For the transition period from to
Commission file number
1‑42211-4221
(Exact
Namename of
Registrantregistrant as
Specifiedspecified in
Its Charter)its charter) | | | | | |
Delaware | 73‑0679879
73-0679879 |
(State or Other Jurisdictionother jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Incorporation or Organization)
| |
1437 S. Boulder Ave., Suite 1400, Tulsa, Oklahoma
| 74119‑3623
|
(Address of Principal Executive Offices)
| (Zip Code)
|
(918) 742‑5531
|
Registrant’s telephone number, including area code
|
1437 South Boulder Avenue, Suite 1400, Tulsa, Oklahoma 74119
(Address of principal executive offices) (Zip Code)
(918) 742-5531
(Registrant’s telephone number, including area code)
N/A
(Former name, former address and former fiscal year,
if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | |
Title of Each Classeach class | Trading symbol(s) | Name of Each Exchangeeach exchange on Which Registered which registered |
Common Stock ($0.10 par value) | HP | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the Registrant is a
well‑knownwell-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
☐ No ☒Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
☒ No ☐Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes
☒ No ☐Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☐
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a
non‑non‑accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b‑12b‑2 of the Exchange Act. | | | | | | | | | | | | | | | | | |
| Large accelerated filer | ☒ | Accelerated filer | ☐ | Non‑accelerated filer | ☐ |
Smaller reporting company☐ | ☐ | Accelerated filer ☐
Emerging Growth Company ☐ | ☐ | Non‑accelerated filer ☐
| |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
☐Indicate by check mark whether the Registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the Registrant is a shell company (as defined in Rule
12b‑12b‑2 of the Exchange Act). Yes ☐ No ☒At March
29, 2018,31, 2021, the last business day of the Registrant’s most recently completed second fiscal quarter, the aggregate market value of the Registrant’s common stock held by
non‑non‑affiliates was approximately $7.25$2.91 billion based on the closing price of such stock on the New York Stock Exchange on such date of $66.56.$26.96.
Number of shares of common stock outstanding at November 8,
2018: 109,038,462DOCUMENTS INCORPORATED BY REFERENCE
2021: 108,002,263
Portions of the Registrant’s
20192022 Proxy Statement for the Annual Meeting of Stockholders to be held
on March 5, 2019in calendar year 2022 are incorporated by reference into Part III of this Form
10‑10‑K. The 20192022 Proxy Statement will be filed with the U.S. Securities and Exchange Commission (“SEC”) within 120 days after the end of the fiscal year to which this Form 10‑10‑K relates.
HELMERICH & PAYNE, INC.
INDEX TO FORM 10‑K
YEAR ENDED SEPTEMBER 30, 2018
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2021 FORM 10-K|2
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
| | | | | | | | | | | | | | |
| Cautionary Note Regarding Forward-Looking Statements |
This Annual Report on Form
10‑10‑K (“Form 10‑10‑K”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Form 10-K, including without limitation, statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “predict,” “project,” “target,” “continue,” or the negative thereof or similar terminology. Forward-looking statements are based upon current plans, estimates, and expectations that are subject to risks, uncertainties, and assumptions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Actual results may vary materially from those indicated or anticipated by such forward-looking statements. The inclusion of such statements should not be regarded as a representation that such plans, estimates, or expectations will be achieved.
These forward-looking statements include, among others, such things as:
| ·
| | the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures, and the number of rigs we plan to construct or acquire;
|
•our business strategy; | ·
| | the volatility of future oil and natural gas prices;
|
•estimates of our revenues, income, earnings per share, and market share; | ·
| | changes in future levels of drilling activity and capital expenditures by our customers, whether as a result of global capital markets and liquidity, changes in prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs, or increase our capital expenditures and the construction or acquisition of rigs;
|
•our capital structure and our ability to return cash to stockholders through dividends or share repurchases; | ·
| | changes in worldwide rig supply and demand, competition, or technology;
|
•the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures; | ·
| | possible cancellation, suspension, renegotiation or termination (with or without cause) of our contracts as a result of general or industry-specific economic conditions, mechanical difficulties, performance or other reasons;
|
•the volatility of future oil and natural gas prices; | ·
| | expansion and growth of our business and operations;
|
•the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing nations (together, “OPEC+”) with respect to production levels or other matters related to the prices of oil and natural gas; | ·
| | our belief that the final outcome of our legal proceedings will not materially affect our financial results;
|
•changes in future levels of drilling activity and capital expenditures by our customers, whether as a result of global capital markets and liquidity, changes in prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs, or increase our capital expenditures and the construction or acquisition of rigs; | ·
| | impact of federal and state legislative and regulatory actions affecting our costs and increasing operation restrictions or delay and other adverse impacts on our business;
|
•the effect, impact, potential duration or other implications of the novel strain of coronavirus ("COVID-19") pandemic, the ongoing recovery from and response to the oil price collapse in 2020, and any expectations we may have with respect thereto; | ·
| | environmental or other liabilities, risks, damages or losses, whether related to storms or hurricanes (including wreckage or debris removal), collisions, grounding, blowouts, fires, explosions, other accidents, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;
|
•changes in worldwide rig supply and demand, competition, or technology; | ·
| | our financial condition and liquidity;
|
•possible cancellation, suspension, renegotiation or termination (with or without cause) of our contracts as a result of general or industry-specific economic conditions, mechanical difficulties, performance or other reasons; | ·
| | tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes; and
|
•expansion and growth of our business and operations; | ·
| | potential long-lived asset impairments.
