’ EQUITY: |
|
|
|
|
|
|
|
Common stock, $.10 par value, 160,000,000 shares authorized, 111,956,875 and 111,400,339 shares issued as of September 30, 2017 and 2016, respectively, and 108,604,047 and 108,077,916 shares outstanding as of September 30, 2017 and 2016, respectively |
|
| 11,196 |
|
| 11,140 |
|
Preferred stock, no par value, 1,000,000 shares authorized, no shares issued |
|
| — |
|
| — |
|
Additional paid-in capital |
|
| 487,248 |
|
| 448,452 |
|
Retained earnings |
|
| 3,855,686 |
|
| 4,289,807 |
|
Accumulated other comprehensive income (loss) |
|
| 2,300 |
|
| (204) |
|
|
|
| 4,356,430 |
|
| 4,749,195 |
|
Less treasury stock, 3,352,828 shares in 2017 and 3,322,423 shares in 2016, at cost |
|
| (191,839) |
|
| (188,270) |
|
Total shareholders’ equity |
|
| 4,164,591 |
|
| 4,560,925 |
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY |
| $ | 6,439,988 |
| $ | 6,832,019 |
|
| HELMERICH & PAYNE, INC. | |||||||||||||||||||||||||||||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY | |||||||||||||||||||||||||||||||||||||||||||||||
| Common Stock | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Treasury Stock | |||||||||||||||||||||||||||||||||||||||||||
| (in thousands, except per share amounts) | Shares | Amount | Shares | Amount | Total | ||||||||||||||||||||||||||||||||||||||||||
| 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 | — | — | — | (494,497) | — | — | — | (494,497) | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 2,447 | — | — | 2,447 | |||||||||||||||||||||||||||||||||||||||
| Dividends declared ($1.92 per share) | — | — | — | (209,798) | — | — | — | (209,798) | |||||||||||||||||||||||||||||||||||||||
| Exercise of employee stock options, net of shares withheld for employee taxes | — | — | (3,151) | — | — | (110) | 7,195 | 4,044 | |||||||||||||||||||||||||||||||||||||||
| Vesting of restricted stock awards, net of shares withheld for employee taxes | 71 | 7 | (21,855) | — | — | (329) | 18,119 | (3,729) | |||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 36,329 | — | — | — | — | 36,329 | |||||||||||||||||||||||||||||||||||||||
| Share repurchases | — | — | — | — | — | 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 | |||||||||||||||||||||||||||||||||
| Comprehensive income (loss): | |||||||||||||||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | (326,150) | — | — | — | (326,150) | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 5,944 | — | — | 5,944 | |||||||||||||||||||||||||||||||||||||||
| Dividends declared ($1.00 per share) | — | — | — | (109,236) | — | — | — | (109,236) | |||||||||||||||||||||||||||||||||||||||
| Vesting of restricted stock awards, net of shares withheld for employee taxes | 71 | 7 | (18,683) | — | — | (339) | 16,515 | (2,161) | |||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 27,858 | — | — | — | — | 27,858 | |||||||||||||||||||||||||||||||||||||||
| Cumulative effect adjustment for adoption of ASU No. 2016-13 | — | — | — | (1,251) | — | — | — | (1,251) | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | (900) | — | — | — | — | (900) | |||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2021 | 112,222 | $ | 11,222 | $ | 529,903 | $ | 2,573,375 | $ | (20,244) | 4,324 | $ | (181,638) | $ | 2,912,618 | |||||||||||||||||||||||||||||||||
| Comprehensive income: | |||||||||||||||||||||||||||||||||||||||||||||||
| Net Income | — | — | — | 6,953 | — | — | — | 6,953 | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 8,172 | — | — | 8,172 | |||||||||||||||||||||||||||||||||||||||
| Dividends declared ($1.00 per share) | — | — | — | (106,756) | — | — | — | (106,756) | |||||||||||||||||||||||||||||||||||||||
| Vesting of restricted stock awards, net of shares withheld for employee taxes | — | — | (28,608) | — | — | (550) | 23,109 | (5,499) | |||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 28,032 | — | — | — | — | 28,032 | |||||||||||||||||||||||||||||||||||||||
| Share repurchases | — | — | — | — | — | 3,155 | (76,999) | (76,999) | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | (1,049) | — | — | — | (1,049) | ||||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2022 | 112,222 | $ | 11,222 | $ | 528,278 | $ | 2,473,572 | $ | (12,072) | 6,929 | $ | (235,528) | $ | 2,765,472 | |||||||||||||||||||||||||||||||||
51
2022 FORM 10-K|62Consolidated Statements of Shareholders’ Equity
HELMERICH & PAYNE, INC.
| HELMERICH & PAYNE, INC. | |||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||||||||
| Year Ended September 30, | |||||||||||||||||
| (in thousands) | 2022 | 2021 | 2020 | ||||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||||||||||||
| Net income (loss) | $ | 6,953 | $ | (326,150) | $ | (494,497) | |||||||||||
| Adjustment for income from discontinued operations | (401) | (11,309) | (1,895) | ||||||||||||||
| Income (loss) from continuing operations | 6,552 | (337,459) | (496,392) | ||||||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization | 403,170 | 419,726 | 481,885 | ||||||||||||||
| Asset impairment charges | 4,363 | 70,850 | 563,234 | ||||||||||||||
| Amortization of debt discount and debt issuance costs | 1,200 | 1,423 | 1,817 | ||||||||||||||
| Loss on extinguishment of debt | 60,083 | — | — | ||||||||||||||
| Provision for credit loss | 1,081 | 203 | 2,203 | ||||||||||||||
| Stock-based compensation | 28,032 | 27,858 | 36,329 | ||||||||||||||
| Loss (gain) on investment securities | (57,937) | (6,727) | 8,720 | ||||||||||||||
| Gain on reimbursement of drilling equipment | (29,443) | (12,322) | (26,959) | ||||||||||||||
| Other (gain) loss on sale of assets | (5,432) | 11,280 | (19,816) | ||||||||||||||
| Gain on sale of subsidiary | — | — | (14,963) | ||||||||||||||
| Deferred income tax benefit | (28,488) | (89,752) | (157,555) | ||||||||||||||
| Other | 6,533 | 13,794 | (2,423) | ||||||||||||||
| Change in assets and liabilities: | |||||||||||||||||
| Accounts receivable | (235,562) | (28,416) | 300,807 | ||||||||||||||
| Inventories of materials and supplies | (5,228) | 19,847 | 9,420 | ||||||||||||||
| Prepaid expenses and other | 6,224 | (21,400) | (5,506) | ||||||||||||||
| Other noncurrent assets | 2,581 | 2,772 | 2,820 | ||||||||||||||
| Accounts payable | 53,242 | 31,027 | (9,414) | ||||||||||||||
| Accrued liabilities | 45,069 | 33,957 | (138,414) | ||||||||||||||
| Deferred income tax liability | 447 | 1,101 | 908 | ||||||||||||||
| Other noncurrent liabilities | (22,501) | (1,274) | 2,227 | ||||||||||||||
| Net cash provided by operating activities from continuing operations | 233,986 | 136,488 | 538,928 | ||||||||||||||
| Net cash used in operating activities from discontinued operations | (73) | (48) | (47) | ||||||||||||||
| Net cash provided by operating activities | 233,913 | 136,440 | 538,881 | ||||||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||
| Capital expenditures | (250,894) | (82,148) | (140,795) | ||||||||||||||
| Other capital expenditures related to assets held-for-sale | (21,645) | — | — | ||||||||||||||
| Purchase of short-term investments | (165,109) | (315,078) | (134,641) | ||||||||||||||
| Purchase of long-term investments | (51,241) | (102,523) | (550) | ||||||||||||||
| Proceeds from sale of short-term investments | 244,728 | 207,716 | 94,646 | ||||||||||||||
| Proceeds from sale of long-term investments | 22,042 | — | — | ||||||||||||||
| Proceeds from sale of subsidiary | — | — | 15,056 | ||||||||||||||
| Proceeds from asset sales | 62,304 | 43,515 | 78,399 | ||||||||||||||
| Advance payment for sale of property, plant and equipment | — | 86,524 | — | ||||||||||||||
| Other | (7,500) | — | — | ||||||||||||||
| Net cash used in investing activities | (167,315) | (161,994) | (87,885) | ||||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||
| Dividends paid | (107,395) | (109,130) | (260,335) | ||||||||||||||
| Proceeds from debt issuance | — | 548,719 | — | ||||||||||||||
| Debt issuance costs | — | (3,935) | — | ||||||||||||||
| Proceeds from stock option exercises | — | — | 4,100 | ||||||||||||||
| Payments for employee taxes on net settlement of equity awards | (5,505) | (2,162) | (3,784) | ||||||||||||||
| Payment of contingent consideration from acquisition of business | (250) | (7,250) | (8,250) | ||||||||||||||
| Payments for early extinguishment of long-term debt | (487,148) | — | — | ||||||||||||||
| Make-whole premium payment | (56,421) | — | — | ||||||||||||||
| Share repurchases | (76,999) | — | (28,505) | ||||||||||||||
| Other | (587) | (719) | (446) | ||||||||||||||
| Net cash provided by (used in) financing activities | (734,305) | 425,523 | (297,220) | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents and restricted cash | (667,707) | 399,969 | 153,776 | ||||||||||||||
| Cash and cash equivalents and restricted cash, beginning of period | 936,716 | 536,747 | 382,971 | ||||||||||||||
| Cash and cash equivalents and restricted cash, end of period | $ | 269,009 | $ | 936,716 | $ | 536,747 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
| Additional |
|
|
|
| Other |
|
|
|
|
|
|
|
|
| ||
|
| Common Stock |
| Paid-In |
| Retained |
| Comprehensive |
| Treasury Stock |
|
|
|
| |||||||||
|
| Shares |
| Amount |
| Capital |
| Earnings |
| Loss |
| Shares |
| Amount |
| Total |
| ||||||
|
| (in thousands, except per share amounts) |
| ||||||||||||||||||||
Balance, September 30, 2014 |
| 110,509 |
| $ | 11,051 |
| $ | 383,972 |
| $ | 4,525,989 |
| $ | 83,126 |
| 2,276 |
| $ | (112,969) |
| $ | 4,891,169 |
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
| 420,427 |
|
|
|
|
|
|
|
|
|
| 420,427 |
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
| (84,503) |
|
|
|
|
|
|
| (84,503) |
|
Dividends declared ($2.75 per share) |
|
|
|
|
|
|
|
|
|
| (298,070) |
|
|
|
|
|
|
|
|
|
| (298,070) |
|
Exercise of stock options |
| 255 |
|
| 26 |
|
| 7,223 |
|
|
|
|
|
|
| 64 |
|
| (4,599) |
|
| 2,650 |
|
Tax benefit of stock-based awards |
|
|
|
|
|
|
| 3,772 |
|
|
|
|
|
|
|
|
|
|
|
|
| 3,772 |
|
Stock issued for vested restricted stock, net of shares withheld for employee taxes |
| 223 |
|
| 22 |
|
| (21) |
|
|
|
|
|
|
| 70 |
|
| (5,141) |
|
| (5,140) |
|
Repurchase of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 810 |
|
| (59,654) |
|
| (59,654) |
|
Stock-based compensation |
|
|
|
|
|
|
| 25,195 |
|
|
|
|
|
|
|
|
|
|
|
|
| 25,195 |
|
Balance, September 30, 2015 |
| 110,987 |
|
| 11,099 |
|
| 420,141 |
|
| 4,648,346 |
|
| (1,377) |
| 3,220 |
|
| (182,363) |
|
| 4,895,846 |
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
| (56,828) |
|
|
|
|
|
|
|
|
|
| (56,828) |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
| 1,173 |
|
|
|
|
|
|
| 1,173 |
|
Dividends declared ($2.775 per share) |
|
|
|
|
|
|
|
|
|
| (301,711) |
|
|
|
|
|
|
|
|
|
| (301,711) |
|
Exercise of stock options |
| 220 |
|
| 22 |
|
| 6,937 |
|
|
|
|
|
|
| 99 |
|
| (5,919) |
|
| 1,040 |
|
Tax benefit of stock-based awards |
|
|
|
|
|
|
| 934 |
|
|
|
|
|
|
|
|
|
|
|
|
| 934 |
|
Stock issued for vested restricted stock, net of shares withheld for employee taxes |
| 193 |
|
| 19 |
|
| (3,943) |
|
|
|
|
|
|
| 3 |
|
| 12 |
|
| (3,912) |
|
Stock-based compensation |
|
|
|
|
|
|
| 24,383 |
|
|
|
|
|
|
|
|
|
|
|
|
| 24,383 |
|
Balance, September 30, 2016 |
| 111,400 |
|
| 11,140 |
|
| 448,452 |
|
| 4,289,807 |
|
| (204) |
| 3,322 |
|
| (188,270) |
|
| 4,560,925 |
|
Comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
| (128,212) |
|
|
|
|
|
|
|
|
|
| (128,212) |
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
| 2,504 |
|
|
|
|
|
|
| 2,504 |
|
Dividends declared ($2.80 per share) |
|
|
|
|
|
|
|
|
|
| (305,909) |
|
|
|
|
|
|
|
|
|
| (305,909) |
|
Exercise of stock options |
| 415 |
|
| 42 |
|
| 15,738 |
|
|
|
|
|
|
| 88 |
|
| (5,246) |
|
| 10,534 |
|
Tax benefit of stock-based awards |
|
|
|
|
|
|
| 4,414 |
|
|
|
|
|
|
|
|
|
|
|
|
| 4,414 |
|
Stock issued for vested restricted stock, net of shares withheld for employee taxes |
| 142 |
|
| 14 |
|
| (7,539) |
|
|
|
|
|
|
| (57) |
|
| 1,677 |
|
| (5,848) |
|
Stock-based compensation |
|
|
|
|
|
|
| 26,183 |
|
|
|
|
|
|
|
|
|
|
|
|
| 26,183 |
|
Balance, September 30, 2017 |
| 111,957 |
| $ | 11,196 |
| $ | 487,248 |
| $ | 3,855,686 |
| $ | 2,300 |
| 3,353 |
| $ | (191,839) |
| $ | 4,164,591 |
|
The accompanying notes are an integral part of these consolidated financial statements.
52
2022 FORM 10-K|63Consolidated Statements of Cash Flows
HELMERICH & PAYNE, INC.
| HELMERICH & PAYNE, INC. | |||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED) | |||||||||||||||||
| Year Ended September 30, | |||||||||||||||||
| (in thousands) | 2022 | 2021 | 2020 | ||||||||||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | |||||||||||||||||
| Cash paid during the period: | |||||||||||||||||
| Interest paid | $ | 18,909 | $ | 26,706 | $ | 22,928 | |||||||||||
| Income tax paid (received), net | 17,669 | (32,462) | 46,700 | ||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | |||||||||||||||||
| Payments for operating leases | 11,233 | 17,266 | 18,646 | ||||||||||||||
| Non-cash operating and investing activities: | |||||||||||||||||
| Changes in accounts payable and accrued liabilities related to purchases of property, plant and equipment | (2,425) | (1,526) | 3,123 | ||||||||||||||
| Changes in accounts receivable, property, plant and equipment and other noncurrent assets related to the sale of equipment | — | 9,290 | — | ||||||||||||||
| Cumulative effect adjustment for adoption of ASU No. 2016-13 | — | (1,251) | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| Year Ended September 30, |
| |||||||
|
| 2017 |
| 2016 |
| 2015 |
| |||
|
| (in thousands) |
| |||||||
OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
| $ | (128,212) |
| $ | (56,828) |
| $ | 420,427 |
|
Adjustment for loss from discontinued operations |
|
| 349 |
|
| 3,838 |
|
| 47 |
|
Income (loss) from continuing operations |
|
| (127,863) |
|
| (52,990) |
|
| 420,474 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
| 585,543 |
|
| 598,587 |
|
| 608,039 |
|
Asset impairment charge |
|
| — |
|
| 6,250 |
|
| 39,242 |
|
Amortization of debt discount and debt issuance costs |
|
| 1,055 |
|
| 1,168 |
|
| 749 |
|
Provision for (recovery of) bad debt |
|
| 2,016 |
|
| (2,013) |
|
| 6,034 |
|
Stock-based compensation |
|
| 26,183 |
|
| 24,383 |
|
| 25,195 |
|
Pension settlement charge |
|
| 1,640 |
|
| 4,964 |
|
| 2,873 |
|
Loss on investment securities |
|
| — |
|
| 25,989 |
|
| — |
|
Income from asset sales |
|
| (20,627) |
|
| (9,896) |
|
| (11,834) |
|
Deferred income tax (benefit) expense |
|
| (24,111) |
|
| 60,088 |
|
| 131,431 |
|
Other |
|
| 543 |
|
| 151 |
|
| (368) |
|
Change in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
| (97,114) |
|
| 72,792 |
|
| 259,024 |
|
Inventories |
|
| (10,607) |
|
| 1,944 |
|
| (23,052) |
|
Prepaid expenses and other |
|
| 31,434 |
|
| (2,460) |
|
| (4,457) |
|
Accounts payable |
|
| 39,412 |
|
| (10,907) |
|
| (38,983) |
|
Accrued liabilities |
|
| (36,120) |
|
| 49,562 |
|
| (24,756) |
|
Deferred income taxes |
|
| (942) |
|
| 2,769 |
|
| 688 |
|
Other noncurrent liabilities |
|
| (13,075) |
|
| (16,831) |
|
| 38,322 |
|
Net cash provided by operating activities from continuing operations |
|
| 357,367 |
|
| 753,550 |
|
| 1,428,621 |
|
Net cash provided by (used in) operating activities from discontinued operations |
|
| (150) |
|
| 47 |
|
| (47) |
|
Net cash provided by operating activities |
|
| 357,217 |
|
| 753,597 |
|
| 1,428,574 |
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (397,567) |
|
| (257,169) |
|
| (1,131,445) |
|
Purchase of short-term investments |
|
| (69,866) |
|
| (57,276) |
|
| (45,607) |
|
Payment for acquisition of business, net of cash acquired |
|
| (70,416) |
|
| — |
|
| — |
|
Proceeds from sale of short-term investments |
|
| 69,449 |
|
| 58,381 |
|
| — |
|
Proceeds from asset sales |
|
| 23,412 |
|
| 21,845 |
|
| 22,643 |
|
Net cash used in investing activities |
|
| (444,988) |
|
| (234,219) |
|
| (1,154,409) |
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
Payments on long-term debt |
|
| — |
|
| (40,000) |
|
| (40,000) |
|
Proceeds from senior notes, net of discount |
|
| — |
|
| — |
|
| 497,125 |
|
Debt issuance costs |
|
| — |
|
| (1,111) |
|
| (5,474) |
|
Proceeds on short-term debt |
|
| — |
|
| — |
|
| 1,002 |
|
Payments on short-term debt |
|
| — |
|
| — |
|
| (1,002) |
|
Repurchase of common stock |
|
| — |
|
| — |
|
| (59,654) |
|
Dividends paid |
|
| (305,515) |
|
| (300,152) |
|
| (298,367) |
|
Exercise of stock options, net of tax withholding |
|
| 10,534 |
|
| 1,040 |
|
| 2,650 |
|
Tax withholdings related to net share settlements of restricted stock |
|
| (5,848) |
|
| (3,912) |
|
| (5,140) |
|
Excess tax benefit from stock-based compensation |
|
| 4,414 |
|
| 934 |
|
| 3,772 |
|
Net cash provided by (used in) financing activities |
|
| (296,415) |
|
| (343,201) |
|
| 94,912 |
|
Net increase (decrease) in cash and cash equivalents |
|
| (384,186) |
|
| 176,177 |
|
| 369,077 |
|
Cash and cash equivalents, beginning of period |
|
| 905,561 |
|
| 729,384 |
|
| 360,307 |
|
Cash and cash equivalents, end of period |
| $ | 521,375 |
| $ | 905,561 |
| $ | 729,384 |
|
The accompanying notes are an integral part of these consolidated financial statements.