|
•our belief that the final outcome of our legal proceedings will not materially affect our financial results;•impact of federal and state legislative and regulatory actions and policies, affecting our costs and increasing operation restrictions or delay and other adverse impacts on our business;
•environmental or other liabilities, risks, damages or losses, whether related to storms or hurricanes (including wreckage or debris removal), collisions, grounding, blowouts, fires, explosions, other accidents, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;
•our financial condition and liquidity;
•tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;
•potential long-lived asset impairments; and
•our sustainability strategy.
2021 FORM 10-K|3
Important factors that could cause actual results to differ materially from our expectations or results discussed in the
forward‑forward‑looking statements are disclosed in this Form 10‑10‑K under Item 1A— “Risk Factors,” as well as inFactors” and Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All subsequent written and oral forward‑forward‑looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by such cautionary statements. Because of the underlying risks and uncertainties, we caution you against placing undue reliance on these forward-looking statements. We assume no duty to update or revise these forward‑forward‑looking statements based on changes in internal estimates, expectations or otherwise, except as required by law.This summary briefly lists the principal risks and uncertainties facing our business, which are only a select portion of those risks. A more complete discussion of those risks and uncertainties is set forth in this Form 10‑K under Item 1A— “Risk Factors.” Additional risks not presently known to us or that we currently deem immaterial may also affect us. If any of these risks occur, our business, financial condition or results of operations could be materially and adversely affected. Our business is subject to the following principal risks and uncertainties:
Business and Operating Risks
•the impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic;
•the level of activity in the oil and natural gas industry;
•the drilling services and solutions business is highly competitive;
•new technologies may cause our drilling methods and equipment to become less competitive;
•our drilling and technology related operations are subject to a number of operational risks, and we are not fully insured against all of these risks;
•cybersecurity risks;
•risks associated with our acquisitions, dispositions and investments;
•our reliance on management and competition for experienced personnel;
•the effect of the loss of one or a number of our large customers;
•our current backlog of drilling services and solutions revenue may not be ultimately realized;
•risks associated with our contracts with national oil companies;
•our dependence on a limited number of vendors;
•shortages of drilling equipment and supplies;
•unionization efforts and labor regulations in certain countries in which we operate;
•the effect of improvements in or new discoveries of alternative technologies;
•risks associated with doing business in certain foreign countries;
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;
•the impact of a downgrade in our credit ratings;
•our ability to access capital markets could be limited;
•our inability to generate cash to service all of our indebtedness;
2021 FORM 10-K|4
PART I
Legal and Regulatory Risks
•the impact of the regulation of greenhouse gases and climate change;
•the impact of new legislation and regulatory initiatives related to hydraulic fracturing or other aspects of the oil and gas industry;
•failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti-bribery legislation;
•complex and evolving laws and regulations regarding privacy and data protection;
•government policies, mandates and regulations specifically affecting the energy sector and related industries;
•the impact of legal claims and litigation;
•the effect of additional tax liabilities, limitations on our use of net operating losses and tax credits and/or our significant net deferred tax liability;
•failure to comply with or changes to governmental and environmental laws;
Risks Related to Our Common Stock and Corporate Structure
•we may reduce or suspend our dividend in the future;
•the market price of our common stock may be highly volatile; and
•certain provisions of our corporate governing documents could make an acquisition of our company more difficult; and
•the effect of public and investor sentiment towards climate change, fossil fuels and other environmental, social and governance ("ESG") matters on the price of our common stock
Helmerich & Payne, Inc.
(which,("H&P," which, together with its subsidiaries, is identified as the “Company,” “we,” “us” or “our,” except where stated or the context requires otherwise) was incorporated under the laws of the State of Delaware on February 3, 1940 and is successor to a business originally organized in 1920. We provide performance-driven drilling
services and technologiessolutions that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. We are an important vendor for a number of oil and gas exploration and production companies, but we focus
exclusivelyprimarily on the drilling segment of the oil and gas production value chain.
Our global contract drilling business is composed of three reportable business segments: U.S. Land, Offshore and International Land. During the fiscal year ended September 30, 2018, our U.S. Land operations were located in Colorado, Louisiana, Ohio, Oklahoma, New Mexico, North Dakota, Pennsylvania, Texas, Utah, West Virginia and Wyoming. Our Offshore operations were conducted in the Gulf of Mexico. Our International Land operations had rigs located in five international locations during fiscal year 2018: Argentina, Bahrain, Colombia, Ecuador and United Arab Emirates (“U.A.E.”).
Wetechnology services focus on researchdeveloping, promoting and development of technologycommercializing technologies designed to improve the efficiency and accuracy of drilling operations, as well as wellbore quality and placement.
Our global business is composed of three reportable business segments: North America Solutions, Offshore Gulf of Mexico, and International Solutions. During the fiscal year ended September 30, 2021, our North America Solutions operations were primarily located in Colorado, Louisiana, Montana, Nevada, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, Utah, West Virginia and Wyoming. Our Offshore Gulf of Mexico operations were conducted in Louisiana and in U.S. federal waters in the Gulf of Mexico. Our International Solutions operations had rigs located in four international locations during fiscal year 2021: Argentina, Bahrain, Colombia and United Arab Emirates (“U.A.E.”).
We also own and operate a limited number of commercial real estate properties located in Tulsa, Oklahoma. Our real estate investments include a shopping center containing approximately 390,000 leasable square feet and approximately 176 acres of undeveloped real estate. Our research and development endeavors include
ongoing improvementsboth internal development and external acquisition of
developing technologies. Our wholly-owned captive insurance companies (the “Captives”) are used to insure the deductibles for our
rig fleetworkers’ compensation, general liability and
advancementsautomobile liability insurance programs. The Company and the Captives maintain excess property and casualty reinsurance programs with third-party insurers in
rig technology, including our FlexApp™ services, developmentan effort to limit the financial impact of
a proprietary Bit Guidance System™, offered as a service through MOTIVE Drilling Technologies, Inc. (“MOTIVE”), which we acquired in June 2017, and 3D geomagnetic reference modeling and measurement while drilling survey correction services, offered through Magnetic Variation Services, LLC (“MagVAR”), which we acquired in December 2017. We also own, develop and operate limited commercial real estate properties.significant events covered under these programs. Our real estate investments, whichoperations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are located exclusively within Tulsa, Oklahoma, include a shopping center containing approximately 441,000 leasable square feet, multi‑tenant industrial warehouse properties containing approximately one million leasable square feet and approximately 210 acres of undeveloped real estate.
2021 FORM 10-K|5
The following map
and table sets forth certain information concerningshows the number of working rigs by basin in our
U.S. land drilling rigsNorth America Solutions reportable segment as of September 30,
2018:
| | | | | | | | | | |
U.S. Land Fleet |
| AC (FlexRig3) (1) | AC (FlexRig4) (2) | AC (FlexRig5) (3) | SCR (4) | Total Fleet |
Current | Total | Rigs | Total | Rigs | Total | Rigs | Total | Rigs | Total | Rigs |
Location | Available | Contracted | Available (5) | Contracted | Available | Contracted | Available | Contracted | Available | Contracted |
TX | 141 | 110 | 38 | 1 | 22 | 22 | 1 | — | 202 | 133 |
OK | 20 | 18 | 1 | 1 | 15 | 15 | — | — | 36 | 34 |
NM | 27 | 26 | — | — | 2 | 2 | — | — | 29 | 28 |
ND | 13 | 4 | 11 | — | 3 | 3 | — | — | 27 | 7 |
CO | — | — | 21 | 6 | 2 | 2 | — | — | 23 | 8 |
PA | 5 | 2 | 4 | — | 2 | 1 | — | — | 11 | 3 |
LA | 7 | 7 | — | — | 2 | 1 | 1 | — | 10 | 8 |
OH | 4 | 3 | — | — | 2 | 2 | — | — | 6 | 5 |
WY | 2 | 2 | — | — | 2 | 2 | — | — | 4 | 4 |
UT | — | — | 1 | 1 | — | — | — | — | 1 | 1 |
WV | — | — | — | — | 1 | 1 | — | — | 1 | 1 |
Totals | 219 | 172 | 76 | 9 | 53 | 51 | 2 | — | 350 | 232 |
| (1)
| | The FlexRig3 is equipped with a 750,000 lb. mast, Varco TDS-11HP top drive and Gardner Denver PZ-11 mud pumps. It can be equipped with an optional skidding or walking system for pad work and 7,500 psi high pressure mud system. This rig is capable of horizontal and vertical drilling.