53
2022 FORM 10-K|64NotesHELMERICH & PAYNE, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| NOTE 1 NATURE OF OPERATIONS | ||||||||||||||
HELMERICH & PAYNE, INC.
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statementsmake hydrocarbon recovery safer and more economical for oil and gas exploration and production companies.
BASIS OF PRESENTATION
will not have a significant effect on our operations and financial results going forward.
| NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, RISKS AND UNCERTAINTIES | ||||||||||||||
FOREIGN CURRENCIES
2022 FORM 10-K|65RECENTLY ADOPTED ACCOUNTING STANDARDS
In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-04, Intangibles-Goodwill
In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements — Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The guidance provides principlesbanks and definitions for management that are intended to reduce diversity in the timing and content of disclosures provided in footnotes. Under the standard, management is required to evaluate for each annual and interim reporting period whether it is probable that the entity will not be able to meet its obligations as they become due within one year after the date that financial statements are issued (or are available to be issued, where applicable). We adopted ASU No. 2014-15, as required, on September 30, 2017 with no impact on the consolidated financial statements.
54
CASH AND CASH EQUIVALENTS
Cash equivalents consist of investments in short-term,all highly liquid securities havinginvestments with original maturities of three months or less. The carrying valuesOur cash, cash equivalents and short-term investments are subject to potential credit risk, and certain of these assets approximate their fair values. We utilize aour cash management system with a series of separate accounts consisting of lockbox accounts for receiving cash, concentration accounts, and several “zero-balance” disbursement accounts for funding payroll and accounts payable.
RESTRICTED CASH AND CASH EQUIVALENTS
carry balances greater than the federally insured limits.
The
|
|
|
|
|
|
|
|
|
| September 30, |
| ||||
|
| 2017 |
| 2016 |
| ||
|
| (in thousands) |
| ||||
Prepaid expenses and other |
| $ | 32,439 |
| $ | 27,631 |
|
Other assets |
| $ | 6,695 |
| $ | 2,000 |
|
| September 30, | |||||||||||||||||
| (in thousands) | 2022 | 2021 | 2020 | ||||||||||||||
| Cash and cash equivalents | $ | 232,131 | $ | 917,534 | $ | 487,884 | |||||||||||
| Restricted cash | 36,246 | 18,350 | 45,577 | ||||||||||||||
| Restricted cash - long-term: | |||||||||||||||||
| Other assets, net | 632 | 832 | 3,286 | ||||||||||||||
| Total cash, cash equivalents, and restricted cash | $ | 269,009 | $ | 936,716 | $ | 536,747 | |||||||||||
INVENTORIES
INVESTMENTS
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 $28.0 million and $29.3 million for fiscal years 2022 and 2021, respectively.
We regularly review investment securities for impairment based on criteria that include the extent to which the investment’s carrying value exceeds its related fair value, the durationtax effect, in other comprehensive income. Upon sale, realized gains/losses are reported in net income.
2022 FORM 10-K|66PROPERTY, PLANT AND EQUIPMENT
Equipment
We lease office space and equipment for use in operations. Leases are evaluated at inceptionrecognize, on a prospective basis, increased or upon any subsequent material modification and, depending on the lease terms, are classified as either capital leases or operating leases as appropriate under Accounting Standards Codification (“ASC”) 840, Leases. We do not have significant capital leases.
55
CAPITALIZATION OF INTEREST
We capitalize interest on major projects during construction. Interest is capitalized based on the average interest rate on related debt. Capitalized interest for fiscal 2017, 2016 and 2015 was $0.3 million, $2.8 million and $7.0 million, respectively.
VALUATION OF LONG-LIVED ASSETS
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, completionrestructuring of specific contractsour drilling fleet, and/or overall general market conditions. If athe review of the long-lived assets indicates that the carrying value of certain of these assetsassets/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,recognized, as required, to adjust the carrying value down to the estimated fair value of the asset. The estimated 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 market approach. combination of multiple approaches.
Beginning in the first fiscal quarter of fiscal 2015 and continuing into fiscal 2016, domestic and international oil prices declined significantly but have since largely stabilized at lower levels. This decline in pricing resulted in lower demand for our drilling services. For any asset group for which an impairment indicator was present, we performed an impairment evaluation in accordance with ASC 360, Property, Plant, and Equipment by estimating our future undiscounted cash flows from the use and eventual disposal of the asset group using probability weighted scenarios. The most significant assumptions used in our analysis are expected margin per day, utilization and expected value upon disposal. We believe the assumptions and estimates used in our impairment analysis, including the development of probability weighted cash flow projections, are reasonable and appropriate; however, different assumptions and estimates could materially impact the analysis and resulting conclusions in some cases.
During fiscal 2016, we recorded an asset impairment charge in the U.S. Land segment of $6.3 million to reduce the carrying value of rig and rig related equipment classified as held for sale to their estimated fair values, based on expected sales prices. The assets were originally classified as held for sale with the intent of selling them into an international location. The outlook on U.S. trade policies with the targeted international location subsequently shifted, causing sale negotiations to stall. Thus, during the second quarter of fiscal 2017, we determined the equipment no longer met the held for sale criteria and reclassified it to property, plant and equipment. There was no impact on our results of operations from this decision. The rig equipment is from rigs that were decommissioned from service in prior fiscal years and written down to their estimated recoverable value at the time of decommissioning and is recorded at its carrying value which is lower than its estimated fair value.
During fiscal 2015, our valuation of long-lived assets resulted in $39.2 million of impairment charges to reduce the carrying value of seven SCR land rigs within our International Land segment to their estimated fair value of $20.6 million which was based on a discounted cash flow analysis. Our discounted cash flow analysis consisted of creating projected cash flows that a market participant would reasonably develop and then applying an appropriate risk adjusted rate. Six of these rigs along with other rig related assets were classified as held for sale at September 30, 2016. When the assets were originally classified as held for sale, the Latin American drilling market appeared to be trending upward. As marketing efforts continued, buyer interest diminished due to the Latin American market remaining flat in terms of rig counts and oil prices. Since that point, the market remained flat in terms of rig counts and oil prices. During the third quarter of fiscal 2017, we determined the equipment no longer met the held for sale criteria and reclassified it to property, plant and equipment. Our 2017 results of operations reflect a $2.2 million depreciation catch-up adjustment as a result of this decision. The equipment is recorded at its carrying value which is lower than its estimated fair value.
56
GOODWILL AND INTANGIBLE ASSETS
Goodwill represents the excess of costthe purchase price over the fair value of net assets acquired and liabilities assumed in a business combination.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 indications of potential impairment exist.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’sunit'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. All of our goodwill is within our other non-reportable business segment. We assess goodwill for impairment in the fourth fiscal quarter. Our assessment in fiscal 2017, 2016 and 2015 did not result in any impairment charge. The following is a summary of changes in goodwill (in thousands):
|
|
|
|
|
Balance at September 30, 2015 |
| $ | 4,718 |
|
Additions |
|
| — |
|
Balance at September 30, 2016 |
|
| 4,718 |
|
Additions |
|
| 46,987 |
|
Balance at September 30, 2017 |
| $ | 51,705 |
|
|
|
|
|
|
Intangible assets with indefinite lives are tested for impairment at least annually in the fourth fiscal quarter and if events occur or circumstances change that would indicate that the value of the asset may be impaired. Impairment is measured as the difference between the fair value of the asset and its carrying value. 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 155 to 20 years, and are evaluated for impairment in accordance with our policies for valuation of long-lived assets. No impairment of intangible assets was recorded in fiscal 2017, 2016 or 2015. The following is a summary of our finite-lived and indefinite-lived intangible assets other than goodwill at September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| September 30, 2017 |
| September 30, 2016 |
| ||||||||
|
| Gross |
|
|
| Gross |
|
|
| ||||
|
| Carrying |
| Accumulated |
| Carrying |
| Accumulated |
| ||||
|
| Amount |
| Amortization |
| Amount |
| Amortization |
| ||||
|
| (in thousands) |
| ||||||||||
Finite-lived intangible asset: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed technology |
| $ | 51,000 |
| $ | 1,134 |
| $ | — |
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Indefinite-lived intangible asset: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Trademark |
| $ | 919 |
|
|
|
| $ | 919 |
|
|
|
|
Amortization expense was $1.1 million for the year ended September 30, 2017 and is estimated to be $3.4 million in each of the next five fiscal years.
SELF-INSURANCE ACCRUALS
We have accrued a liability for estimated worker’s compensation and other casualty claims incurred based upon case 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
DRILLING REVENUES
Contract drilling revenues areprimarily 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,Revenues associated with mobilization and demobilization and direct costs incurred for the mobilization, are deferred and recognized on a straight-line basis overas the term of the related drilling contract.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 2017, 2016years 2022, 2021 and 20152020 were $179.9$263.1 million, $125.9$148.0 million and $302.2$212.0 million, respectively. For fixed-term 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
57
from early terminated contracts are recognized when all contractual requirements have been met. Early termination revenue for fiscal 2017, 2016years 2022, 2021 and 20152020 was approximately $29.4$0.7 million, $219.0$7.7 million and $222.3$73.4 million, respectively.
RENT REVENUES
2022 FORM 10-K|67
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
|
| Year Ended September 30, |
| Year Ended September 30, | |||||||||||||||||||||||
|
| 2017 |
| 2016 |
| 2015 |
| ||||||||||||||||||||
|
| (in thousands) |
| ||||||||||||||||||||||||
| (in thousands) | (in thousands) | 2022 | 2021 | 2020 | |||||||||||||||||||||||
Minimum rents |
| $ | 9,735 |
| $ | 9,196 |
| $ | 9,608 |
| Minimum rents | $ | 6,362 | $ | 5,589 | $ | 9,245 | ||||||||||
Overage and percentage rents |
| $ | 936 |
| $ | 1,211 |
| $ | 1,030 |
| Overage and percentage rents | 773 | 726 | 656 | |||||||||||||
|
|
|
|
|
Fiscal Year |
| Amount |
| |
|
| (in thousands) |
| |
2018 |
| $ | 7,845 |
|
2019 |
|
| 6,100 |
|
2020 |
|
| 4,961 |
|
2021 |
|
| 3,973 |
|
2022 |
|
| 2,032 |
|
Thereafter |
|
| 5,293 |
|
Total |
| $ | 30,204 |
|
| Fiscal Year | Amount (in thousands) | ||||
| 2023 | $ | 5,214 | |||
| 2024 | 4,519 | ||||
| 2025 | 3,733 | ||||
| 2026 | 2,820 | ||||
| 2027 | 1,575 | ||||
| Thereafter | 2,241 | ||||
| Total | $ | 20,102 | |||
|
|
|
|
|
|
|
| |||||||||||
|
| September 30, |
| September 30, | ||||||||||||||
|
| 2017 |
| 2016 |
| |||||||||||||
|
| (in thousands) |
| |||||||||||||||
| (in thousands) | (in thousands) | 2022 | 2021 | |||||||||||||||
Real estate properties |
| $ | 66,005 |
| $ | 62,929 |
| Real estate properties | $ | 45,557 | $ | 43,302 | ||||||
Accumulated depreciation |
|
| (42,169) |
|
| (40,777) |
| Accumulated depreciation | (30,510) | (28,846) | ||||||||
|
| $ | 23,836 |
| $ | 22,152 |
| $ | 15,047 | $ | 14,456 | |||||||
INCOME TAXES
58
EARNINGS PER SHARE
Basic earnings per share is computed utilizing the two-class method and is calculated based on the weighted-average number of common shares outstanding during the periods presented. Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options, and nonvested restricted stock.
STOCK-BASED COMPENSATION
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.
2022 FORM 10-K|68TREASURY STOCK
See Note 11—Stock-based Compensation for additional discussion on stock-based compensation.
COMPREHENSIVE INCOME OR LOSS
Treasury stock may be issued under the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan.
NEW ACCOUNTING STANDARDS NOT YET ADOPTED
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes virtually all existing revenue recognition guidance. Throughout 2016
59
In July 2015, the FASB issued ASU No 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. This update simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with the lower of cost or net realizable value test. Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard should be applied prospectively and is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. We will adopt ASU No. 2015-11 on October 1, 2017 and do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The standard requires entities to measure equity investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any changes in fair value in net income. The provisions of ASU 2016-01 are effective for interim and annual periods starting after December 15, 2017. At adoption, a cumulative-effect adjustment to beginning retained earnings will be recorded. We will adopt this standard on October 1, 2018. Subsequent to adoption, changes in the fair value of our available-for-sale investments will be recognized in net income and the effect will be subject to stock market fluctuations.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 will require organizations that lease assets — referred to as “lessees” — to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. Under ASU 2016-02, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Lessor accounting remains substantially similar to current GAAP. In addition, disclosures of leasing activities are to be expanded to include qualitative along with specific quantitative information. For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-02 mandates a modified retrospective transition method with an option to use certain practical expedients. Since a portion of our contract drilling revenue will be subject to this new leasing guidance, we expect to adopt this new lease guidance utilizing the modified retrospective method of adoption in the first quarter of fiscal 2019 concurrently with ASU 2014-09. We are currently evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. Our findings are periodically reported to management. We have performed a scoping and preliminary assessment of the impact of this new standard. As a lessor, we expect the adoption of this new standard will apply to our drilling contracts and as a result, we expect to have a lease component and a service component of our revenues derived from drilling contracts. As a lessee, this standard will primarily impact us in situations where we lease real estate and equipment, for which we will recognize a right-of-use asset and a corresponding lease liability on our consolidated balance sheet. We are currently evaluating the potential impact of adopting this guidance on our consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-09, Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity orwithin accrued liabilities and classification on the statement of cash flows. For public entities, ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. We will adopt ASU No. 2016-09 on October 1, 2017. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses. The ASU sets forth a “current expected credit loss” (CECL) model which requires companies to measure all expected credit losses for financial instruments heldother non-current liabilities at the reporting date based on historical experience, current conditions and reasonable supportable forecasts. This replacesat which the existing incurred loss model andleased asset is applicable to the measurement of credit losses on financial assets measured at amortized cost and applies to some off-balance sheet credit exposures. This standard is effectiveavailable for interim and annual periods beginning after December 15, 2019. We are currently assessing the impact this standard will have on our consolidated financial statements and disclosures.
In August 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). The ASU is intended to reduce diversity in practice in presentation and classification of certain cash receipts and cash paymentsuse by providing guidance on eight specific cash flow issues. The ASU is effective for interim and annual periods beginning after December 15, 2017 and early adoption
60
is permitted, including adoption during an interim period. We are currently assessing the impact this standard will have on our consolidated statement of cash flows.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows - Restricted Cash. The ASU requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. The ASU is effective for interim and annual periods beginning after December 31, 2017 and early adoption is permitted, including adoption during an interim period. We will adopt the guidance beginning October 1, 2018 applied retrospectively to all periods presented. The adoption is not expected to have a material impact on our consolidated financial position or cash flows.
In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. ASU 2017-07 will change how employers that sponsor defined benefit pension and/or other post-retirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Employers will present the other components of the net periodic benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income, if one is presented. This standard is effective for public business entities for annual periods or any interim periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted. We do not expect the new guidance to have a material impact on our financial condition or results of operation.
We have evaluated all new accounting standards that are in effect and may impact our financial statements and do not believe that there are any other new accounting standards that have been issued that might have a material impact on our financial position or results of operations.
NOTE 2 BUSINESS COMBINATIONS
On June 2, 2017, we completed a merger transaction (“MOTIVE Merger”) pursuant to which an unaffiliated drilling technology company, MOTIVE Drilling Technologies, Inc., a Delaware corporation (“MOTIVE”), was merged with and into our wholly owned subsidiary Spring Merger Sub, Inc., a Delaware corporation. MOTIVE survived the transaction and is now a wholly owned subsidiary of the Company. The operations for MOTIVE are included with all other non-reportable business segments. At the effective time of the MOTIVE Merger, MOTIVE shareholders received aggregate cash consideration of $74.3 million, net of customary closing adjustments, and may receive up to an additional $25.0 million in potential earnout payments based on future performance. At closing, $9.4 million of the cash consideration was placed in escrow, with one-half to be released to the seller on each of the twelve and eighteen month anniversaries of the merger completion date. Transaction costs related to the MOTIVE Merger incurred during fiscal 2017 were $3.2 million and are recorded in the Consolidated Statement of Operations within the general and administrativeOperating lease expense line item. We recorded revenue of $3.3 million and a net loss of $2.2 million related to the MOTIVE Merger during fiscal 2017.
MOTIVE has a proprietary Bit Guidance System that is an algorithm-driven system that considers the total economic consequences of directional drilling decisions and has proven to consistently lower drilling costs through more efficient drilling and increase hydrocarbon production through smoother wellbores and more accurate well placement. Given our strong and longstanding technology and innovation focus, we believe the technology will continue to advance and provide further benefits for the industry.
The MOTIVE Merger is accounted for as a business combination in accordance with ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. The following table summarizes the purchase price and the allocation of the fair values of assets acquired and liabilities assumed and separately identifiable intangible assets at the acquisition date (in thousands):
61
|
|
|
|
Purchase Price |
|
|
|
Consideration given |
|
|
|
|
|
|
|
Cash consideration |
| $ | 74,275 |
Long-term contingent earnout liability (Other noncurrent liabilities) |
|
| 14,509 |
Total consideration given |
| $ | 88,784 |
|
|
|
|
Allocation of Purchase Price |
|
|
|
Fair value of assets acquired |
|
|
|
Current assets |
| $ | 4,425 |
Property, plant and equipment |
|
| 300 |
Intangible asset - developed technology (Intangible assets, net of amortization) |
|
| 51,000 |
Goodwill |
|
| 46,987 |
|
|
|
|
Total assets acquired |
| $ | 102,712 |
|
|
|
|
Fair value of liabilities assumed |
|
|
|
Current liabilities |
| $ | 25 |
Deferred income taxes |
|
| 13,903 |
|
|
|
|
Total liabilities acquired |
| $ | 13,928 |
|
|
|
|
Fair value of total assets and liabilities acquired |
| $ | 88,784 |
The fair value of the contingent consideration of $14.5 million at June 2, 2017 and $14.9 million at September 30, 2017 was calculated using a Monte Carlo simulation which evaluates numerous potential earnings and pay out scenarios and is considered a level 3 measurement under the fair value hierarchy. The developed technology is an intangible asset that will be amortizedrecognized on a straight-line basis over the life of the lease. 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.
2022 FORM 10-K|69| Standard | Description | Date of Adoption | Effect on the Financial Statements or Other Significant Matters | ||||||||
| Recently Adopted Accounting Pronouncements | |||||||||||
| ASU No. 2019-12, Financial Instruments – Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes | 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 update is effective for annual periods beginning after December 15, 2020. | October 1, 2021 | We adopted this ASU, as required, during the first quarter of fiscal year 2022. The adoption did not have a material effect on our Consolidated Financial Statements and disclosures. | ||||||||
| Standards that are not yet adopted as of September 30, 2022 | |||||||||||
| ASU No. 2020-06, Debt with conversion and other options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s own equity (subtopic 815-40): Accounting For Convertible Instruments and Contracts In An Entity’s Own Equity | This ASU reduces the complexity of accounting for convertible debt and other equity-linked instruments by reducing the number of accounting models for convertible debt instruments and convertible preferred stock. Limiting the accounting models results in fewer embedded conversion features being separately recognized from the host contract as compared with current GAAP. Convertible instruments that continue to be subject to separation models are (1) those with embedded conversion features that are not clearly and closely related to the host contract, that meet the definition of a derivative, and that do not qualify for a scope exception from derivative accounting and (2) convertible debt instruments issued with substantial premiums for which the premiums are recorded as paid-in capital. This update is effective for annual and interim periods beginning after December 15, 2021. Early adoption of the amendment is permitted. | October 1, 2022 | We plan to adopt this ASU, as required, during the first quarter of fiscal year 2023. We do not believe the adoption will have a material effect on our Consolidated Financial Statements and disclosures. | ||||||||
| ASU No. 2022-03, Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions | The amendments in this update clarify that a contractual restriction on the sale of an equity security is not considered part of the unit of account of the equity security and, therefore, is not considered in measuring fair value (i.e., the entity would not apply a discount related to the contractual sale restriction). Furthermore, an entity cannot, as a separate unit of account, recognize and measure a contractual sale restriction. The following disclosures for equity securities subject to contractual sale restrictions will be required: (1) the fair value of the equity securities subject to contractual sale restrictions reflected in the balance sheet, (2) the nature and remaining duration of the restriction(s), and (3) the circumstances that could cause a lapse in the restriction(s). This update is effective for annual and interim periods beginning after December 15, 2023. Early adoption of the amendment is permitted for both interim and annual financial statements. | October 1, 2022 | We plan to early adopt this ASU during the first quarter of fiscal year 2023. We do not believe the adoption will have a material effect on our Consolidated Financial Statements and disclosures. | ||||||||
2022 FORM 10-K|70The following unaudited pro forma combined financial information is provided for fiscal 2017 and fiscal 2016, as though the MOTIVE Merger had been completed as of October 1, 2015. These pro forma combined results of operations have been prepared by adjusting our historical results to include the historical results of MOTIVE and reflect pro forma adjustments based on available informationadjusters’ estimates, historical experience and certain assumptionsstatistical methods commonly used within the insurance industry that we believe are reasonable, including applicationreliable. We have also engaged a third-party actuary to perform a review of an appropriate income taxour 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.
2022 FORM 10-K|7162
2022 FORM 10-K|72
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|
|
|
|
| Pro Forma | ||||
|
| 2017 |
| 2016 | ||
|
| (unaudited) | ||||
|
|
|
|
|
|
|
Revenues |
| $ | 1,807,950 |
| $ | 1,626,305 |
Net loss |
| $ | (127,093) |
| $ | (59,776) |
NOTE 3 DISCONTINUED OPERATIONS
Current assets of
| NOTE 3 DISCONTINUED OPERATIONS | ||||||||||||||
Expenses incurred for in-country obligations are reported as discontinued operations.
In March 2016,operations within our Consolidated Statements of Operations.
| NOTE 4 PROPERTY, PLANT AND EQUIPMENT | ||||||||||||||
| (in thousands) | Estimated Useful Lives | September 30, 2022 | September 30, 2021 | ||||||||||||||
| Drilling services equipment | 4 - 15 years | $ | 6,369,888 | $ | 6,229,011 | ||||||||||||
| Tubulars | 4 years | 569,496 | 573,900 | ||||||||||||||
| Real estate properties | 10 - 45 years | 45,557 | 43,302 | ||||||||||||||
| Other | 2 - 23 years | 422,479 | 459,741 | ||||||||||||||
Construction in progress1 | 70,119 | 47,587 | |||||||||||||||
| 7,477,539 | 7,353,541 | ||||||||||||||||
| Accumulated depreciation | (4,516,730) | (4,226,254) | |||||||||||||||
| Property, plant and equipment, net | $ | 2,960,809 | $ | 3,127,287 | |||||||||||||
| Assets held-for-sale | $ | 4,333 | $ | 71,453 | |||||||||||||
2022 FORM 10-K|73| Balance at September 30, 2020 | $ | — | |||
| Plus: | |||||
| Asset additions | 77,929 | ||||
| Less: | |||||
| Sale of assets held-for-sale | (6,476) | ||||
| Balance at September 30, 2021 | 71,453 | ||||
| Plus: | |||||
| Asset additions | 2,580 | ||||
| Less: | |||||
| Sale of assets held-for-sale | (67,592) | ||||
| Reclassification to assets held and used | (2,108) | ||||
| Balance at September 30, 2022 | $ | 4,333 | |||
2022 FORM 10-K|742022 FORM 10-K|75| NOTE 5 LEASES | ||||||||||||||
| (in thousands) | September 30, 2022 | September 30, 2021 | |||||||||
Operating lease commitments, including probable extensions1 | $ | 44,769 | $ | 56,667 | |||||||
| Discounted using the lessee's incremental borrowing rate | $ | 41,002 | $ | 52,372 | |||||||
| (Less): short-term leases recognized on a straight-line basis as expense | (1,052) | (1,761) | |||||||||
| (Less): other | (218) | (123) | |||||||||
| Lease liability recognized | $ | 39,732 | $ | 50,488 | |||||||
| Of which: | |||||||||||
| Current lease liabilities | $ | 12,382 | $ | 12,624 | |||||||
| Non-current lease liabilities | 27,350 | 37,864 | |||||||||
| (in thousands) | September 30, 2022 | September 30, 2021 | |||||||||
| Properties | $ | 38,925 | $ | 48,176 | |||||||
| Equipment | 125 | 935 | |||||||||
| Other | 14 | 76 | |||||||||
| Total right-of-use assets | $ | 39,064 | $ | 49,187 | |||||||
| Year ended September 30, | |||||||||||
| (in thousands) | 2022 | 2021 | |||||||||
| Operating lease cost | $ | 9,687 | $ | 13,686 | |||||||
| Short-term lease cost | 1,546 | 3,580 | |||||||||
| Total lease cost | $ | 11,233 | $ | 17,266 | |||||||
2022 FORM 10-K|76| September 30, 2022 | September 30, 2021 | ||||||||||
| Weighted average remaining lease term | 5.9 | 6.7 | |||||||||
| Weighted average discount rate | 2.5 | % | 2.5 | % | |||||||
| Fiscal Year | Amount | ||||
| 2023 | $ | 9,767 | |||
| 2024 | 7,801 | ||||
| 2025 | 4,501 | ||||
| 2026 | 2,033 | ||||
| 2027 | 2,046 | ||||
| Thereafter | 5,465 | ||||
Total1 | $ | 31,613 | |||
| NOTE 6 GOODWILL AND INTANGIBLE ASSETS | ||||||||||||||
2022 FORM 10-K|77| September 30, 2022 | September 30, 2021 | ||||||||||||||||||||||||||||||||||||||||
| (in thousands) | Weighted Average Estimated Useful Lives | Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | ||||||||||||||||||||||||||||||||||
| Finite-lived intangible asset: | |||||||||||||||||||||||||||||||||||||||||
| Developed technology | 15 years | $ | 89,096 | $ | 28,137 | $ | 60,959 | $ | 89,096 | $ | 22,182 | $ | 66,914 | ||||||||||||||||||||||||||||
| Intellectual property | 13 years | 2,000 | 328 | 1,672 | 1,500 | 216 | 1,284 | ||||||||||||||||||||||||||||||||||
| Trade name | 20 years | 5,865 | 1,475 | 4,390 | 5,865 | 1,158 | 4,707 | ||||||||||||||||||||||||||||||||||
| Customer relationships | 5 years | 4,000 | 3,867 | 133 | 4,000 | 3,067 | 933 | ||||||||||||||||||||||||||||||||||
| $ | 100,961 | $ | 33,807 | $ | 67,154 | $ | 100,461 | $ | 26,623 | $ | 73,838 | ||||||||||||||||||||||||||||||
NOTE 4 DEBT
At September 30, 2017our cash flow model include timing of awarded future contracts, commercial pricing terms, utilization, discount rate, and 2016,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.
2022 FORM 10-K|78| NOTE 7 DEBT | ||||||||||||||
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|
|
|
|
|
|
| Unamortized Discount and |
| ||||
|
| Principal |
| Debt Issuance Costs |
| ||||||||
|
| September 30, |
| September 30, |
| September 30, |
| September 30, |
| ||||
|
| 2017 |
| 2016 |
| 2017 |
| 2016 |
| ||||
|
| (in thousands) |
| ||||||||||
Unsecured senior notes issued March 19, 2015: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Due March 19, 2025 |
| $ | 500,000 |
| $ | 500,000 |
| $ | (7,098) |
| $ | (8,153) |
|
|
|
| 500,000 |
|
| 500,000 |
|
| (7,098) |
|
| (8,153) |
|
Less long-term debt due within one year |
|
| — |
|
| — |
|
| — |
|
| — |
|
Long-term debt |
| $ | 500,000 |
| $ | 500,000 |
| $ | (7,098) |
| $ | (8,153) |
|
| September 30, 2022 | September 30, 2021 | ||||||||||||||||||||||||||||||||||
| (in thousands) | Face Amount | Unamortized Discount and Debt Issuance Cost | Book Value | Face Amount | Unamortized Discount and Debt Issuance Cost | Book Value | |||||||||||||||||||||||||||||
| Unsecured senior notes: | |||||||||||||||||||||||||||||||||||
Due March 19, 20251 | $ | — | $ | — | $ | — | $ | 487,148 | $ | (3,662) | $ | 483,486 | |||||||||||||||||||||||
| Due September 29, 2031 | 550,000 | (7,390) | 542,610 | 550,000 | (8,003) | 541,997 | |||||||||||||||||||||||||||||
| 550,000 | (7,390) | 542,610 | 1,037,148 | (11,665) | 1,025,483 | ||||||||||||||||||||||||||||||
| Less: long-term debt due within one year | $ | — | — | — | (487,148) | 3,662 | (483,486) | ||||||||||||||||||||||||||||
| Long-term debt | $ | 550,000 | $ | (7,390) | $ | 542,610 | $ | 550,000 | $ | (8,003) | $ | 541,997 | |||||||||||||||||||||||
We have
2022 FORM 10-K|7963
Subsequent to September 30, 2017, the Company entered into a $12 million unsecured standalone line of credit facility, which is purposed for the issuance of bid and performance bonds, as needed, for international operations. The Company currently has two bonds issued under this line for a total value of approximately $5.4 million.
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, 2017,2022, we were in compliance with all debt covenants.
|
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|
Years ending September 30, |
|
|
|
|
2018 |
| $ | — |
|
2019 |
|
| — |
|
2020 |
|
| — |
|
2021 |
|
| — |
|
2022 |
|
| — |
|
Thereafter |
| $ | 500,000 |
|
|
| $ | 500,000 |
|
| Year ending September 30, | |||||
| 2023 | $ | — | |||
| 2024 | — | ||||
| 2025 | — | ||||
| 2026 | — | ||||
| 2027 | — | ||||
| Thereafter - Due 2031 | 550,000 | ||||
| $ | 550,000 | ||||
NOTE 5 INCOME TAXES
| NOTE 8 INCOME TAXES | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
|
| Year Ended September 30, |
| Year Ended September 30, | |||||||||||||||||||||||
|
| 2017 |
| 2016 |
| 2015 |
| ||||||||||||||||||||
|
| (in thousands) |
| ||||||||||||||||||||||||
| (in thousands) | (in thousands) | 2022 | 2021 | 2020 | |||||||||||||||||||||||
Current: |
|
|
|
|
|
|
|
|
|
| Current: | ||||||||||||||||
Federal |
| $ | (36,260) |
| $ | (86,010) |
| $ | 84,229 |
| Federal | $ | 40,245 | $ | (15,466) | $ | 15,431 | ||||||||||
Foreign |
|
| 4,108 |
|
| 9,987 |
|
| 14,864 |
| Foreign | 10,703 | 772 | 1,495 | |||||||||||||
State |
|
| (472) |
|
| (3,742) |
|
| 10,881 |
| State | 1,906 | 725 | 523 | |||||||||||||
|
|
| (32,624) |
|
| (79,765) |
|
| 109,974 |
| 52,854 | (13,969) | 17,449 | ||||||||||||||
Deferred: |
|
|
|
|
|
|
|
|
|
| Deferred: | ||||||||||||||||
Federal |
|
| (14,953) |
|
| 58,136 |
|
| 165,491 |
| Federal | (32,382) | (81,760) | (127,096) | |||||||||||||
Foreign |
|
| (7,827) |
|
| 408 |
|
| (34,410) |
| Foreign | (1,310) | 4,106 | (12,390) | |||||||||||||
State |
|
| (1,331) |
|
| 1,544 |
|
| 350 |
| State | 5,204 | (12,098) | (18,069) | |||||||||||||
|
|
| (24,111) |
|
| 60,088 |
|
| 131,431 |
| (28,488) | (89,752) | (157,555) | ||||||||||||||
Total provision (benefit) |
| $ | (56,735) |
| $ | (19,677) |
| $ | 241,405 |
| Total provision (benefit) | $ | 24,366 | $ | (103,721) | $ | (140,106) | ||||||||||
2022 FORM 10-K|80
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
|
| Years Ended September 30, |
| Year Ended September 30, | |||||||||||||||||||||||
|
| 2017 |
| 2016 |
| 2015 |
| ||||||||||||||||||||
|
| (in thousands) |
| ||||||||||||||||||||||||
| (in thousands) | (in thousands) | 2022 | 2021 | 2020 | |||||||||||||||||||||||
Domestic |
| $ | (173,157) |
| $ | (49,636) |
| $ | 675,425 |
| Domestic | $ | (14,411) | $ | (412,556) | $ | (458,364) | ||||||||||
Foreign |
|
| (11,441) |
|
| (23,031) |
|
| (13,546) |
| Foreign | 45,329 | (28,624) | (178,134) | |||||||||||||
|
| $ | (184,598) |
| $ | (72,667) |
| $ | 661,879 |
| $ | 30,918 | $ | (441,180) | $ | (636,498) | |||||||||||
| Year Ended September 30, | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| U.S. Federal income tax rate | 21.0 | % | 21.0 | % | 21.0 | % | |||||||||||
| Effect of foreign taxes | 31.7 | 0.1 | (0.2) | ||||||||||||||
| State income taxes, net of federal tax benefit | 21.7 | 2.6 | 2.8 | ||||||||||||||
| Other impact of foreign operations | 3.5 | — | (0.5) | ||||||||||||||
| Non-deductible meals and entertainment | 1.0 | (0.1) | (0.2) | ||||||||||||||
| Equity compensation | 9.6 | (0.8) | (0.3) | ||||||||||||||
| Excess officer's compensation | 3.8 | — | (0.2) | ||||||||||||||
| Foreign derived intangible income | (13.8) | — | — | ||||||||||||||
| Other | 0.3 | 0.7 | (0.4) | ||||||||||||||
| Effective income tax rate | 78.8 | % | 23.5 | % | 22.0 | % | |||||||||||
64
The components of our net deferred tax liabilities are as follows:
|
|
|
|
|
|
|
| |||||||||||
|
| September 30, |
| September 30, | ||||||||||||||
|
| 2017 |
| 2016 |
| |||||||||||||
|
| (in thousands) |
| |||||||||||||||
| (in thousands) | (in thousands) | 2022 | 2021 | |||||||||||||||
Deferred tax liabilities: |
|
|
|
|
|
|
| Deferred tax liabilities: | ||||||||||
Property, plant and equipment |
| $ | 1,386,512 |
| $ | 1,411,139 |
| Property, plant and equipment | $ | 558,293 | $ | 598,798 | ||||||
Available-for-sale securities |
|
| 24,940 |
|
| 25,470 |
| |||||||||||
| Marketable securities | Marketable securities | 9,766 | 1,669 | |||||||||||||||
Other |
|
| 21,609 |
|
| 2,326 |
| Other | 24,460 | 26,244 | ||||||||
Total deferred tax liabilities |
|
| 1,433,061 |
|
| 1,438,935 |
| Total deferred tax liabilities | 592,519 | 626,711 | ||||||||
Deferred tax assets: |
|
|
|
|
|
|
| Deferred tax assets: | ||||||||||
Pension reserves |
|
| 7,614 |
|
| 8,330 |
| Pension reserves | 4,811 | 5,791 | ||||||||
Self-insurance reserves |
|
| 19,461 |
|
| 15,282 |
| Self-insurance reserves | 7,333 | 7,862 | ||||||||
Net operating loss, foreign tax credit, and other federal tax credit carryforwards |
|
| 62,478 |
|
| 71,778 |
| Net operating loss, foreign tax credit, and other federal tax credit carryforwards | 8,673 | 25,474 | ||||||||
Financial accruals |
|
| 62,971 |
|
| 67,594 |
| Financial accruals | 31,022 | 31,910 | ||||||||
Other |
|
| 6,003 |
|
| 4,952 |
| Other | 13,678 | 17,963 | ||||||||
Total deferred tax assets |
|
| 158,527 |
|
| 167,936 |
| Total deferred tax assets | 65,517 | 89,000 | ||||||||
Valuation allowance |
|
| (58,155) |
|
| (71,457) |
| Valuation allowance | (10,710) | (25,726) | ||||||||
Net deferred tax assets |
|
| 100,372 |
|
| 96,479 |
| Net deferred tax assets | 54,807 | 63,274 | ||||||||
Net deferred tax liabilities |
| $ | 1,332,689 |
| $ | 1,342,456 |
| Net deferred tax liabilities | $ | 537,712 | $ | 563,437 | ||||||
2022 FORM 10-K|81The federal net operating loss carryforward of $12.6 million and other federal tax credit carryforward of $0.3 million resulted from the acquisition of MOTIVE, which closed during the third quarter of fiscal 2017. The acquisition represented an ownership change under Internal Revenue Code Section 382 for which both are subject to an annual limitation. Both tax attributes begin to expire in 2034 and it is more likely than not both will be utilized.
For the fiscal year ended September 30, 2017, the Company is estimating a federal net operating loss for income tax purposes of approximately $125.1 million. At this time, the Company is anticipating carrying back the federal net operating loss to the fiscal year ended September 30, 2015 and has recorded an estimated income tax receivable of $39.8 million. The Company has until the filing of the federal income tax return for the fiscal year ended September 30, 2017 to decide whether to carryback or carryforward the net operating loss.