|
2021: | (2)
| | The FlexRig4 model is a trailerized rig designed to be highly mobile. The rig is equipped with a 300,000 lb. or 500,000 lb. mast, 400HP top drive and Gardner Denver HS-2250 or PZ-11 mud pumps. Range 3 drill pipe is used without setback. The rig is capable of horizontal and vertical drilling.
|
| (3)
| | The FlexRig5 base configuration includes a 100 foot, bi-directional skidding system with an optional package that extends to 200 feet. It includes a 750,000 lb. mast, Varco TDS-11HP top drive and Gardner Denver mud pumps. An optional third pump and 7,500 psi high pressure mud system can also be used. This rig is capable of horizontal and vertical drilling.
|
| (4)
| | A silicon-controlled-rectifier (“SCR”) system converts alternate current (“AC”) produced by one or more AC generator sets into direct current (“DC”).
|
| (5)
| | Two Domestic FlexRig4 rigs completed their conversions to Domestic FlexRig3’s in the fourth fiscal quarter of 2018. Two Domestic FlexRig4 rigs began the conversion process and three additional rigs are planned for conversion to be completed during the first fiscal quarter of 2019.
|
We operate a large fleet of super-spec rigs, which are generally considered to include rig specifications of an AC drive with 1,500 horse power drawworks, 750,000 lbs. hookload ratings, 7,500 psi mud circulating systems and multiple-well pad drilling systems. The chart below depicts the states in which our super-spec rigs operate.
The following table sets forth certain information concerning our offshoreNorth America Solutions drilling rigs as of September 30, 2018:
| | | | | | |
Offshore Fleet |
Current | Shallow Water (1) | Deep Water (1) | Total Fleet |
Location | Total Available | Rigs Contracted | Total Available | Rigs Contracted | Total Available | Rigs Contracted |
Louisiana (2) | 2 | - | - | - | 2 | - |
Gulf of Mexico | 3 | 3 | 3 | 3 | 6 | 6 |
Totals | 5 | 3 | 3 | 3 | 8 | 6 |
| (1)
| | Deep water rigs operate on floating facilities and shallow water rigs operate on fixed facilities.
|
2021: | (2)
| | Rigs are idle, stacked on land and not in state waters.
|
| | | | | | | | | | | | | | | | | | | | |
 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 | 139 | 66 | 3 | — | 142 | 66 |
| NM | 36 | 26 | — | — | 36 | 26 |
| OK | 25 | 10 | 1 | — | 26 | 10 |
| ND | 8 | 6 | — | — | 8 | 6 |
| LA | 5 | 5 | — | — | 5 | 5 |
| OH | 4 | 1 | — | — | 4 | 1 |
| PA | 4 | 2 | — | — | 4 | 2 |
| UT | 3 | 3 | — | — | 3 | 3 |
| CO | 1 | 1 | 2 | 2 | 3 | 3 |
| WV | 2 | 2 | — | — | 2 | 2 |
| MT | 1 | 1 | — | — | 1 | 1 |
| NV | 1 | 1 | — | — | 1 | 1 |
| WY | 1 | 1 | — | — | 1 | 1 |
| Totals | 230 | 125 | 6 | 2 | 236 | 127 |
(1)AC drive, minimum of 1,500 horsepower drawworks, minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and multiple-well pad capability.
(2)AC drive, 1,500 horsepower drawworks, 500,000 or 750,000 lbs. hookload rating, 5,000 or 7,500 psi mud circulating system, may or may not have multiple-well pad capability.