Effective income tax rates as compared to the U.S. Federal income tax rate are as follows:
|
|
|
|
|
|
|
|
|
| Year Ended September 30, |
| ||||
|
| 2017 |
| 2016 |
| 2015 |
|
U.S. Federal income tax rate |
| 35.0 | % | 35.0 | % | 35.0 | % |
Effect of foreign taxes |
| 1.8 |
| (13.8) |
| (3.2) |
|
State income taxes, net of federal tax benefit |
| 0.6 |
| 3.2 |
| 0.8 |
|
U.S. domestic production activities |
| (2.1) |
| (10.4) |
| (1.2) |
|
Other impact of foreign operations |
| (2.9) |
| 14.7 |
| 4.5 |
|
Other |
| (1.7) |
| (1.6) |
| 0.6 |
|
Effective income tax rate |
| 30.7 | % | 27.1 | % | 36.5 | % |
Effective tax rates differ from the U.S. federal statutory rate of 35.0 percent primarily due to state and foreign income taxes. The effective tax rate for the twelve months ended September 30, 2017 was also impacted by a reduction
65
to the benefit of the carryback of the federal net operating loss generated in the fiscal year ended September 30, 2017 resulting from the reduction of the Internal Revenue Code Section 199 deduction in the carryback year.
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, 20172022, 2021 and 2016,2020, we had accrued interest and penalties of $3.0 million, $2.9 million and $2.8 million, and $6.8 million, respectively.
A reconciliation of the change in our gross unrecognized tax benefits for the fiscal years ended September 30, 2017 and 2016 isare as follows:
|
|
|
|
|
|
|
| |||||||||||||||||
|
| September 30, |
| |||||||||||||||||||||
|
| 2017 |
| 2016 |
| |||||||||||||||||||
|
| (in thousands) |
| |||||||||||||||||||||
| (in thousands) | (in thousands) | 2022 | 2021 | 2020 | ||||||||||||||||||||
Unrecognized tax benefits at October 1, |
| $ | 9,551 |
| $ | 11,211 |
| Unrecognized tax benefits at October 1, | $ | 1,678 | $ | 13,440 | $ | 15,759 | ||||||||||
Gross decreases - tax positions in prior periods |
|
| (1) |
|
| — |
| |||||||||||||||||
Gross decreases - current period effect of tax positions |
|
| (170) |
|
| (1,173) |
| Gross decreases - current period effect of tax positions | (718) | (11,648) | (2,338) | |||||||||||||
Gross increases - current period effect of tax positions |
|
| 300 |
|
| 969 |
| Gross increases - current period effect of tax positions | — | — | 20 | |||||||||||||
Expiration of statute of limitations for assessments |
|
| (4,907) |
|
| (679) |
| Expiration of statute of limitations for assessments | — | (114) | (1) | |||||||||||||
Settlements |
|
| — |
|
| (777) |
| |||||||||||||||||
Unrecognized tax benefits at September 30, |
| $ | 4,773 |
| $ | 9,551 |
| Unrecognized tax benefits at September 30, | $ | 960 | $ | 1,678 | $ | 13,440 | ||||||||||
NOTE 6 SHAREHOLDERS’ EQUITY
| NOTE 9 SHAREHOLDERS’ EQUITY | ||||||||||||||
66
2022 FORM 10-K|82ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Accumulated Other Comprehensive Loss
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
|
| September 30, |
| September 30, | |||||||||||||||||||||||
|
| 2017 |
| 2016 |
| 2015 |
| ||||||||||||||||||||
|
| (in thousands) |
| ||||||||||||||||||||||||
| (in thousands) | (in thousands) | 2022 | 2021 | 2020 | |||||||||||||||||||||||
Pre-tax amounts: |
|
|
|
|
|
|
|
|
|
| Pre-tax amounts: | ||||||||||||||||
Unrealized appreciation on securities |
| $ | 31,700 |
| $ | 33,051 |
| $ | 27,021 |
| |||||||||||||||||
Unrealized actuarial loss |
|
| (28,873) |
|
| (34,112) |
|
| (30,144) |
| Unrealized actuarial loss | (15,703) | (26,268) | (33,923) | |||||||||||||
|
| $ | 2,827 |
| $ | (1,061) |
| $ | (3,123) |
| $ | (15,703) | $ | (26,268) | $ | (33,923) | |||||||||||
After-tax amounts: |
|
|
|
|
|
|
|
|
|
| After-tax amounts: | ||||||||||||||||
Unrealized appreciation on securities |
| $ | 20,070 |
| $ | 20,899 |
| $ | 17,201 |
| |||||||||||||||||
Unrealized actuarial loss |
|
| (17,770) |
|
| (21,103) |
|
| (18,578) |
| Unrealized actuarial loss | (12,072) | (20,244) | (26,188) | |||||||||||||
|
| $ | 2,300 |
| $ | (204) |
| $ | (1,377) |
| $ | (12,072) | $ | (20,244) | $ | (26,188) | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| Unrealized |
|
|
|
|
|
|
| |
|
| Appreciation |
|
|
|
|
|
|
| |
|
| (Depreciation) on |
| Defined |
|
|
|
| ||
|
| Available-for-sale |
| Benefit |
|
|
|
| ||
|
| Securities |
| Pension Plan |
| Total |
| |||
|
| (in thousands) |
| |||||||
Balance at September 30, 2016 |
| $ | 20,899 |
| $ | (21,103) |
| $ | (204) |
|
Other comprehensive loss before reclassifications |
|
| (829) |
|
| — |
|
| (829) |
|
Amounts reclassified from accumulated other comprehensive income |
|
| — |
|
| 3,333 |
|
| 3,333 |
|
Net current-period other comprehensive income (loss) |
|
| (829) |
|
| 3,333 |
|
| 2,504 |
|
Balance at September 30, 2017 |
| $ | 20,070 |
| $ | (17,770) |
| $ | 2,300 |
|
| (in thousands) | Defined Benefit Pension Plan | ||||
| Balance at September 30, 2021 | $ | (20,244) | |||
| Activity during the period | |||||
| Amounts reclassified from accumulated other comprehensive loss | 8,172 | ||||
| Net current-period other comprehensive income | 8,172 | ||||
| Balance at September 30, 2022 | $ | (12,072) | |||
| NOTE 10 REVENUE FROM CONTRACTS WITH CUSTOMERS | ||||||||||||||
2022 FORM 10-K|83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Amount |
|
|
| ||||
|
| Reclassified from |
|
|
| ||||
|
| Accumulated Other |
|
|
| ||||
|
| Comprehensive |
|
|
| ||||
Details About Accumulated Other |
| Income (Loss) |
| Affected Line Item in the |
| ||||
Comprehensive Income (Loss) Components |
| 2017 |
| 2016 |
| Consolidated Statements of Operations |
| ||
|
|
| (in thousands) |
|
|
| |||
Other-than-temporary impairment of available-for-sale securities |
| $ | — |
| $ | 1,509 |
| Loss on investment securities |
|
|
|
| — |
|
| (583) |
| Income tax provision |
|
|
| $ | — |
| $ | 926 |
| Net of tax |
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial loss on defined benefit pension plan |
| $ | 5,238 |
| $ | (3,968) |
| General and administrative |
|
|
|
| (1,905) |
|
| 1,443 |
| Income tax provision |
|
|
| $ | 3,333 |
| $ | (2,525) |
| Net of tax |
|
Total reclassifications for the period |
| $ | 3,333 |
| $ | (1,599) |
|
|
|
67
| (in thousands) | September 30, 2022 | September 30, 2021 | |||||||||
| Contract assets, net | $ | 6,319 | $ | 4,513 | |||||||
2022 FORM 10-K|84| (in thousands) | September 30, 2022 | ||||
| Contract liabilities balance at October 1, 2020 | $ | 8,636 | |||
| Payment received/accrued and deferred | 30,721 | ||||
| Revenue recognized during the period | (30,071) | ||||
| Contract liabilities balance at September 30, 2021 | 9,286 | ||||
| Payment received/accrued and deferred | 58,202 | ||||
| Revenue recognized during the period | (46,842) | ||||
| Contract liabilities balance at September 30, 2022 | $ | 20,646 | |||
NOTE 7 STOCK-BASED COMPENSATION
| NOTE 11 STOCK-BASED COMPENSATION | ||||||||||||||
2020 Plan.
|
|
|
|
|
|
|
|
|
|
|
|
| September 30, |
| |||||||
|
| 2017 |
| 2016 |
| 2015 |
| |||
|
| (in thousands) |
| |||||||
Compensation expense |
|
|
|
|
|
|
|
|
|
|
Stock options |
| $ | 7,439 |
| $ | 8,290 |
| $ | 8,846 |
|
Restricted stock |
|
| 18,744 |
|
| 16,093 |
|
| 16,349 |
|
|
| $ | 26,183 |
| $ | 24,383 |
| $ | 25,195 |
|
Benefits of tax deductions in excess of recognized compensation cost of $4.4 million, $0.9 millionSelling, General and $3.8 million are reported as a financing cash flow in theAdministrative Expense on our Consolidated Statements of Cash FlowsOperations, in fiscal years 2022, 2021 and 2020 is as follows:
| September 30, | |||||||||||||||||
| (in thousands) | 2022 | 2021 | 2020 | ||||||||||||||
| Stock-based compensation expense | |||||||||||||||||
| Drilling services operating | $ | 5,142 | $ | 5,927 | $ | 9,086 | |||||||||||
| Research and development | 1,551 | 1,271 | 765 | ||||||||||||||
| Selling, general and administrative | 21,339 | 20,660 | 29,960 | ||||||||||||||
Restructuring charges1 | — | — | (3,482) | ||||||||||||||
| $ | 28,032 | $ | 27,858 | $ | 36,329 | ||||||||||||
STOCK OPTIONS
Vesting requirements fordetails.
restricted stock. 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 torecognize compensation expense on a straight-line basis over the requisite service periodsvesting 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, 2022, there was $24.8 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 1.7 years.
2022 FORM 10-K|85| 2022 | 2021 | 2020 | |||||||||||||||||||||||||||||||||
| (shares in thousands) | Shares1 | Weighted-Average Grant Date Fair Value per Share | Shares1 | Weighted-Average Grant Date Fair Value per Share | Shares1 | Weighted-Average Grant Date Fair Value per Share | |||||||||||||||||||||||||||||
| Non-vested restricted stock outstanding at October 1, | 1,412 | $ | 37.36 | 1,280 | $ | 49.81 | 1,085 | $ | 61.28 | ||||||||||||||||||||||||||
| Granted | 744 | 25.83 | 701 | 25.61 | 781 | 39.99 | |||||||||||||||||||||||||||||
Vested2 | (610) | 39.81 | (534) | 51.79 | (501) | 59.46 | |||||||||||||||||||||||||||||
| Forfeited | (53) | 30.98 | (35) | 35.76 | (85) | 48.98 | |||||||||||||||||||||||||||||
| Non-vested restricted stock outstanding at September 30, | 1,493 | $ | 30.85 | 1,412 | $ | 37.36 | 1,280 | $ | 49.81 | ||||||||||||||||||||||||||
2022 FORM 10-K|86| 2022 | 2021 | 2020 | |||||||||||||||||||||||||||||||||
| (in thousands, except per share amounts) | Shares | 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 performance units outstanding at October 1, | 699 | $ | 41.55 | 337 | $ | 51.09 | 145 | $ | 62.66 | ||||||||||||||||||||||||||
| Granted | 227 | 30.12 | 313 | 29.77 | 259 | 43.40 | |||||||||||||||||||||||||||||
Vested 1 | (161) | 62.66 | — | — | — | — | |||||||||||||||||||||||||||||
| Dividend rights performance units credited | 15 | 32.82 | 60 | 49.64 | — | — | |||||||||||||||||||||||||||||
| Forfeited | (54) | 34.16 | (11) | 43.40 | (67) | 46.35 | |||||||||||||||||||||||||||||
Non-vested performance units outstanding September 30,2 | 726 | $ | 33.67 | 699 | $ | 41.55 | $ | 337 | $ | 51.09 | |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| 2017 |
| 2016 |
| 2015 |
|
Risk-free interest rate |
| 2.0 | % | 1.8 | % | 1.7 | % |
Expected stock volatility |
| 38.9 | % | 37.6 | % | 36.9 | % |
Dividend yield |
| 3.7 | % | 4.6 | % | 3.9 | % |
Expected term (in years) |
| 5.5 |
| 5.5 |
| 5.5 |
|
| 2022 | 2021 | 2020 | |||||||||||||||
Risk-free interest rate1 | 1.0 | % | 0.2 | % | 1.6 | % | |||||||||||
Expected stock volatility2 | 67.3 | % | 62.3 | % | 34.8 | % | |||||||||||
| Expected term (in years) | 3 | 3 | 3 | ||||||||||||||
2017 2016 2015 Weighted-Average Weighted-Average Weighted-Average Options Exercise Price Options Exercise Price Options Exercise Price Outstanding at October 1, 3,312 $ 51.74 2,776 $ 48.51 2,629 $ 43.46 Granted 396 76.61 876 58.25 420 68.83 Exercised (415) 38.04 (220) 31.52 (255) 28.46 Forfeited/Expired (15) 68.32 (120) 61.80 (18) 66.78 Outstanding on September 30, 3,278 $ 56.41 3,312 $ 51.74 2,776 $ 48.51 Exercisable on September 30, 2,167 $ 50.87 2,225 $ 46.66 2,014 $ 41.62 Shares available to grant 5,624 6,600 2,515 Outstanding Stock Options Exercisable Stock Options Weighted-Average Weighted-Average Weighted-Average Range of Exercise Prices Options Remaining Life Exercise Price Options Exercise Price $21.065 to $38.015 714 1.3 $ 30.63 714 $ 30.63 $47.29 to $59.76 1,618 6.3 $ 56.46 1,048 $ 55.80 $68.83 to $81.31 946 7.6 $ 75.77 405 $ 73.75 $21.065 to $81.31 3,278 5.6 $ 56.41 2,167 $ 50.87 2017 2016 2015 Weighted-Average Weighted-Average Weighted-Average Grant Date Fair Grant Date Fair Grant Date Fair Shares Value per Share Shares Value per Share Shares Value per Share Outstanding at October 1, 648 $ 64.24 668 $ 67.03 634 $ 64.03 Granted 292 78.69 294 58.25 275 68.83 Vested (1) (271) 63.81 (256) 64.75 (214) 60.80 Forfeited (10) 68.09 (58) 63.65 (27) 64.45 Outstanding on September 30, 659 $ 70.76 648 $ 64.24 668 $ 67.03 September 30, 2017 2016 2015 (in thousands) Numerator: Income (loss) from continuing operations $ (127,863) $ (52,990) $ 420,474 Loss from discontinued operations (349) (3,838) (47) Net income (loss) (128,212) (56,828) 420,427 Adjustment for basic earnings per share Earnings allocated to unvested shareholders (1,811) (1,858) (2,163) Numerator for basic earnings per share: From continuing operations (129,674) (54,848) 418,311 From discontinued operations (349) (3,838) (47) (130,023) (58,686) 418,264 Adjustment for diluted earnings per share: Effect of reallocating undistributed earnings of unvested shareholders — — 6 Numerator for diluted earnings per share: From continuing operations (129,674) (54,848) 418,317 From discontinued operations (349) (3,838) (47) $ (130,023) $ (58,686) $ 418,270 Denominator: Denominator for basic earnings per share - weighted-average shares 108,500 107,996 107,754 Effect of dilutive shares from stock options and restricted stock — 816 Denominator for diluted earnings per share - adjusted weighted-average shares 108,500 107,996 108,570 Basic earnings per common share: Income (loss) from continuing operations $ (1.20) $ (0.50) $ 3.88 Loss from discontinued operations — (0.04) — Net income (loss) $ (1.20) $ (0.54) $ 3.88 Diluted earnings per common share: Income (loss) from continuing operations $ (1.20) $ (0.50) $ 3.85 Loss from discontinued operations — (0.04) — Net income (loss) $ (1.20) $ (0.54) $ 3.85 2017 2016 2015 (in thousands, except per share amounts) Shares excluded from calculation of diluted earnings per share 1,008 1,788 667 Weighted-average price per share $ 74.38 $ 63.73 $ 72.85 Gross Gross Estimated Unrealized �� Unrealized Fair Cost Gains Losses Value (in thousands) Equity Securities: September 30, 2017 $ 38,473 $ 31,700 $ — $ 70,173 September 30, 2016 $ 38,473 $ 33,051 $ — $ 71,524 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: Fair Value (Level 1) (Level 2) (Level 3) (in thousands) Recurring fair value measurements: Short-term investments: Certificates of deposit $ 1,500 $ — $ 1,500 $ — Corporate and municipal debt securities 15,818 — 15,818 — U.S. government and federal agency securities 27,173 24,853 2,320 — Total short-term investments 44,491 24,853 19,638 — Cash and cash equivalents 521,375 521,375 — — Investments 70,173 70,173 — — Other current assets 32,439 32,189 250 — Other assets 6,695 6,695 — — Total assets measured at fair value $ 675,173 $ 655,285 $ 19,888 $ — Liabilities: Contingent earnout liability $ 14,879 $ — $ — $ 14,879 The following information presents the supplemental fair value information September 30, 2017 2016 (in millions) Carrying value of long-term fixed-rate debt $ 492.9 $ 491.8 Fair value of long-term fixed-rate debt $ 529.0 $ 529.6 2017 2016 (in thousands) Accumulated Benefit Obligation $ 109,976 $ 109,731 Changes in projected benefit obligations Projected benefit obligation at beginning of year $ 109,731 $ 107,417 Interest cost 4,053 4,266 Actuarial loss 3,633 15,051 Benefits paid (7,441) (17,003) Projected benefit obligation at end of year $ 109,976 $ 109,731 Change in plan assets Fair value of plan assets at beginning of year $ 90,748 $ 98,060 Actual return on plan assets 9,470 9,653 Employer contribution 39 38 Benefits paid (7,441) (17,003) Fair value of plan assets at end of year $ 92,816 $ 90,748 Funded status of the plan at end of year $ (17,160) $ (18,983) Accrued liabilities $ (45) $ (45) Noncurrent liabilities-other (17,115) (18,938) Net amount recognized $ (17,160) $ (18,983) Net actuarial loss $ (28,873) $ (34,112) The weighted average assumptions used for the pension calculations were as follows: Year Ended September 30, 2017 2016 2015 Discount rate for net periodic benefit costs 3.64 % 4.27 % 4.32 % Discount rate for year-end obligations 3.79 % 3.64 % 4.27 % Expected return on plan assets 6.17 % 5.89 % 6.26 % Year Ended September 30, 2017 2016 2015 (in thousands) Interest cost $ 4,053 $ 4,266 $ 4,584 Expected return on plan assets (5,130) (5,616) (6,855) Recognized net actuarial loss 2,891 2,083 1,308 Settlement 1,640 4,964 2,873 Net pension expense $ 3,454 $ 5,697 $ 1,910 a special eligibility window to be available to certain participants. During the period beginning on May 2, 2022 and ending on June 30, 2022, these participants could elect the limited lump sum distribution. This one-time lump sum was subsequently paid in August 2022 and resulted in a pension settlement charge of $7.8 million during the year ended September 30, 2022. Year Ended September 30, Year Ended September 30, 2018 2019 2020 2021 2022 2023 – 2027 Total $ 16,050 $ 6,844 $ 7,222 $ 5,591 $ 6,383 $ 32,723 $ 74,813 During the 2021 fiscal year, we implemented a glide-path strategy with a goal to reduce risk as certain funded levels are achieved and began aligning our fixed income exposure with our pension liabilities. The target allocation for Percentage of Plan Target Assets at Allocation September 30, Asset Category 2018 2017 2016 U.S. equities 45 % 50 % 62 % International equities 20 16 12 Fixed income 35 34 21 Real estate and other — — 5 Total 100 % 100 % 100 % Fair Value as of September 30, 2017 Total Level 1 Level 2 Level 3 (in thousands) Short-term investments $ 3,488 $ 3,488 $ — $ — Mutual funds: Domestic stock funds 18,377 18,377 — — Bond funds 18,357 18,357 — — Balanced funds 18,222 18,222 — — International stock funds 14,583 14,583 — — Total mutual funds 69,539 69,539 — — Domestic common stock 19,692 19,692 — — Oil and gas properties 97 — — 97 Total $ 92,816 $ 92,719 $ — $ 97 Fair Value as of September 30, 2016 Total Level 1 Level 2 Level 3 (in thousands) Short-term investments $ 467 $ 467 $ — $ — Mutual funds: Domestic stock funds 36,107 36,107 — — Bond funds 22,809 22,809 — — International stock funds 11,334 11,334 — — Total mutual funds 70,250 70,250 — — Domestic common stock 18,305 18,305 — — Foreign equity stock 1,549 1,549 — — Oil and gas properties 177 — — 177 Total $ 90,748 $ 90,571 $ — $ 177 Oil and Gas Properties Year Ended September 30, 2017 2016 (in thousands) Balance, beginning of year $ 177 $ 387 Unrealized losses relating to property still held at the reporting date (80) (210) Balance, end of year $ 97 $ 177 Substantially all employees on the September 30, 2017 2016 2015 (in thousands) Reserve for bad debt: Balance at October 1, $ 2,696 $ 6,181 $ 4,597 Provision for (recovery of) bad debt 2,016 (2,013) 6,034 (Write-off) recovery of bad debt 1,009 (1,472) (4,450) Balance at September 30, $ 5,721 $ 2,696 $ 6,181 September 30, 2017 2016 (in thousands) Accounts receivable, net of reserve: Trade receivables $ 398,348 $ 286,998 Income tax receivable 78,726 37,971 Insurance recovery receivable — 50,200 Total accounts receivable, net of reserve $ 477,074 $ 375,169 Prepaid expenses and other current assets: Restricted cash $ 32,439 $ 27,566 Deferred mobilization 6,458 9,913 Prepaid insurance 4,060 4,354 Prepaid value added tax 3,870 1,407 Prepaid income taxes — 26,138 Other 8,293 8,689 Total prepaid expenses and other current assets $ 55,120 $ 78,067 Accrued liabilities: Accrued operating costs $ 36,949 $ 17,009 Payroll and employee benefits 54,941 43,547 Taxes payable, other than income tax 35,638 31,443 Self-insurance liabilities 22,159 14,801 Deferred income 25,893 34,681 Deferred mobilization 9,828 17,923 Accrued income taxes 8,011 — Litigation and claims 1,779 70,535 Other 13,485 4,700 Total accrued liabilities $ 208,683 $ 234,639 Noncurrent liabilities — Other: Pension and other non-qualified retirement plans $ 37,989 $ 39,762 Self-insurance liabilities 29,037 21,651 Contingent earnout liability 14,879 — Deferred mobilization 7,689 24,781 Uncertain tax positions including interest and penalties 3,562 12,502 Other 8,253 4,085 Total noncurrent liabilities — other $ 101,409 $ 102,781 Year Ended September 30, 2017 2016 2015 (in thousands) Cash payments: Interest paid, net of amounts capitalized $ 22,936 $ 28,011 $ 11,651 Income taxes paid $ 3,749 $ 15,577 $ 131,128 September 30, 2017 2016 2015 (in thousands) Capital expenditures incurred $ 408,106 $ 241,290 $ 1,033,241 Additions incurred in prior year but paid for in current year 9,465 25,344 123,548 Additions incurred but not paid for as of the end of the period (20,004) (9,465) (25,344) Capital expenditures per Consolidated Statements of Cash Flows $ 397,567 $ 257,169 $ 1,131,445 Fiscal Year Amount (in thousands) 2018 $ 8,015 2019 5,454 2020 3,795 2021 2,944 2022 2,926 Thereafter 6,825 Total $ 29,959 Guarantee Arrangements Segment Performance restructuring charges. Summarized financial information of our reportable segments for Segment Depreciation Additions External Inter- Total Operating and Total to Long-Lived (in thousands) Sales Segment Sales Income (Loss) Amortization Assets Assets September 30, 2017 Contract Drilling U.S. Land $ 1,439,523 $ — $ 1,439,523 $ (94,880) $ 499,486 $ 4,967,074 $ 394,508 Offshore 136,263 — 136,263 24,201 11,764 99,533 2,847 International Land 212,972 — 212,972 (7,224) 53,622 413,392 3,400 1,788,758 — 1,788,758 (77,903) 564,872 5,479,999 400,755 Other 15,983 862 16,845 (9,449) 20,671 959,986 7,351 1,804,741 862 1,805,603 (87,352) 585,543 6,439,985 408,106 Eliminations — (862) (862) — — — — Total $ 1,804,741 $ — $ 1,804,741 $ (87,352) $ 585,543 $ 6,439,985 $ 408,106 Segment Additions External Inter- Total Operating Total to Long-Lived (in thousands) Sales Segment Sales Income (Loss) Depreciation Assets Assets September 30, 2016 Contract Drilling U.S. Land $ 1,242,462 $ — $ 1,242,462 $ 74,118 $ 508,237 $ 5,005,299 $ 209,156 Offshore 138,601 — 138,601 15,659 12,495 105,152 9,694 International Land 229,894 — 229,894 (14,086) 57,102 487,181 2,364 1,610,957 — 1,610,957 75,691 577,834 5,597,632 221,214 Other 13,275 855 14,130 (7,491) 20,753 1,234,323 20,076 1,624,232 855 1,625,087 68,200 598,587 6,831,955 241,290 Eliminations — (855) (855) — — — — Total $ 1,624,232 $ — $ 1,624,232 $ 68,200 $ 598,587 $ 6,831,955 $ 241,290 Segment Additions External Inter- Total Operating Total to Long-Lived (in thousands) Sales Segment Sales Income (Loss) Depreciation Assets Assets September 30, 2015 Contract Drilling U.S. Land $ 2,523,518 $ — $ 2,523,518 $ 698,375 $ 519,950 $ 5,429,179 $ 949,978 Offshore 241,666 — 241,666 68,002 11,659 118,852 16,100 International Land 382,331 — 382,331 (7,093) 57,334 565,712 39,645 3,147,515 — 3,147,515 759,284 588,943 6,113,743 1,005,723 Other 14,187 880 15,067 (10,911) 19,096 1,025,402 27,518 3,161,702 880 3,162,582 748,373 608,039 7,139,145 1,033,241 Eliminations — (880) (880) — — — — Total $ 3,161,702 $ — $ 3,161,702 $ 748,373 $ 608,039 $ 7,139,145 $ 1,033,241 Year Ended September 30, 2017 2016 2015 (in thousands) Segment operating income (loss) $ (87,352) $ 68,200 $ 748,373 Income from asset sales 20,627 9,896 11,834 Corporate general and administrative costs and corporate depreciation (105,816) (104,062) (88,244) Operating income (loss) (172,541) (25,966) 671,963 Other income (expense) Interest and dividend income 5,915 3,166 5,840 Interest expense (19,747) (22,913) (15,023) Loss on investment securities — (25,989) — Other 1,775 (965) (901) Total unallocated amounts (12,057) (46,701) (10,084) Income (loss) from continuing operations before income taxes $ (184,598) $ (72,667) $ 661,879 Year Ended September 30, 2017 2016 2015 (in thousands) Operating Revenues United States $ 1,591,769 $ 1,386,786 $ 2,750,043 Argentina 157,257 159,427 177,984 Colombia 37,554 20,488 70,076 Ecuador 6 4,948 30,987 Other Foreign 18,155 52,583 132,612 Total $ 1,804,741 $ 1,624,232 $ 3,161,702 Long-Lived Assets United States $ 4,686,235 $ 4,804,328 $ 5,149,315 Argentina 155,978 183,286 211,862 Colombia 81,798 91,815 102,401 Ecuador 22,298 438 28,918 Other Foreign 54,742 64,866 70,674 Total $ 5,001,051 $ 5,144,733 $ 5,563,170 Year Ended September 30, 2017 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Operating revenue $ — $ 1,575,787 $ 229,021 $ (67) $ 1,804,741 Operating costs and other 16,566 1,707,473 254,125 (882) 1,977,282 Operating income (loss) from continuing operations (16,566) (131,686) (25,104) 815 (172,541) Other income (expense), net (240) 7,342 1,403 (815) 7,690 Interest expense (398) (20,136) 787 — (19,747) Equity in net income (loss) of subsidiaries (116,212) (8,012) — 124,224 — Loss from continuing operations before income taxes (133,416) (152,492) (22,914) 124,224 (184,598) Income tax benefit (5,204) (38,600) (12,931) — (56,735) Loss from continuing operations (128,212) (113,892) (9,983) 124,224 (127,863) Income from discontinued operations before income taxes — — 3,285 — 3,285 Income tax provision — — 3,634 — 3,634 Loss from discontinued operations — — (349) — (349) Net loss $ (128,212) $ (113,892) $ (10,332) $ 124,224 $ (128,212) Year Ended September 30, 2017 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Net loss $ (128,212) $ (113,892) $ (10,332) $ 124,224 $ (128,212) Other comprehensive income, net of income taxes: Unrealized depreciation on securities, net — (829) — — (829) Minimum pension liability adjustments, net 860 2,473 — — 3,333 Other comprehensive income 860 1,644 — — 2,504 Comprehensive loss $ (127,352) $ (112,248) $ (10,332) $ 124,224 $ (125,708) Year Ended September 30, 2016 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Operating revenue $ — $ 1,373,511 $ 250,791 $ (70) $ 1,624,232 Operating costs and other 13,145 1,358,269 280,107 (1,323) 1,650,198 Operating income (loss) from continuing operations (13,145) 15,242 (29,316) 1,253 (25,966) Other expense, net (194) (22,243) (98) (1,253) (23,788) Interest expense (375) (20,256) (2,282) — (22,913) Equity in net income (loss) of subsidiaries (47,166) (14,472) — 61,638 — Loss from continuing operations before income taxes (60,880) (41,729) (31,696) 61,638 (72,667) Income tax provision (benefit) (4,052) 5,127 (20,752) — (19,677) Loss from continuing operations (56,828) (46,856) (10,944) 61,638 (52,990) Income from discontinued operations before income taxes — — 2,360 — 2,360 Income tax provision — — 6,198 — 6,198 Loss from discontinued operations — — (3,838) — (3,838) Net loss $ (56,828) $ (46,856) $ (14,782) $ 61,638 $ (56,828) Year Ended September 30, 2016 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Net loss $ (56,828) $ (46,856) $ (14,782) $ 61,638 $ (56,828) Other comprehensive loss, net of income taxes: Unrealized appreciation on securities, net — 2,772 — — 2,772 Reclassification of realized losses in net income, net — 926 — — 926 Minimum pension liability adjustments, net (63) (2,462) — — (2,525) Other comprehensive income (loss) (63) 1,236 — — 1,173 Comprehensive loss $ (56,891) $ (45,620) $ (14,782) $ 61,638 $ (55,655) Year Ended September 30, 2015 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Operating revenue $ — $ 2,735,863 $ 425,914 $ (75) $ 3,161,702 Operating costs and other 10,875 2,037,465 444,503 (3,104) 2,489,739 Operating income (loss) from continuing operations (10,875) 698,398 (18,589) 3,029 671,963 Other income (expense), net (91) 7,523 536 (3,029) 4,939 Interest expense (159) (8,955) (5,909) — (15,023) Equity in net income of subsidiaries 427,342 (13,128) — (414,214) — Income (loss) from continuing operations before income taxes 416,217 683,838 (23,962) (414,214) 661,879 Income tax provision (4,210) 258,536 (12,921) — 241,405 Income (loss) from continuing operations 420,427 425,302 (11,041) (414,214) 420,474 Loss from discontinued operations before income taxes — — (124) — (124) Income tax benefit — — (77) — (77) Loss from discontinued operations — — (47) — (47) Net income (loss) $ 420,427 $ 425,302 $ (11,088) $ (414,214) $ 420,427 Year Ended September 30, 2015 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Net income (loss) $ 420,427 $ 425,302 $ (11,088) $ (414,214) $ 420,427 Other comprehensive loss, net of income taxes: Unrealized depreciation on securities, net — (80,217) — — (80,217) Minimum pension liability adjustments, net (666) (3,620) — — (4,286) Other comprehensive loss (666) (83,837) — — (84,503) Comprehensive income (loss) $ 419,761 $ 341,465 $ (11,088) $ (414,214) $ 335,924 September 30, 2017 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated ASSETS Current assets: Cash and cash equivalents $ (587) $ 508,091 $ 13,871 $ — $ 521,375 Short-term investments — 44,491 — — 44,491 Accounts receivable, net of reserve 766 411,599 64,714 (5) 477,074 Inventories — 102,470 34,734 — 137,204 Prepaid expenses and other 12,200 6,383 36,979 (442) 55,120 Current assets of discontinued operations — — 3 — 3 Total current assets 12,379 1,073,034 150,301 (447) 1,235,267 Investments 13,853 70,173 — — 84,026 Property, plant and equipment, net 49,851 4,609,144 342,056 — 5,001,051 Intercompany 90,885 1,746,662 248,540 (2,086,087) — Goodwill — — 51,705 — 51,705 Intangible assets, net of amortization — — 50,785 — 50,785 Other assets 4,955 3,839 8,360 — 17,154 Investment in subsidiaries 5,470,050 183,382 — (5,653,432) — Total assets $ 5,641,973 $ 7,686,234 $ 851,747 $ (7,739,966) $ 6,439,988 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $ 82,360 $ 48,679 $ 4,589 $ — $ 135,628 Accrued liabilities 26,698 148,491 33,941 (447) 208,683 Current liabilities of discontinued operations — — 74 — 74 Total current liabilities 109,058 197,170 38,604 (447) 344,385 Noncurrent liabilities: Long-term debt — 492,902 — — 492,902 Deferred income taxes (11,201) 1,286,381 57,509 — 1,332,689 Intercompany 1,354,068 210,823 521,096 (2,085,987) — Other 25,457 43,471 32,481 — 101,409 Noncurrent liabilities of discontinued operations — — 4,012 — 4,012 Total noncurrent liabilities 1,368,324 2,033,577 615,098 (2,085,987) 1,931,012 Shareholders’ equity: Common stock 11,196 100 — (100) 11,196 Additional paid-in capital 487,248 52,437 1,039 (53,476) 487,248 Retained earnings 3,855,686 5,396,212 197,006 (5,593,218) 3,855,686 Accumulated other comprehensive income 2,300 6,738 — (6,738) 2,300 Treasury stock, at cost (191,839) — — — (191,839) Total shareholders’ equity 4,164,591 5,455,487 198,045 (5,653,532) 4,164,591 Total liabilities and shareholders’ equity $ 5,641,973 $ 7,686,234 $ 851,747 $ (7,739,966) $ 6,439,988 September 30, 2016 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated ASSETS Current assets: Cash and cash equivalents $ (955) $ 899,028 $ 7,488 $ — $ 905,561 Short-term investments — 44,148 — — 44,148 Accounts receivable, net of reserve 2 325,325 51,121 (1,279) 375,169 Inventories — 87,946 36,379 — 124,325 Prepaid expenses and other 6,928 20,625 71,753 (21,239) 78,067 Assets held for sale — 18,471 26,881 — 45,352 Current assets of discontinued operations — — 64 — 64 Total current assets 5,975 1,395,543 193,686 (22,518) 1,572,686 Investments 13,431 71,524 — — 84,955 Property, plant and equipment, net 59,173 4,716,736 368,824 — 5,144,733 Intercompany 16,147 1,399,323 260,939 (1,676,409) — Goodwill — — 4,718 — 4,718 Intangible assets, net of amortization — — 919 — 919 Other assets 233 267 23,508 — 24,008 Investment in subsidiaries 5,579,713 208,118 — (5,787,831) — Total assets $ 5,674,672 $ 7,791,511 $ 852,594 $ (7,486,758) $ 6,832,019 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $ 80,000 $ 10,868 $ 5,828 $ (1,274) $ 95,422 Accrued liabilities 1,822 176,985 35,598 20,234 234,639 Current liabilities of discontinued operations — — 59 — 59 Total current liabilities 81,822 187,853 41,485 18,960 330,120 Noncurrent liabilities: Long-term debt — 491,847 — — 491,847 Deferred income taxes (5,930) 1,303,324 45,062 — 1,342,456 Intercompany 1,016,673 209,276 491,838 (1,717,787) — Other 21,182 36,379 45,220 — 102,781 Noncurrent liabilities of discontinued operations — — 3,890 — 3,890 Total noncurrent liabilities 1,031,925 2,040,826 586,010 (1,717,787) 1,940,974 Shareholders’ equity: Common stock 11,140 100 — (100) 11,140 Additional paid-in capital 448,452 47,533 549 (48,082) 448,452 Retained earnings 4,289,807 5,510,105 224,550 (5,734,655) 4,289,807 Accumulated other comprehensive income (loss) (204) 5,094 — (5,094) (204) Treasury stock, at cost (188,270) — — — (188,270) Total shareholders’ equity 4,560,925 5,562,832 225,099 (5,787,931) 4,560,925 Total liabilities and shareholders’ equity $ 5,674,672 $ 7,791,511 $ 852,594 $ (7,486,758) $ 6,832,019 September 30, 2017 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (3,828) $ 349,929 $ 11,116 $ — $ 357,217 INVESTING ACTIVITIES: Capital expenditures (4,264) (387,392) (5,911) — (397,567) Purchase of short-term investments — (69,866) — — (69,866) Acquisition of business, net cash received (70,416) — — — (70,416) Proceeds from sale of short-term investments — 69,449 — — 69,449 Intercompany transfers 74,680 (74,680) — — — Proceeds from asset sales — 22,724 688 — 23,412 Net cash used in investing activities — (439,765) (5,223) — (444,988) FINANCING ACTIVITIES: Intercompany transfers 305,515 (305,515) — — — Dividends paid (305,515) — — — (305,515) Exercise of stock options, net of tax withholding 10,534 — — — 10,534 Tax withholdings related to net share settlements of restricted stock (5,848) — — — (5,848) Excess tax benefit from stock-based compensation (490) 4,414 490 — 4,414 Net cash provided by (used in) financing activities 4,196 (301,101) 490 — (296,415) Net increase (decrease) in cash and cash equivalents 368 (390,937) 6,383 — (384,186) Cash and cash equivalents, beginning of period (955) 899,028 7,488 — 905,561 Cash and cash equivalents, end of period $ (587) $ 508,091 $ 13,871 $ — $ 521,375 September 30, 2016 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ 3,521 $ 776,364 $ (26,288) $ — $ 753,597 INVESTING ACTIVITIES: Capital expenditures (16,119) (235,078) (5,972) — (257,169) Purchase of short-term investments — (57,276) — — (57,276) Proceeds from sale of short-term investments — 58,381 — — 58,381 Intercompany transfers 16,119 (16,119) — — — Proceeds from asset sales 9 19,237 2,599 — 21,845 Net cash provided by (used in) investing activities 9 (230,855) (3,373) — (234,219) FINANCING ACTIVITIES: Payments on long-term debt — (40,000) — — (40,000) Debt issuance costs — (1,111) — — (1,111) Intercompany transfers 300,152 (300,152) — — — Dividends paid (300,152) — — — (300,152) Exercise of stock options, net of tax withholding 1,040 — — — 1,040 Tax withholdings related to net share settlements of restricted stock (3,912) — — — (3,912) Excess tax benefit from stock-based compensation (775) 1,509 200 — 934 Net cash provided by (used in) financing activities (3,647) (339,754) 200 — (343,201) Net increase (decrease) in cash and cash equivalents (117) 205,755 (29,461) — 176,177 Cash and cash equivalents, beginning of period (838) 693,273 36,949 — 729,384 Cash and cash equivalents, end of period $ (955) $ 899,028 $ 7,488 $ — $ 905,561 September 30, 2015 Guarantor/ Issuer Non-Guarantor Total Parent Subsidiary Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ 3,623 $ 1,379,707 $ 45,244 $ — $ 1,428,574 INVESTING ACTIVITIES: Capital expenditures (24,818) (1,064,288) (42,339) — (1,131,445) Purchase of short-term investments — (45,607) — — (45,607) Intercompany transfers 24,818 (24,818) — — — Proceeds from asset sales 1 21,329 1,313 — 22,643 Net cash provided by (used in) investing activities 1 (1,113,384) (41,026) — (1,154,409) FINANCING ACTIVITIES: Payments on long-term debt — (40,000) — — (40,000) Proceeds from senior notes, net of discount — 497,125 — — 497,125 Debt issuance costs — (5,474) — — (5,474) Proceeds on short-term debt — — 1,002 — 1,002 Payments on short-term debt — — (1,002) — (1,002) Repurchase of common stock (59,654) — — — (59,654) Intercompany transfers 358,021 (358,021) — — — Dividends paid (298,367) — — — (298,367) Exercise of stock options, net of tax withholding 2,650 — — — 2,650 Tax withholdings related to net share settlements of restricted stock (5,140) — — — (5,140) Excess tax benefit from stock-based compensation 78 3,665 29 — 3,772 Net cash provided by (used in) financing activities (2,412) 97,295 29 — 94,912 Net increase in cash and cash equivalents 1,212 363,618 4,247 — 369,077 Cash and cash equivalents, beginning of period (2,050) 329,655 32,702 — 360,307 Cash and cash equivalents, end of period $ (838) $ 693,273 $ 36,949 $ — $ 729,384 2017 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Operating revenues $ 368,590 $ 405,283 $ 498,564 $ 532,304 Operating loss (49,164) (65,672) (28,028) (29,677) Loss from continuing operations (34,554) (48,473) (23,125) (21,711) Net loss (35,063) (48,818) (21,799) (22,532) Basic earnings per common share: Loss from continuing operations (0.33) (0.45) (0.22) (0.20) Net loss (0.33) (0.45) (0.21) (0.21) Diluted earnings per common share: Loss from continuing operations (0.33) (0.45) (0.22) (0.20) Net loss (0.33) (0.45) (0.21) (0.21) 2016 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Operating revenues $ 487,847 $ 438,191 $ 366,486 $ 331,708 Operating income (loss) 38,670 41,621 (13,256) (93,001) Income (loss) from continuing operations 15,898 25,174 (21,193) (72,869) Net income (loss) 16,002 21,205 (21,200) (72,835) Basic earnings per common share: Income (loss) from continuing operations 0.15 0.23 (0.20) (0.68) Net income (loss) 0.15 0.19 (0.20) (0.68) Diluted earnings per common share: Income (loss) from continuing operations 0.15 0.23 (0.20) (0.68) Net income (loss) 0.15 0.19 (0.20) (0.68) b)Management’s Report on Internal Control over Financial Reporting. 2022. Page 3.1 * * * * * Financial statements from this Form 10‑K formatted in *Management or Compensatory Plan or Arrangement. (This page has been left blank intentionally.) HELMERICH & PAYNE, INC. By: /s/ John W. Lindsay John W. Lindsay, Director, President and Chief Executive Officer Signature Title Date /s/ John W. Lindsay Director, President and Chief Executive November John W. Lindsay /s/ Senior Vice President and Chief Financial Officer November (Principal Financial Officer) /s/ Vice President and November (Principal Accounting Officer) /s/ Hans Helmerich Director and Chairman of the Board November Hans Helmerich /s/ Delaney M. Bellinger Director November Kevin G. Cramton /s/ Randy A. Foutch Director November Randy A. Foutch /s/ Jose R. Mas Director November Jose R. Mas /s/ Thomas A. Petrie Director November Thomas A. Petrie /s/ Donald F. Robillard, Jr. Director November Donald F. Robillard, Jr. /s/ Edward B. Rust, Jr. Director November Edward B. Rust, Jr. /s/ Mary M. VanDeWeghe Director November John D. ZeglisRisk-Free Interest Rate.(1)The risk-free interest rate is based on U.S. Treasury securities for the expected term of the option.Expected Volatility Rate.performance 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 option.Expected Dividend Yield. The dividend yield is based on our current dividend yield.68Expected Term. The expected term of the options granted represents the period of time that they are expected to be outstanding. We estimate the expected term of options granted based on historical experience with grants and exercises.Based on these calculations, the weighted-average fair value per option granted to acquire a share of common stock was $20.48, $13.12. and $16.39 per share for fiscal 2017, 2016 and 2015, respectively.The following summary reflects the stock option activity for our common stock and related information for fiscal 2017, 2016 and 2015 (shares in thousands):The following table summarizes information about stock options at September 30, 2017 (shares in thousands):At September 30, 2017, the weighted-average remaining life of exercisable stock options was 4.2 years and the aggregate intrinsic value was $16.1 million with a weighted-average exercise price of $50.87 per share.The number of options vested or expected to vest at September 30, 2017 was 3,224,548 with an aggregate intrinsic value of $16.2 million and a weighted-average exercise price of $56.19 per share.As of September 30, 2017, the unrecognized compensation cost related to the stock options was $6.6 million. That cost is expected to be recognized over a weighted-average period of 2.2 years.The total intrinsic value of options exercised during fiscal 2017, 2016 and 2015 was $13.1 million, $6.3 million and $10.7 million, respectively.The grant date fair value of shares vested during fiscal 2017, 2016 and 2015 was $6.7 million, $9.6 million and $8.1 million, respectively.RESTRICTED STOCKRestricted stock awards consist of our common stock and are time-vested over three to six years. We recognize compensation expense on a straight-line basis over the vesting period. The fair value of restricted stock awards under the 2016 Plan is determined based on the closing price of our shares on the grant date. As of September 30, 2017, there was $21.4 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 2.2 years.69A summary of the status of our restricted stock awards as of September 30, 2017, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2017, 2016 and 2015, is as follows (shares in thousands):(1)The number of restricted stock awards vested includes shares that we withheld on behalf of our employees to satisfy the statutory tax withholding requirements.NOTE 12 EARNINGS (LOSS) PER COMMON SHARE NOTE 8 EARNINGS PER SHAREASC 260, Earnings per Share,, requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividenddividends or dividend equivalents as a separate class of securities in calculating earnings per share. We have granted and expect to continue to grant to employees restricted stock grants that contain non-forfeitable rights to dividends. Such grants are considered participating securities under ASC 260. As such, we are required to include these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.Basic earnings per share is computed utilizing the two-class method and is calculated based on the weighted-average number of common shares outstanding during the periods presented.Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options, non-vested restricted stock and nonvestedperformance 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.70