2021 FORM 10-K|6
The following table sets forth certain information concerning our
international landOffshore Gulf of Mexico drilling rigs as of September 30,
2018:2021: | | | | | | | | | | |
International Land Fleet |
| AC (FlexRig3) | AC (FlexRig4) | Other AC | SCR (1) | Total Fleet |
Current | Total | Rigs | Total | Rigs | Total | Rigs | Total | Rigs | Total | Rigs |
Location | Available | Contracted | Available | Contracted | Available | Contracted | Available | Contracted | Available | Contracted |
Argentina | 11 | 11 | 4 | 4 | - | - | 4 | - | 19 | 15 |
Colombia | 2 | 2 | 3 | - | 1 | 1 | 2 | 2 | 8 | 5 |
Bahrain | - | - | 3 | 1 | - | - | - | - | 3 | 1 |
U.A.E. | 2 | - | - | - | - | - | - | - | 2 | - |
Totals | 15 | 13 | 10 | 5 | 1 | 1 | 6 | 2 | 32 | 21 |
| | | | | | | | | | | | | | | | | | | | |
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 |
(1)Deep water rigs operate on floating facilities and shallow water rigs operate on fixed facilities.
(2)Rigs are idle, stacked on land and not in state waters.
The following table sets forth certain information concerning our International Solutions drilling rigs as of September 30, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | 3 | 4 | — | — | — | 4 | — | 20 | 3 |
| Colombia | 2 | — | 2 | — | 1 | — | 2 | — | 7 | — |
| Bahrain | — | — | 3 | 3 | — | — | — | — | 3 | 3 |
| Totals | 14 | 3 | 9 | 3 | 1 | — | 6 | — | 30 | 6 |
(1)Other than four super–spec rigs in Argentina, the FlexRig®3 is equipped with an AC drive, 1,500 horsepower drawworks, and a 750,000 lb. hookload rating. It can be equipped with an optional skid or walking system, third mud pump, and 7,500 psi high pressure mud system. The other eight rigs in Argentina are equipped with skid systems.
(2)The FlexRig® 4 model has a small footprint and is designed to be highly mobile. The rig is equipped with a 300,000 lb. mast, 400HP top drive and two mud pumps. Range 3 drill pipe is used without setback. The rig is capable of horizontal and vertical drilling, but is primarily used for vertical drilling.
(3)A silicon-controlled-rectifier (“SCR”) system converts alternate current (“AC”) produced by one or more AC generator sets into direct current (“DC”). Of the six SCR rigs, one is equipped with 2,100 horsepower drawworks and the remaining five are equipped with 3,000 horsepower drawworks to drill deep conventional wells.
| (1)
| | During the fourth quarter of fiscal year 2018, we ceased operations in Ecuador. On October 1, 2018, we executed a sales agreement with respect to the six conventional rigs present in the country, pursuant to which the rigs, together with associated equipment
| | | | | | | | | | | |
Drilling Services and machinery will be sold to a third party to be recycled. Prior to the sale that was executed on October 1, 2018, certain components of these rigs that are not subject to the sale agreement were transferred to the United States. As such, these rigs have been excluded from the table.Solutions |
General
Contract Drilling
General
We are the largest provider of advanced technologysuper-spec AC drive land rigs in the Western Hemisphere. Operating principally in North and South America, we specialize in shale and unconventional resource plays, drilling challenging and complex wells in oil and gas producing basins in the United States and in international locations. In the United States, we have a diverse mix of customers consisting of large independent, major, mid-sized and small cap oil companies and private independent companies (including private equity-backed companies) that are primarily focused on unconventional shale basins. In South America and the Middle East, our customers primarily include major international and national oil companies.