stock grants that receive dividends, which are considered participating securities.2022 FORM 10-K|87The following table sets forth the computation of basic and diluted earnings (loss) per share:September 30, (in thousands, except per share amounts) 2022 2021 2020 Numerator: Income (loss) from continuing operations $ 6,552 $ (337,459) $ (496,392) Income from discontinued operations 401 11,309 1,895 Net income (loss) 6,953 (326,150) (494,497) Adjustment for basic earnings (loss) per share Losses allocated to unvested shareholders (1,508) (1,350) (2,647) Numerator for basic earnings (loss) per share: From continuing operations 5,044 (338,809) (499,039) From discontinued operations 401 11,309 1,895 5,445 (327,500) (497,144) Numerator for diluted earnings (loss) per share: From continuing operations 5,044 (338,809) (499,039) From discontinued operations 401 11,309 1,895 $ 5,445 $ (327,500) $ (497,144) Denominator: Denominator for basic earnings (loss) per share - weighted-average shares 105,891 107,818 108,009 Effect of dilutive shares from stock options, restricted stock and performance share units 664 — — Denominator for diluted earnings (loss) per share - adjusted weighted-average shares 106,555 107,818 108,009 Basic earnings (loss) per common share: Income (loss) from continuing operations $ 0.05 $ (3.14) $ (4.62) Income from discontinued operations — 0.10 0.02 Net income (loss) $ 0.05 $ (3.04) $ (4.60) Diluted earnings (loss) per common share: Income (loss) from continuing operations $ 0.05 $ (3.14) $ (4.62) Income from discontinued operations — 0.10 0.02 Net income (loss) $ 0.05 $ (3.04) $ (4.60) We had a net loss for fiscal 2017years 2021 and 2016.2020. 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 (loss) per share because their inclusion would have been anti-dilutive:71(in thousands, except per share amounts) 2022 2021 2020 Potentially dilutive shares excluded as anti-dilutive 2,543 3,894 4,004 Weighted-average price per share $ 62.36 $ 57.23 $ 60.72 NOTE 13 FAIR VALUE MEASUREMENT OF FINANCIAL INSTRUMENTS NOTE 9 FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTThe estimated fair value of our available-for-sale securities is primarily based on market quotes. The following is a summary of available-for-sale securities, which excludesWe have certain assets held in a Non-qualified Supplemental Savings Plan:On an ongoing basis we evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determinedand liabilities that are required to be other-than-temporary, an impairment charge is recordedmeasured and a new cost basis established. We review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery indisclosed at fair value. The cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold. During the fourth quarter of fiscal 2016, we recognized a $26.0 million other-than-temporary impairment charge on one of our securities. No impairment charges were recognized in fiscal 2017 or fiscal 2015. There were no realized gains or losses on sales of available-for-sale securities in fiscal 2017, 2016 or 2015. The assets held in a Non-qualified Supplemental Savings Plan are carried at fair value and totaled $13.9 million and $13.4 million at September 30, 2017 and 2016, 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.The majority of cash equivalents are invested in highly-liquid money-market mutual funds invested primarily in direct or indirect obligations of the U.S. Government. The carrying amount of cash and cash equivalents approximates fair value due to the short maturity of those investments.The carrying value of other current assets, accrued liabilities and other liabilities approximated fair value at September 30, 2017 and 2016.·Level 1 — Quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity can access at the measurement date.
•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 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.At September 30, 2017,2022 FORM 10-K|88•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 Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.Recurring Fair Value MeasurementsThe following tables summarize our financial instruments utilizingassets and liabilities measured at fair value on a recurring basis and indicate the level in the fair value hierarchy in which we classify the fair value measurement.September 30, 2022 (in thousands) Fair Value Level 1 Level 2 Level 3 Assets Short-term investments: Corporate debt securities $ 98,264 — 98,264 — U.S. government and federal agency securities 18,837 18,837 — — Total short-term investments 117,101 18,837 98,264 — Investments: Non-qualified supplemental savings plan 14,301 14,301 — — Equity investment in ADNOC Drilling 147,370 147,370 — — Debt security investment in Galileo 33,000 — — 33,000 Other debt securities 565 — — 565 Total investments 195,236 161,671 — 33,565 Liabilities Contingent consideration $ 4,022 $ — $ — $ 4,022 September 30, 2021 (in thousands) Fair Value Level 1 Level 2 Level 3 Assets Short-term investments: Corporate debt securities $ 192,950 $ — $ 192,950 $ — U.S. government and federal agency securities 5,750 5,750 — — Total short-term investments 198,700 5,750 192,950 — Investments: Non-qualified supplemental savings plan 18,221 18,221 — — Equity and debt securities 14,358 13,858 — 500 Cornerstone investment in ADNOC Drilling 100,000 100,000 — — Total investments 132,579 132,079 — 500 Liabilities Contingent consideration $ 2,996 $ — $ — $ 2,996 Short-term Investments Short-term investments primarily 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. These securities are recorded at fair value. Level 1 inputs include cash equivalents, equityU.S. agency issued debt securities with active markets and money market funds we have elected to classify as restricted assets that are included in72other current assets and other assets. Also included is cash denominated in a foreign currency that we have elected to classify as restricted to be used to settle the remaining liabilities of discontinued operations.funds. For these items, quoted current market prices are readily available.At September 30, 2017, Level 2 inputs include U.S. Agency issued debt securities, municipal bonds and corporate bonds measured using broker quotations that utilize observable market inputs. Also includedLong-term Investments Our long-term investments include debt and equity securities and assets held in a Non-Qualified Supplemental Savings Plan ("Savings Plan") and are recorded within Investments on our Consolidated Balance Sheets. Our assets that we hold in the Savings Plan are comprised of mutual funds that are measured using Level 1 inputs.2022 FORM 10-K|89During September 2021, the Company made a $100.0 million cornerstone investment in ADNOC Drilling in advance of its announced IPO, representing 159.7 million shares of ADNOC Drilling, equivalent to a one percent ownership stake and subject to a three-year lockup period. ADNOC Drilling’s IPO was completed on October 3, 2021, and its shares are listed and traded on the Abu Dhabi Securities Exchange. Our investment is classified as a long-term equity investment within Investments in our Consolidated Balance Sheets. We have applied the guidance in Topic 820, Fair Value Measurement, in the initial accounting of the transaction and the subsequent revaluation of the investment balance, concluding that the contractual restriction on the sale of an equity security that is publicly traded is not considered in measuring fair value. During the fiscal year ended September 30, 2022, we recognized a gain of $47.4 million on our Consolidated Statements of Operations, as a result of the change in fair value of the investment during the period. As of September 30, 2022, this investment is classified as a Level 1 investment based on the quoted stock price on the Abu Dhabi Securities Exchange.During the fiscal year ended September 30, 2022, the Company made a $33.0 million cornerstone investment in Galileo Holdco 2 Limited Technologies ("Galileo Holdco 2"), part of the group of companies known as Galileo Technologies (“Galileo”) in the form of a convertible note. Galileo specializes in liquification, natural gas compression and re-gasification modular systems and technologies to make the production, transportation, and consumption of natural gas, biomethane, and hydrogen more economically viable. The convertible note bears interest at 5.0 percent per annum with a maturity date of the earlier of April 2027 or an exit event (as defined in the agreement as either an initial public offering or a sale of Galileo). If the conversion option is exercised, the note would convert into common shares of the parent of Galileo Holdco 2 ("Galileo Parent"). We do not intend to sell this investment prior to its maturity date or an exit event. As of September 30, 2022, the fair value of the convertible note was approximately equal to the cost basis.All of our long-term debt securities, including our investment in Galileo, are classified as available-for-sale and are measured using Level 3 unobservable inputs based on the absence of market activity. The following table reconciles changes in the fair value of our Level 3 assets for the periods presented below:Year Ended (in thousands) 2022 2021 Assets at beginning of period $ 500 $ 500 Purchases 36,065 — Transfers out1(3,000) — Assets at end of period $ 33,565 $ 500 (1)Conversion from debt to equity securityThe following table provides quantitative information (in thousands) about our Level 3 unobservable significant inputs related to our debt security investment with Galileo at September 30, 2022:Fair Value Valuation Technique Unobservable Inputs $ 33,000 Black-Scholes-Merton model Discount rate 22.4 % Risk-free rate 4.0 % Equity volatility 92.5 % The above significant unobservable inputs are bank certificatessubject to change based on changes in economic and market conditions. The use of depositsignificant unobservable inputs creates uncertainty in the measurement of fair value as of the reporting date. Significant increases or decreases in the discount rate, risk-free rate, and equity volatility in isolation would result in a significantly lower or higher fair value measurement. It is not possible for us to predict the effect of future economic or market conditions on our estimated fair values.During the fiscal year ended September 30, 2022, we sold our remaining equity securities of approximately 467.5 thousand shares in Schlumberger, Ltd. and received proceeds of approximately $22.0 million. For the fiscal year ended September 30, 2022, we recorded a total gain of $8.2 million related to this investment, which included a $0.5 million gain recognized upon the sale of our investment and a $7.7 million gain as a result of the change in short-term investments or current assets.Ourfair value of the investment during the period. This activity is reported in Gain (Loss) on Investment Securities in our Consolidated Statements of Operations. This investment was classified as Level 1 and based on the quoted stock price.2022 FORM 10-K|90Contingent ConsiderationOther financial instruments measured using Level 3 unobservable inputs primarily consist of potential earnout payments associated with our business acquisitions in fiscal year 2019 and certain consulting services. Contingent consideration is recorded in Accrued Liabilities and Other Noncurrent Liabilities on the MOTIVE acquisition.Consolidated Balance Sheets based on the expected timing of milestone achievements. The valuation techniques used for determiningfollowing table reconciles changes in the fair value of our Level 3 liabilities for the potentialperiods presented below:(in thousands) 2022 2021 Liabilities at beginning of period $ 2,996 $ 9,123 Additions 1,500 — Total gains or losses: Included in earnings (224) 1,123 Settlements1(250) (7,250) Liabilities at end of period $ 4,022 $ 2,996 (1)Settlements represent earnout payments that have been paid or earned during the period.Nonrecurring Fair Value MeasurementsWe have certain assets that are described furthersubject to measurement at fair value on a nonrecurring basis. For these nonfinancial assets, measurement at fair value in Note 2.The following table summarizes ourperiods subsequent to their initial recognition is applicable if they are determined to be impaired. These assets generally include property, plant and equipment, goodwill, intangible assets, and operating lease right-of-use assets. If measured at fair value presented in the Consolidated Balance Sheets, these would generally be classified within Level 2 or 3 of the fair value hierarchy. Further details on any changes in valuation of these assets is provided in their respective footnotes.Other Equity SecuritiesWe also hold various other equity securities without readily determinable fair values. These equity securities are measured at cost, less any impairments, and recorded within Investments on our Consolidated Balance Sheet asSheets. As of September 30, 2017:2022 and 2021, the aggregate balance of these equity securities was $23.7 million and $2.9 million, respectively. During the fiscal year ended September 30, 2022 and 2021, we did not record any impairments on these investments.The following table reconciles changes in the balance of our equity securities, without readily determinable fair values, for the periods presented below:73Year Ended
September 30,(in thousands) 2022 2021 Assets at beginning of period $ 2,865 $ — Purchases 15,177 2,865 Transfers in13,000 — Unrealized gain included in earnings 2,703 — Assets at end of period $ 23,745 $ 2,865 (1)Conversion from debt to equity securityGeothermal InvestmentsAs of September 30, 2022 and 2021 the aggregate balance of our debt and equity security investments in geothermal energy was $23.7 million and $2.7 million, respectively. All of our geothermal investments are considered a Level 3 input based on the absence of market activity. These investments include assets measured on both a recurring and nonrecurring basis (discussed in the subsections above).Other Financial InstrumentsThe carrying amount of cash and cash equivalents and restricted cash approximates fair value due to the short-term nature of these items. 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 value of accounts receivable, other current and noncurrent assets, accounts payable, accrued liabilities and other liabilities approximated fair value at September 30, 2022 and 2021.2022 FORM 10-K|91aboutfor our current and long-term fixed-rate debt at September 30, 20172022 and September 30, 2016.September 30, (in millions) 2022 2021 Current portion of long-term debt, net1Carrying value $ — $ 483.5 Fair value — 541.6 Long-term debt, net Carrying value 542.6 542.0 Fair value 430.7 554.3 (1)On October 27, 2021 we redeemed the outstanding 2025 Notes. See Note 7—Debt to our Consolidated Financial Statements.The fair value forvalues of the $500 millioncurrent and long-term fixed-rate debt wasis based on broker quotes at September 30, 2017.2022 and 2021. The notes are classified within Level 2 of the fair value hierarchy as they are not actively traded in markets.NOTE 10 EMPLOYEE BENEFIT PLANSNOTE 14 EMPLOYEE BENEFIT PLANS We maintain a domestic noncontributory defined benefit pension plan covering certain U.S. employees who meet certain age and service requirements. In July 2003, we revised the Helmerich & Payne, Inc. Employee Retirement Plan (“Pension Plan”) to close the Pension Plan to new participants effective October 1, 2003, and reduce benefit accruals for current participants through September 30, 2006, at which time benefit accruals were discontinued and the Pension Plan was frozen.The following table provides a reconciliation of the changes in the pension benefit obligations and fair value of Pension Plan assets over the two-year period ended September 30, 20172022 and a statement of the funded status as of September 30, 20172022 and 2016:2021:September 30, (in thousands) (in thousands) 2022 2021 Accumulated benefit obligation Accumulated benefit obligation $ 60,463 $ 110,352 Changes in projected benefit obligations: Changes in projected benefit obligations: Projected benefit obligation at beginning of year $ 110,352 $ 116,146 Interest cost 2,537 2,925 Actuarial (gain) loss Actuarial (gain) loss (16,260) 7,111 Benefits paid (36,166) (15,749) Other Other — (81) Projected benefit obligation at end of year $ 60,463 $ 110,352 Change in plan assets: Change in plan assets: Fair value of plan assets at beginning of year $ 87,255 $ 86,103 Actual return on plan assets (14,324) 11,835 Employer contribution 5,000 5,066 Benefits paid (36,167) (15,749) Fair value of plan assets at end of year $ 41,764 $ 87,255 Funded status of the plan at end of year $ (18,699) $ (23,097) Fluctuations in actuarial gains and losses during the period are primarily due to changes in the discount rate and investment returns. The mortality table issued by the Society of Actuaries in October 2021 was used for the September 30, 2022 pension calculation.The amounts recognized in the Consolidated Balance Sheets at September 30, 20172022 and 20162021 are as follows (in thousands):follows:September 30, (in thousands) (in thousands) 2022 2021 Accrued liabilities $ — $ — Noncurrent liabilities-other (18,699) (23,097) Net amount recognized $ (18,699) $ (23,097) 2022 FORM 10-K|92The amounts recognized in Accumulated Other Comprehensive Income (Loss) at September 30, 20172022 and 2016,2021, and not yet reflected in net periodic benefit cost, are as follows (in thousands):follows:September 30, (in thousands) 2022 2021 Net actuarial loss $ 15,703 $ 26,268 The amount recognized in Accumulated Other Comprehensive Income (Loss) andUnrecognized actuarial gains/losses outside of a corridor of the greater of: 1) 10 percent of the Projected Benefit Obligation, or 2) the fair value of assets, are amortized into expense for the year on a straight-line basis over the average remaining service years of participants. Amortization is not yet reflected in periodic benefit cost expected to be amortized in next year’s periodic benefit cost is a net actuarial loss of $1.8 million.carried from year-to-year as the calculation resets each year.74September 30, 2022 2021 2020 Discount rate for net periodic benefit costs 2.75 % 2.66 % 3.16 % Discount rate for year-end obligations 5.44 % 2.75 % 2.66 % Expected return on plan assets 4.25 % 3.50 % 4.65 % The mortality table issued by the SocietyWe made a voluntary contribution of Actuaries$5.0 million in October 2017 was used for the September 30, 2017 pension calculation. The new mortality information reflects improved life expectanciesboth fiscal year 2022 and projected mortality improvements. We did not make any contributions to the Pension Plan in fiscal 2017.year 2021. In fiscal 2018,year 2023, we do not expect minimum contributions required by law to be needed. However, we may make contributions in fiscal 2018year 2023 if needed to fund unexpected distributions in lieu of liquidating pension assets.Components of the net periodic pension expense (benefit) were as follows:Year Ended September 30, (in thousands) (in thousands) 2022 2021 2020 Interest cost $ 2,537 $ 2,925 $ 3,598 Expected return on plan assets1Expected return on plan assets1(2,481) (3,722) (4,784) Recognized net actuarial loss 2,080 3,205 2,718 Settlement expense Settlement expense 9,031 3,448 3,001 Other Other — (81) — Net pension expense $ 11,167 $ 5,775 $ 4,533 (1)The Company uses the fair value of plan assets in determining the expected return on plan assets.We record settlement expense when benefit payments exceed the total annual serviceinterest costs. During March 2022, the Company's domestic noncontributory defined benefit pension plan was amended to include a limited lump sum distribution option and interest costs.The following table reflects the expected benefits to be paid from the Pension Plan in each of the next five fiscal years, and in the aggregate for the five years thereafter (in thousands).:Year Ended September 30, 2023 2023 2024 2025 2026 2027 2028 – 2032 Total 5,479 $ 5,049 $ 5,614 $ 5,088 $ 5,376 $ 22,827 $ 49,433 Included in the Pension Plan is an unfunded supplemental executive retirement plan.INVESTMENT STRATEGY AND ASSET ALLOCATIONInvestment Strategy and Asset AllocationOur 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.2022 FORM 10-K|93The 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.7520182023 and the asset allocation for the Pension Plan at the end of fiscal 2017years 2022 and 2016,2021, by asset category, were as follows:Target Allocation September 30, Asset Category 2023 2022 2021 U.S. equities 17 % 18 % 46 % International equities 12 11 17 Fixed income 71 71 37 Total 100 % 100 % 100 % PLAN ASSETSPlan AssetsThe fair value of Pension Plan assets at September 30, 20172022 and 2016,2021, summarized by level within the fair value hierarchy described in Note 9,13—Fair Value Measurement of Financial Instruments, are as follows:September 30, 2022 (in thousands) (in thousands) Total Level 1 Level 2 Level 3 Short-term investments $ 555 $ 555 $ — $ — Mutual funds: Domestic stock funds 7,318 7,318 — — Bond funds 29,093 29,093 — — International stock funds 4,739 4,739 — — Total mutual funds 41,150 41,150 — — Oil and gas properties 59 — — 59 Total $ 41,764 $ 41,705 $ — $ 59 September 30, 2021 (in thousands) (in thousands) Total Level 1 Level 2 Level 3 Short-term investments $ 2,444 $ 2,444 $ — $ — Mutual funds: Domestic stock funds 35,212 35,212 — — Bond funds 17,679 17,679 — — Balanced funds Balanced funds 17,520 17,520 — — International stock funds 14,379 14,379 — — Total mutual funds 84,790 84,790 — — Oil and gas properties 21 — — 21 Total $ 87,255 $ 87,234 $ — $ 21 TheAs of September 30, 2022 and 2021, the Pension Plan’s financial assets utilizing Level 1 inputs are valued based on quoted prices in active markets for identical securities. The Plan has no assets utilizing Level 2. TheAs of September 30, 2022 and 2021, 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.Defined Contribution Plan76The following table sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the years ended September 30, 2017 and 2016:DEFINED CONTRIBUTION PLANUnited StatesU.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 $16.6$24.8 million, $21.6$13.6 million and $24.8$23.8 million in fiscal 2017, 2016years 2022, 2021 and 2015,2020, respectively.During fiscal 2016, we determined that employee workforce reductions which started during 2015 and continued into 2016 due to reduced drilling activity resulted in a partial plan termination2022 FORM 10-K|94NOTE 11 SUPPLEMENTAL BALANCE SHEET INFORMATIONNOTE 15 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in our reserve for bad debtexpected credit losses on trade receivables for 2017, 2016fiscal years 2022, 2021 and 2015:2020:77September 30, (in thousands) 2022 2021 2020 Reserve for credit losses: Balance at October 1, $ 2,068 $ 1,820 $ 9,927 Provision for credit loss 1,077 203 2,203 (Write-off) recovery of credit loss (170) 45 (10,310) Balance at September 30, $ 2,975 $ 2,068 $ 1,820 2022 FORM 10-K|95Accounts receivable, prepaid expenses and other current assets, net, accrued liabilities and long-termnoncurrent liabilities —other at September 30, 2022 and 2021 consist of the following:September 30, (in thousands) (in thousands) 2022 2021 Accounts receivable, net of reserve: Trade receivables $ 430,944 $ 204,424 Income tax receivable 27,769 24,470 Total accounts receivable, net of reserve $ 458,713 $ 228,894 Prepaid expenses and other current assets, net: Prepaid expenses and other current assets, net: Deferred mobilization $ 5,048 $ 3,734 Prepaid insurance 7,498 7,313 Prepaid value added tax 6,628 7,682 Prepaid maintenance and rent Prepaid maintenance and rent 13,092 5,540 Accrued demobilization, net Accrued demobilization, net 6,319 4,513 Prepaid operating expenses Prepaid operating expenses — 17,959 Prepaid equipment Prepaid equipment 10,091 — Other 17,787 20,837 Total prepaid expenses and other current assets, net Total prepaid expenses and other current assets, net $ 66,463 $ 67,578 Accrued liabilities: Accrued operating costs $ 26,539 $ 20,872 Payroll and employee benefits 58,604 69,311 Taxes payable, other than income tax 26,786 25,329 Self-insurance liabilities 38,422 40,060 Deferred income 19,821 8,546 Advance payment for sale of property, plant and equipment Advance payment for sale of property, plant and equipment — 86,524 Deferred mobilization revenue Deferred mobilization revenue 8,959 4,662 Accrued income taxes 40,833 881 Contingent liability Contingent liability 2,750 5,985 Operating lease liability Operating lease liability 12,382 12,624 Other 6,055 8,698 Total accrued liabilities $ 241,151 $ 283,492 Noncurrent liabilities — Other: Pension and other non-qualified retirement plans $ 40,423 $ 47,263 Self-insurance liabilities 38,422 40,910 Contingent liability Contingent liability 1,272 1,759 Deferred revenue Deferred revenue 3,162 1,003 Uncertain tax positions including interest and penalties 2,381 2,578 Operating lease liability Operating lease liability 27,350 37,864 Payroll tax deferral1Payroll tax deferral1— 15,424 Other 377 956 Total noncurrent liabilities — other $ 113,387 $ 147,757 NOTE 12 SUPPLEMENTAL CASH FLOW INFORMATIONCapital expenditures(1)Deferral related to the provisions within the Coronavirus Aid, Relief, and Economic Security Act, enacted on the Consolidated Statements of Cash FlowsMarch 27, 2020, which allows for the years ended September 30, 2017, 2016 and 2015 do not include additions which have been incurred but not paid for asdeferral of the endemployer share of the year. The78following table reconciles total capital expenditures incurred to total capital expenditures in the Consolidated Statements of Cash Flows:NOTE 13 RISK FACTORSCONCENTRATION OF CREDITFinancial instruments which potentially subject us to concentrations of credit risk consist primarily of temporary cash investments, short-term investments and trade receivables. We place temporary cash investments in the U.S. with established financial institutions and invest in a diversified portfolio of highly rated, short-term money market instruments. Our trade receivables, primarily with established companies in the oil and gas industry, may impact credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. International sales also present various risks including governmental activities that may limit or disrupt markets and restrict the movement of funds. Most of our international sales, however, are to large international or government-owned national oil companies. We perform credit evaluations of customers and do not typically require collateral in support for trade receivables. We provide an allowance for doubtful accounts, when necessary, to cover estimated credit losses. Such an allowance is based on management’s knowledge of customer accounts.VOLATILITY OF MARKETOur 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 much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices.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 drilling services. This reduction in spending could have a material adverse effect on our operations.SELF-INSURANCEWe self-insure a significant portion of expected losses relating to worker’s compensation, general liability and automobile liability. Generally, deductibles range from $1 million to $5 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates are recorded for incurred outstanding liabilities for worker’s compensation, general liability claims and claims that are incurred but not reported. Estimates are based on adjusters’ estimates, historic experience and statistical methods that we believe are reliable. 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.79We have a wholly-owned captive insurance company which finances a significant portion of the physical damage risk on company-owned drilling rigs as well as international casualty deductibles.INTERNATIONAL DRILLING OPERATIONSInternational 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 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.Estimates from published sources indicate that Argentina is a highly inflationary country, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period based on inflation data published by the respective governments. Regardless, all of our foreign subsidiaries use the U.S. dollar as the functional currency and local currency monetary assets are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. Because of the impact of local laws, our future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. While we believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms acceptable to us.NOTE 14 COMMITMENTS AND CONTINGENCIESPURCHASE OBLIGATIONSNOTE 16 COMMITMENTS AND CONTINGENCIES Purchase CommitmentsEquipment, parts and supplies are ordered in advance to promote efficient construction and capital improvement progress. At September 30, 2017,2022, we had purchase commitments for equipment, parts and supplies of approximately $56.2$148.6 million.LEASESAt September 30, 2017, we were leasing approximately 221,021 square feet of office space near downtown Tulsa, Oklahoma. We alsoLease Obligations Refer to Note 5—Leases for additional information on our lease other office space and equipment for use in operations. For operating leases that contain built-in pre-determined rent escalations, rent expense is recognized on a straight-line basis over the life of the lease. Leasehold improvements are capitalized and amortized over the lease term. Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of a year at September 30, 2017 are as follows:80
obligations.2022 FORM 10-K|96Total rent expense was $14.0 million, $13.5 million and $13.6 million for fiscal 2017, 2016 and 2015, respectively.CONTINGENCIESVarious legal actions, the majority of which arise in the ordinary course of business, are pending. We maintain insurance against certain business risks subject to certain deductibles. With the exception of the matters discussed below, none of these legal actions are expected to have a material adverse effect on our financial condition, cash flows or results of operations.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.ContingenciesDuring 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 andor recognize income until realized. The property and equipment of our Venezuelan subsidiary was seized by the Venezuelan government on June 30, 2010. Our wholly-owned subsidiaries, Helmerich & Payne International Drilling Co. (“HPIDC”("HPIDC"), and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. (“PDVSA”) and PDVSA Petroleo, S.A. (“Petroleo”). Our subsidiaries seek, seeking damages for the takingseizure of their Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No gain contingencies are recognized in our Consolidated Financial Statements.On November 8, 2013, the United States District Court for the Eastern District of Louisiana approved the previously disclosed October 30, 2013 plea agreement between our wholly owned subsidiary, HPIDC, and the United States Department of Justice, United States Attorney’s Office for the Eastern District of Louisiana (“DOJ”). The court’s approval of the plea agreement resolved the DOJ’s investigation into certain choke manifold testing irregularities that occurred in 2010 at one of HPIDC's offshore platform rigs in the Gulf of Mexico. We also engaged in discussions with the Inspector General’s office of the Department of Interior (“DOI”) regarding the same events that were the subject of the DOJ’s investigation. Although we do not presently anticipate any further action by the DOI in this matter, we can provide no assurance as to the timing or eventual outcome of the DOI’s consideration of the matter. On or about April 28, 2015, Joshua Keel ("Keel"),In May 2018, an employee of our subsidiary, HPIDC, filedwas involved in a petitioncar accident in his personal vehicle while not clocked in for work. The accident resulted in a fatality of a passenger in the 152nd Judicial Court for Harris County, Texas (Cause No. 2015-24531) against us, our customer and several subcontractors of our customer.other vehicle. The suit arose from injuries Keel sustained in an accident that occurred while he was working on HPIDC Rig 223 in New Mexico in July of 2014. Keel alleged that the defendants were negligent and negligent per se, acted recklessly, intentionally, and/or with an utterly wanton disregard for the rights and safetyestate of the plaintiffvictim, his widow and sought damages wellchildren subsequently brought a lawsuit against the employee and HPIDC in excess of $100 million. Pursuant toTexas State District Court in January 2020. In February 2022, trial began in the termsmatter and the jury reached a verdict against HPIDC and our employee for approximately $126.0 million, including interest. In March 2022, the court entered a judgment consistent with the findings of the drilling contract between HPIDC and its customer, HPIDC indemnified most of the co-defendants in the lawsuit. On September 14, 2016, the parties in the Keel litigation entered into a global settlement agreement, which was approved by the court on October 14, 2016. The total settlement amount of $72 million, accrued at September 30, 2016, was paid byjury. In April 2022, the Company and its insurers filed post-trial motions, none of which were granted by the trial judge. However, on behalfJune 23, 2022, Plaintiffs' counsel filed a Voluntary Remittitur with the trial court, which formally reduced the verdict to $60.0 million. The Company and its insurers are currently filing motions to appeal the judgement. Accordingly, the Company cannot make an estimate of all defendants, in December 2016, pursuantthe possible loss at this time. As of September 30, 2022, we have incurred expenses, mainly legal fees, against the insurance deductible. At this time, we believe our insurance policies will be responsive to industry standard contractual indemnification obligations. NOTE 15 SEGMENT INFORMATIONWe operate principallythe amounts over our $3.0 million insurance deductible and that foreseeable exposures to the Company exceeding the deductible will be recovered through insurance. Accordingly, we do not believe this exposure will exceed our insurance coverage limits. The Company and its subsidiaries are parties to various other pending legal actions arising in the contractordinary 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 17 BUSINESS SEGMENTS AND GEOGRAPHIC INFORMATION Description of the BusinessWe are a performance-driven drilling industry. The contractsolutions and technologies company based in Tulsa, Oklahoma with operations in all major U.S. onshore oil and gas producing 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. We focus on offering our customers an integrated solutions-based approach by combining proprietary rig technology, automation software, and digital expertise into our rig operations rather than a product-based offering, such as a rig or separate technology package. Our contract drilling business includesservices operations are organized into the following reportable operating business segments: U.S. Land,North America Solutions, Offshore Gulf of Mexico and International Land. Solutions. Each reportable operating segment is a strategic business unit that is managed separately. Our primary international areas of operation include Argentina, Bahrain, Colombia, U.A.E.separately, and other South American and Middle Eastern countries. Other includes additional non-reportable operating segments. Revenues included in Other consist of rental income as well as technology services provided for directional drilling process. Consolidatedconsolidated revenues and expenses reflect the elimination of all material intercompany transactions.81
Our real estate operations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are included in "Other." External revenues included in “Other” primarily consist of rental income.2022 FORM 10-K|97We evaluate segment performance based on income or loss from continuing operations (segment operating income)income (loss)) before income taxes which includes:·revenues from external and internal customers
•Revenues from external and internal customers·direct operating costs
•Direct operating costs·depreciation and