We
don’t operatedid not have any
mechanical rigs.Revenue from individual customers that arerepresented 10% or more of our total consolidated revenues are as follows:
in fiscal years 2021, 2020, or 2019. | | | | | | | | | |
(In thousands) | 2018 | | 2017 | | 2016 |
EOG Resources, Inc. | $ | 258,194 | | $ | 163,582 | | $ | 124,262 | |
2021 FORM 10-K|7
The following table presents our average active rigs per day (a measure of activity and utilization over the fiscal year) and average utilization for the fiscal years 2018, 2017,2021, 2020, and 2016:2019:
| | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, |
| | U.S. Land | | Offshore | | International Land | |
| | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | |
Average active rigs per day | | 213.6 | | 156.5 | | 101.0 | | 5.6 | | 6.2 | | 7.4 | | 18.3 | | 13.6 | | 14.7 | |
Average utilization (1) | | 61 | % | 45 | % | 30 | % | 70 | % | 74 | % | 82 | % | 49 | % | 36 | % | 39 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended September 30, |
| North America Solutions | | Offshore Gulf of Mexico | | International Solutions |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
Average active rigs per day1 | 107.4 | | | 134.3 | | | 224.1 | | | 4.3 | | | 5.3 | | | 5.9 | | | 5.0 | | | 12.6 | | | 17.6 | |
Average utilization2 | 43 | % | | 47 | % | | 67 | % | | 59 | % | | 66 | % | | 74 | % | | 16 | % | | 40 | % | | 55 | % |
(1)Includes the impact of downsizing our fleet and/or rigs that have been reclassified to assets held-for-sale. See Note 4—Property, Plant and Equipment to our Consolidated Financial Statements.
(2)A rig is considered to be utilized when it is operating (or otherwise deployed for a customer) or being moved, assembled or dismantled pursuant to a drilling contract, or stacked under contract.
| (1)
| | A rig is considered to be utilized when it is operated (or otherwise deployed for a customer) or being moved, assembled or dismantled pursuant to a drilling contract.
| | | | | | | | | | | |
| Our Segments | | | | |
Our Segments
U.S. Land
North America Solutions Segment
We believe we operate the largest and most technologically advanced AC drive drilling rig fleet in the United StatesNorth America and have a presence in most of the U.S. shale and unconventional basins. We have athe leading market share in at least three of the three most active oil basins, which include the Permian Basin, Eagle Ford Shale, and Woodford Shale. More than 95 percentNearly all of our active rigs are drilling horizontal or directional wells. As of September 30, 2018,2021, we had over 20approximately 22 percent of the total market share in U.S. land drilling and over 40approximately 32 percent of the super-spec market share in U.S. land drilling.As In the United States, we have the industry's largest super-spec fleet wit
h 230 rigs, of which 125 were under contract at September 30, 2018, 2322021. In total, 127 of our 350 236 marketed rigs were under contract, 13673 were under fixed‑fixed‑term contracts, and 9654 were working well-to-well. Over the past three fiscal years, we have reinvested in our fleet, upgrading over 162 rigs to industry-leading super-specwell-to-well as of September 30, 2021. Our drilling technology within this segment enables a solutions-based approach that provides performance-driven drilling services designed to
drillhelp deliver greater levels of accuracy, consistency, optimization and a reduction of human error to create higher quality wellbores with lower overall risk. This technology is intended to address our customers' unique challenges and should result in less wellbore tortuosity and reduce positional uncertainty in the
most complex unconventional wells.directional drilling process.
Our
U.S. LandNorth America Solutions segment contributed approximately
8384.2 percent ($
2.11.0 billion) of our consolidated operating revenues during fiscal year
2018,2021, compared
withto approximately
8083.1 percent ($
1.41.5 billion) and
7786.7 percent ($
1.22.4 billion) of our consolidated operating revenues during fiscal years
20172020 and
2016,2019, respectively. In
the United States, we drawNorth America, our customers
are primarily from the major
integrated oil companies, large independent oil companies,
and small cap oil
companies.companies and private independent companies (including private equity-backed companies). Revenue from drilling services performed for our largest North America Solutions drilling customer totaled approximately 11.5 percent ($118.4 million) of the North America Solutions segment revenues during fiscal year 2021.
Offshore
Gulf of Mexico Segment
Our Offshore DrillingGulf of Mexico segment has been in operation since 1968 and currently consists of eightseven platform rigs six of which are on operator-owned platforms, which operate solely in the Gulf of Mexico. We supply the rig equipment and crews and the operator, who owns the platform, will typically provide production equipment or other necessary facilities. Our offshore rig fleet operates on both conventional jacket stylefixed leg platforms and floating platforms attached to the sea floor with mooring lines, such as Spars and Tension Leg Platforms. Additionally, we provide management contract services to customer platforms where the customer owns the drilling rig. As of September 30, 2018, six2021, four of the eightseven offshore rigs were under contract. Our Offshore Gulf of Mexico operations contributed approximately 610.4 percent ($142.5126.4 million) of our consolidated operating revenues during fiscal year 2018,2021, compared to approximately 88.1 percent ($136.3143.1 million) and 95.3 percent ($138.6147.6 million) of our consolidated operating revenues during fiscal years 20172020 and 2016,2019, respectively. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 6077.9 percent ($85.898.4 million) of offshore revenues during fiscal year 2018.