•Depreciation and amortization·allocated general and administrative costs•Allocated general and administrative costs•Asset impairment charges•Restructuring chargesbut excludes gain on reimbursement of drilling equipment, other (gain) loss on sale of assets, and corporate selling, general and administrative costs, for othercorporate depreciation, income from asset sales and other corporate income and expense.General and administrative costs are allocated to the segments based primarily on specific identification and, to the extent that such identification is not practical, on other methods may be used which we believe to be a reasonable reflection of the utilization of services provided.Segment operating income for all segments is a non-GAAP financial measure of our performance, as it excludes certain general and administrative expenses, corporate depreciation, income from asset sales and other corporate income and expense. We consider segment operating income to be an important supplemental measure of operating performance for presenting trends in our core businesses. We use this measure to facilitate period-to-period comparisons in operating performance of our reportable segments in the aggregate by eliminating items that affect comparability between periods. We believe that segment operating income is useful to investors because it provides a means to evaluate the operating performance of the segments on an ongoing basis using criteria that are used by our internal decision makers. Additionally, it highlights operating trends and aids analytical comparisons. However, segment operating income has limitations and should not be used as an alternative to operating income or loss, a performance measure determined in accordance with GAAP, as it excludes certain costs that may affect our operating performance in future periods. 82continuing operations for each of the fiscal years ended September 30, 2017, 20162022, 2021 and 20152020 is shown in the following table:tables:83September 30, 2022 (in thousands) North America Solutions Offshore Gulf of Mexico International Solutions Other Eliminations Total External sales $ 1,788,167 $ 125,465 $ 136,072 $ 9,240 $ — $ 2,058,944 Intersegment — — — 57,047 (57,047) — Total sales 1,788,167 125,465 136,072 66,287 (57,047) 2,058,944 Segment operating income (loss) 121,893 23,214 (138) 12,720 (6,422) 151,267 Depreciation and amortization 375,250 9,175 4,156 1,701 — 390,282 September 30, 2021 (in thousands) North America Solutions Offshore Gulf of Mexico International Solutions Other Eliminations Total External sales $ 1,026,364 $ 126,399 $ 57,917 $ 7,888 $ — $ 1,218,568 Intersegment — — — 35,416 (35,416) — Total sales 1,026,364 126,399 57,917 43,304 (35,416) 1,218,568 Segment operating income (loss) (287,176) 15,969 (21,003) (9,704) (1,580) (303,494) Depreciation and amortization 392,415 10,557 2,013 1,426 — 406,411 2022 FORM 10-K|98September 30, 2020 (in thousands) North America Solutions Offshore Gulf of Mexico International Solutions Other Eliminations Total External sales $ 1,474,380 $ 143,149 $ 144,185 $ 12,213 $ — $ 1,773,927 Intersegment — — — 36,901 (36,901) — Total sales 1,474,380 143,149 144,185 49,114 (36,901) 1,773,927 Segment operating income (loss) (393,902) 7,478 (162,368) 4,403 — (544,389) Depreciation and amortization 438,039 11,681 17,531 1,241 — 468,492 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:Year Ended September 30, (in thousands) (in thousands) 2022 2021 2020 Segment operating income (loss) $ 151,267 $ (303,494) $ (544,389) Gain on reimbursement of drilling equipment Gain on reimbursement of drilling equipment 29,443 12,322 26,959 Other gain (loss) on sale of assets Other gain (loss) on sale of assets 5,432 (11,280) 19,816 Corporate selling, general and administrative costs, corporate depreciation and corporate restructuring charges Corporate selling, general and administrative costs, corporate depreciation and corporate restructuring charges (140,850) (126,097) (122,573) Operating income (loss) from continuing operations Operating income (loss) from continuing operations 45,292 (428,549) (620,187) Other income (expense) Interest and dividend income 18,090 10,254 7,304 Interest expense (19,203) (23,955) (24,474) Gain (loss) on investment securities Gain (loss) on investment securities 57,937 6,727 (8,720) Gain on sale of subsidiary Gain on sale of subsidiary — — 14,963 Loss on extinguishment of debt Loss on extinguishment of debt (60,083) — — Other (11,115) (5,657) (5,384) Total unallocated amounts (14,374) (12,631) (16,311) Income (loss) from continuing operations before income taxes $ 30,918 $ (441,180) $ (636,498) The following table reconciles segment total assets to total assets as reported on the Consolidated Balance Sheets:Year Ended September 30, (in thousands) 2022 2021 Total assets1North America Solutions $ 3,406,824 $ 3,418,569 Offshore Gulf of Mexico 80,993 84,580 International Solutions 330,974 269,820 Other 120,305 95,398 3,939,096 3,868,367 Investments and corporate operations 416,435 1,165,761 Total assets from continuing operations $ 4,355,531 $ 5,034,128 (1)Assets by segment exclude investments in subsidiaries and intersegment activity.2022 FORM 10-K|99The following table presents revenues from external customers and long-lived assets by country based on the location of service provided:Year Ended September 30, (in thousands) (in thousands) 2022 2021 2020 Operating revenues Operating revenues United States $ 1,920,026 $ 1,158,230 $ 1,626,407 Argentina 91,385 27,855 84,402 Bahrain Bahrain 16,986 27,435 28,653 United Arab Emirates United Arab Emirates 5,698 957 24,716 Colombia 22,003 1,674 6,414 Other foreign Other foreign 2,846 2,417 3,335 Total $ 2,058,944 $ 1,218,568 $ 1,773,927 Long-lived assets are comprised ofThe following table presents property, plant and equipment.Revenues from one customer accounted for approximately 9 percent, 8 percent and 6 percentequipment by country based on the location of total operating revenues during the years ended September 30, 2017, 2016 and 2015, respectively. Revenues from another customer accounted for approximately 9 percent, 9 percent and 5 percent of total operating revenues during the years ended September 30, 2017, 2016 and 2015, respectively. Collectively, the receivables from these customers were $59.0 million and $58.1 million at September 30, 2017 and 2016, respectively.NOTE 16 GUARANTOR AND NON-GUARANTOR FINANCIAL INFORMATIONIn March 2015, Helmerich & Payne International Drilling Co. (“the issuer”), a 100 percent owned subsidiary of Helmerich & Payne, Inc. (“parent”, “the guarantor”), issued senior unsecured notes with an aggregate principal amount of $500.0 million. The notes are fully and unconditionally guaranteed by the parent. No subsidiaries of the parent84Year Ended September 30, (in thousands) 2022 2021 Property, plant and equipment, net United States $ 2,872,145 $ 3,042,140 Argentina 54,789 50,944 Colombia 21,809 22,959 Other foreign 12,066 11,244 Total $ 2,960,809 $ 3,127,287 NOTE 18 RESTRUCTURING CHARGES currently guarantee the notes, subject to certain provisions that if any subsidiary guarantees certain other debt of the issuer or parent, then such subsidiary will provide a guarantee of the obligation under the notes. In connection with the notes, we are providing the following condensed consolidating financial information in accordance with the Securities and Exchange Commission disclosure requirements. Each entity in the consolidating financial information follows the same accounting policies as described in the consolidated financial statements. Condensed consolidating financial information for the issuer, Helmerich & Payne International Drilling Co., and parent, guarantor, Helmerich & Payne, Inc. is shown in the tables below.CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS(in thousands)CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(in thousands)85CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS(in thousands)CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(in thousands)86CONDENSED CONSOLIDATING STATEMENTS OF INCOME(in thousands)CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME(in thousands)87CONDENSED CONSOLIDATING BALANCE SHEETS(in thousands)88CONDENSED CONSOLIDATING BALANCE SHEETS(in thousands)89CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS(in thousands)90CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS(in thousands)91CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS(in thousands)NOTE 17 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)(in thousands, except per share amounts)92The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding.In the first quarter of fiscal 2017, net loss includes an after-tax gain from the sale of assets of $0.6 million, $0.01 per share on a diluted basis.InDuring the second quarter of fiscal 2017, net loss includes an after-tax gain fromyear 2021, we reorganized our IT operations and moved select IT functions to a managed service provider. Costs incurred as of September 30, 2021 in connection with the salerestructuring are primarily comprised of assets of $10.1 million, $0.09 per share on a diluted basis.Inone-time severance benefits to employees who were involuntarily terminated. During the third quarter of fiscal 2017, net loss includes an after-tax gain fromyear 2021, we commenced a voluntary separation program at our local office in Argentina for which we incurred severance charges for employees who were voluntarily terminated.Additionally, during fiscal year 2021, we continued to take measures to lower our cost structure based on activity levels. During fiscal year 2021, we incurred one-time moving related expenses primarily due to the saledownsizing and relocation of assets of $1.3 million, $0.01 per share on a diluted basis.Inour Houston assembly facility and various storage yards used for idle rigs. These charges are included in other restructuring expenses within the fourth quarter of fiscal 2017, net loss includes an after-tax gain fromtable below.The following table summarizes the sale of assets of $2.3 million, $0.02 per share on a diluted basis.InCompany's restructuring charges incurred during the first quarter of fiscal 2016, net income includes an after-tax gain from the sale of assets of $2.9 million, $0.03 per share on a diluted basis and an after-tax loss related to currency exchange losses of approximately $5.4 million, $0.05 per share on a diluted basis. In the second quarter of fiscal 2016, net income includes an after-tax gain from the sale of assets of $1.5 million, $0.01 per share on a diluted basis.Inyear ended September 30, 2021:Year Ended September 30, 2021 (in thousands) North America Solutions International Solutions Corporate Total Employee termination benefits $ 54 $ 207 $ 1,215 $ 1,476 Other restructuring expenses 3,815 — 635 $ 4,450 Total restructuring charges $ 3,869 207 $ 1,850 $ 5,926 Beginning in the third quarter of fiscal 2016, net loss includes an after-tax impairment charge, primarilyyear 2020, we implemented cost controls and began evaluating further measures to respond to the combination of weakened commodity prices, uncertainties related to used drilling equipment,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 approximately $2.9 million, $0.03restructuring 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 during the fiscal year ended September 30, 2020 in connection with the restructuring were primarily comprised of severance benefits to employees who were voluntarily or involuntarily terminated, benefits related to forfeitures and costs related to modification of stock-based compensation awards.2022 FORM 10-K|100The following table summarizes the Company's restructuring charges incurred during the year ended September 30, 2020:Year Ended September 30, 2020 (in thousands) North America Solutions Offshore Gulf of Mexico International Solutions Other Corporate G&A Total Employee termination benefits $ 10,041 $ 1,432 $ 2,991 $ 321 $ 4,745 $ 19,530 Stock-based compensation benefit (3,036) (178) (11) (61) (197) (3,483) Total restructuring charges $ 7,005 $ 1,254 $ 2,980 $ 260 $ 4,548 $ 16,047 These expenses are recorded within restructuring charges on our Consolidated Statements of Operations for the fiscal years ended September 30, 2021 and 2020.NOTE 19 SUBSEQUENT EVENTS As part of our commitment to return cash to shareholders, on October 17, 2022, the Board of Directors of the Company declared a quarterly cash supplemental dividend of $0.235 per share on a diluted basis.In the fourth quarterCompany’s common stock, payable on December 1, 2022, to stockholders of fiscal 2016, net loss includes an after-tax gain fromrecord at the saleclose of assetsbusiness on November 15, 2022. The payable date and record date of $1.4 million, $0.01this supplemental dividend coincides with the dates applicable to the Company’s base dividend of $0.25 per share, which was declared on September 7, 2022.In October 2022, we purchased a diluted basis.In$14.1 million equity investment, representing approximately 106 million shares, in Tamboran Resources Limited ("Tamboran"). Tamboran's shares are listed and publicly traded on the fourth quarterAustralian Securities Exchange. Additionally, during September 2022, we entered into a fixed-term drilling services agreement with Tamboran. The expected $30.3 million of revenue to be earned over the term of the contract is included within our contract backlog as of September 30, 2022, as mobilization is expected to commence in fiscal 2016, net loss includes an after-tax loss from an other-than-temporary impairment of available-for-sale securities of $15.9 million, $0.15 loss per share on a diluted basis.In the fourth quarter of fiscal 2016, net loss includes an after-tax loss from a litigation settlement of $12.0 million, $0.11 loss per share on a diluted basis.932022 FORM 10-K|101Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.a)Evaluation of Disclosure Controls and Procedures.As of the end of the period covered by this Form 10‑K, ourOur management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a‑15(e) or 15d‑15(e) under the Securities Exchange Act of 1934, as amended) as of September 30, 2017.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 SEC filings, is recorded, processed, summarized and reported within the time periods specific in the SEC’s rules, regulations, and forms and is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, concluded that:
as appropriate to allow timely decisions regarding financial disclosure. 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 disclosure controls and procedures are effective at ensuring that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and·our disclosure controls and procedures operate such that important information flows to appropriate collection and disclosure points in a timely manner and are effective to ensure that such information is accumulated and communicated to our management, and made known to our Chief Executive Officer and Chief Financial Officer, particularly during the period when this Form 10‑K was prepared, as appropriate to allow timely decision regarding the required disclosure.Our management 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, as amended. Our internal control over financial reporting is 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. Our internal control over financial reporting includes those policies and procedures that:(i)pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;(ii)provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and the Board of Directors; and(iii)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.Management, with the participationA copy of our Chief Executive Officer and ChiefManagement’s Report on Internal Control over Financial Officer, conducted an evaluationReporting is included in Item 8 of this Form 10-K.c) Attestation Report of the effectiveness of internal control over financial reporting based on criteria established in the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring OrganizationsIndependent Registered Public Accounting Firm.A copy of the Treadway Commission. This evaluation included reviewreport of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Although there are inherent limitations in the effectiveness of any system of internal control over financial reporting, based on this evaluation, management has concluded thatErnst & Young LLP, our internal control over financial reporting was effective as of September 30, 2017.94The independent registered public accounting firm, that audited our financial statements, Ernst & Young LLP, has issued an attestation report on our internal control over financial reporting. This report appears below at the endis included in Item 8 of this Item 9A of Form 10‑K.c)10-K.d) Changes in Internal Control Over Financial Reporting.There werehave been no material changes in our internal controlcontrols over financial reporting during our fourth fiscal quarter of 2017the year ended September 30, 2022 that have materially affected, or areis reasonably likely to materially affect, our internal controlcontrols over financial reporting.***95Report of Independent Registered Public Accounting FirmThe Board of Directors and Shareholders ofHelmerich & Payne, Inc.We have audited Helmerich & Payne, Inc.’s internal control over financial reporting as of September 30, 2017, 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”). Helmerich & Payne, Inc.’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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.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.In our opinion, Helmerich & Payne, Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2017, based on the COSO criteria.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2017, and our report dated November 22, 2017 expressed an unqualified opinion thereon./s/ Ernst & Young LLPTulsa, OklahomaNovember 22, 201796ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS Not applicable.PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEITEM 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” and “Section 16(a) Beneficial Ownership Reporting Compliance”“Executive Officers” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 7, 2018,in calendar year 2023, to be filed with the SEC notno later than 120 days after September 30, 2017. Information required under this item with respect to executive officers under Item 401 of Regulation S‑K appears under “Executive Officers of the Company” in Part I of this Form 10‑K.We have adopted a Code of Ethics for our Principal Executive Officer and Senior Financial Officers. The text of this code is located on our website under “Corporate Governance.“http://ir.helmerichpayne.com/websites/helmerichandpayne/English/4500.html.” Our Internet address is www.hpinc.com.www.helmerichpayne.com. We intend to disclose any amendments to or waivers from this code on our website.2022 FORM 10-K|102The 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”“Compensation Committee Report” and ending with the caption “Potential Payments Upon Change‑in‑Control”“Pay Ratio Disclosure”, as well as under the captions “Director Compensation in Fiscal 2017”Year 2022” and “Corporate Governance—Compensation Committee Interlocks and Insider Participation” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 7, 2018,in calendar year 2023, to be filed with the SEC notno later than 120 days after September 30, 2017.2022.Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERSITEM 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 7, 2018,in calendar year 2023, to be filed with the SEC notno later than 120 days after September 30, 2017.2022.Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCEITEM 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 7, 2018,in calendar year 2023, to be filed with the SEC notno later than 120 days after September 30, 2017.2022.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 7, 2018,in calendar year 2023, to be filed with the SEC notno later than 120 days after September 30, 2017.2022.97PART IV Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULESITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 1.Financial Statements:Statements: Our consolidated financial statements, together with the notes thereto and the report of Ernst & Young LLP dated November 22, 2017,16, 2022, are listed below and included in Item 8—“Financial “Financial Statements and Supplementary Data” of this Form 10‑K.47Consolidated Balance Sheets at September 30, 2022 and 2021Consolidated Statements of Operations for the Years Ended September 30, 2017, 20162022, 2021 and 2015202048Consolidated Statements of Comprehensive Income (Loss) (Loss)for the Years Ended September 30, 2017, 20162022, 2021 and 201520204950Consolidated Statements of Shareholders’ Equity for the Years Ended September 30, 2017, 20162022, 2021 and 2015202052Consolidated Statements of Cash Flows for the Years Ended September 30, 2017, 20162022, 2021 and 2015202053542.Financial Statement Schedules: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.Exhibits: The following documents are included as exhibits to this Form 10‑K. Exhibits incorporated by reference are duly noted as such.2.1
2022 FORM 10-K|10398991002022 FORM 10-K|104*10.29*10.11 10.3010.3110.3210.3310.3410.35*10.17*10.18 *10.19 *10.20 12.1*10.21*10.22 *10.23 *10.24 21*10.25*10.26 2022 FORM 10-K|105*10.27 *10.28 21 23.1 31.1 31.2 32.101 XBRL:Inline eXtensible Business Reporting Language (XBRL): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (ii)(iii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Shareholders’ Equity, (v) the Consolidated Statements of Cash Flows and (vi) the Notes to Consolidated Financial Statements.104 Cover Page Interactive Date File (formatted as Inline XBRL and contained in Exhibit 101). 101ITEM 16. FORM 10-K SUMMARY None.2022 FORM 10-K|1061021032022 FORM 10-K|107Pursuant 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:Date: November 16, 2022 Date: November 22, 20172022 FORM 10-K|108Pursuant 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:22, 2017Officer (Principal(Principal Executive Officer)Juan Pablo Tardio22, 2017Juan Pablo TardioGordon K. HelmController (Principal22, 2017Gordon K. Helm22, 2017Director November 16, 2022 Delaney Bellinger /s/ Belgacem Chariag Director November 16, 2022 Belgacem Chariag /s/ Kevin G. Cramton 22, 201722, 2017/s/ Paula MarshallDirectorNovember 22, 2017Paula Marshall22, 201722, 201722, 201722, 2017Director November 16, 2022 Mary M. VanDeWeghe /s/ John D. Zeglis 22, 20171042022 FORM 10-K|109