2021.
International
LandSolutions Segment
Our International
LandSolutions segment
operates primarily
conducts operations in Argentina,
and Colombia,
in addition to smaller operations in Bahrain and U.A.E.
During the fourth quarter of fiscal year 2018, we ceased operations in Ecuador. As of September 30,
2018,2021, we had
21six land rigs contracted for work in locations outside of the United States. Our International
LandSolutions operations contributed approximately
104.8 percent ($
238.457.9 million) of our consolidated operating revenues during fiscal year
2018,2021, compared
withto approximately
128.1 percent ($
213.0144.2 million) and
147.6 percent ($
229.9211.7 million) of our consolidated operating revenues during fiscal years
20172020 and
2016,2019, respectively.
2021 FORM 10-K|8
ArgentinaAs of September 30, 2018,2021, we had 1920 rigs in Argentina. Revenues generated by Argentine drilling operations contributed approximately 82.3 percent ($190.027.9 million) of our consolidated operating revenues during fiscal year 20182021 compared to approximately 94.8 percent ($157.384.4 million) and 105.9 percent ($159.4165.7 million) of our consolidated operating revenues during fiscal years 20172020 and 2016,2019, respectively. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 72.2 percent of our consolidated operating revenues and approximately 7145.2 percent of our international operating revenues during fiscal year 2018.2021. The Argentine drilling contracts are primarily with large international or national oil companies.
Colombia As of September 30, 2018, we believe2021, we had approximately 20 percent of total market share and approximately 40 percent of the unconventional horizontal drilling market share in Argentina.Colombia As of September 30, 2018, we had eightseven rigs in Colombia. Revenues generated by Colombian drilling operations contributed approximately 20.1 percent ($38.81.7 million) of our consolidated operating revenues in fiscal year 2018,2021, compared to approximately 20.4 percent ($37.66.4 million) and 11.1 percent ($20.529.8 million) of our consolidated operating revenues during fiscal years 20172020 and 2016,2019, respectively. Revenues from drilling services performed for our two largest customers in Colombia totaled approximately 10.1 percent of our consolidated operating revenues and approximately 132.9 percent of our international operating revenues during fiscal year 2018.2021. The Colombian drilling contracts are primarily with large international or national oil companies.
BahrainAs of September 30, 2021, we had three rigs in Bahrain. Revenues generated by Bahrain drilling operations contributed approximately 2.3 percent ($27.4 million) of our consolidated operating revenues in fiscal year 2021, compared to approximately 1.6 percent ($28.7 million) and 0.4 percent ($11.5 million) of our consolidated operating revenues during fiscal years 2020 and 2019, respectively. All of our revenues in Bahrain are from a partner of the local national oil company.
United Arab EmiratesIn September 2021, we sold two rigs we had in country as part of a larger rig package sale to ADNOC Drilling Company P.J.S.C. As a result of this transaction, we did not have any rigs located in the U.A.E. as of September 30, 2021. See Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” and Note 4—Property, Plant and Equipment to our Consolidated Financial Statements included in this Form 10‑K for additional information. Prior to the sale, revenues generated by our U.A.E. drilling operations contributed approximately 0.1 percent ($1.0 million) of our consolidated operating revenues in fiscal year 2021, compared to approximately 1.4 percent ($24.7 million) and 0.2 percent ($4.7 million) of our consolidated operating revenues during fiscal years 2020 and 2019, respectively. All of our revenues in U.A.E. are from a subsidiary of the national oil company.
Other Operations include additional non-reportable operating segments.
Revenues included in “other” consist of drilling technology services as well as real estate rental income. Our drilling technology focuses on improving the efficiency and accuracy of drilling operations and wellbore quality through the following service offerings: (i) a proprietary Bit Guidance System™, offered as a service through MOTIVE, which we acquired in June 2017, and (ii) 3D geomagnetic reference modeling and measurement while drilling survey correction services, offered through MagVAR, which we acquired in December 2017.We also own develop and operate a limited number of commercial real estate properties.properties located in Tulsa, Oklahoma. Our real estate investments which are located exclusively within Tulsa, Oklahoma, include a shopping center multi‑tenant industrial warehouse properties, and undeveloped real estate.
We have established a wholly-owned captive insurance company
On October 1, 2019, we elected to utilize the Captives to insure
various risksthe deductibles for our workers’ compensation, general liability and automobile liability insurance programs. Casualty claims occurring prior to October 1, 2019 will remain recorded within each of
the operating segments and future adjustments to these claims will continue to be reflected within the operating segments. Reserves for legacy claims occurring prior to October 1, 2019, will remain as liabilities in our operating
subsidiaries.segments until they have been resolved. Changes in those reserves will be reflected in segment earnings as they occur. We will continue to utilize the Captives to finance the risk of loss to equipment and rig property assets. The
amountCompany and the Captives maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of
actual cash investments held bysignificant events covered under these programs. Our operating subsidiaries are paying premiums to the
captive insurance company varies, dependingCaptives, typically on a monthly basis, for the estimated losses based on the
amountexternal actuarial analysis. These premiums are currently held in a restricted cash account, resulting in a transfer of
premiums paidrisk from our operating subsidiaries to the
captive insurance company, the timing and amount of claims paid by the captive insurance company, and the amount of dividends paid by the captive insurance company.Internal Restructuring
We may reorganize our active International Land drilling operations and our Offshore Drilling operations into separate, wholly-owned subsidiaries of Helmerich & Payne, Inc. through an internal restructuring transaction. This may resultCaptives. Starting in the transfersecond quarter of certain assets from Helmerich & Payne International Drilling Co. to other wholly-owned subsidiariesfiscal year 2020, the Captives' insurer issued a stop-loss program that will reimburse the Company's health plan for claims that exceed $50,000. The Company did not previously purchase any stop-loss coverage.
During fiscal year 2019, the Company established an incubator program for new research and development projects, the results of
Helmerich & Payne, Inc. We believe that reorganizing these businesses into separate wholly-owned subsidiaries of Helmerich & Payne, Inc. will foster operational efficiency, simplify our organizational structure and provide additional claritywhich have been included in
our internal reporting. Any such internal reorganization would not impact"Other" within our segment
reporting.disclosures. Rigs, Equipment, R&D, and Facilities
During the late 1990’s, we undertook a strategic initiative to develop a new generation drilling rig that would be the safest, fastest-moving and highest performing rig in the land drilling market. Our first “FlexRig®”FlexRig® drilling rig entered the market in 1998. The original 18 rigs were designated as FlexRig1We continued to innovate and FlexRig2 rigs and were designed to drill wells with a depth of between 8,000 and 18,000 feet. Fromin 2002 to 2004, we designed, built and delivered 32 of the next generation,introduced our first AC drive rigs, known as “FlexRig3,” which incorporated new drilling technology and improved the safety and environmental design. The FlexRig3sThese rigs found immediate success by delivering higher value wells to the customer. This wascustomer and marked the beginning of the AC land rig revolution.
2021 FORM 10-K|9
We also changed our pricing and contracting strategy, and beginning in 2005, predominantly all new FlexRigsFlexRig® drilling rigs were built supported by a firm contract and attractive returns. To date, we have built 232 FlexRig3’s and our strategy included building them under a term contractover 200 FlexRig® rigs that align with substantial payback at attractive rates of return.this strategy. An important part of our strategy was to design a rig that could support continuous improvement through upgrade capability of the hardware and software on the rigs to take advantage of technology improvements and lengthening the industry rig replacement cycle. These upgrades included, but were not limited to, enhanced drilling control systems and software, skid and walking systems for drilling multiple well pads, 7,500 psi mud systems, set back capacity to accommodate the pipe that the longer laterals demanded, and additional mud system capacity.A strategic advantage is our ability to utilize our AC rig design and operational and engineering expertise to exploit different well depths and designs that customers demand. In 2006, we introduced the FlexRig4, which was designed to efficiently drill shallower wells on multi-well pads. The FlexRig4 design offers two options that include trailerized or multi-well pad drilling capability, both of which incorporate additional environmental and safety by design improvements. While the trailerized FlexRig4 design provides for more efficient moves between individual well pads, the multi-well pad design uses a skidding capability that allows for drilling multiple wells from a single pad, which results in a reduced environmental impact and increased production from a smaller footprint.
In 2011, we announced the introduction of the FlexRig5. The FlexRig5 was designedintroduced a FlexRig® design for deeper wells than the FlexRig4 and long lateral drilling of multiple wells from a single location and is designed for drilling horizontally in unconventional shale reservoirs. The new design preservespreserved the key performance features of the FlexRig3 design,earlier designs but addsadded a bi-directional skidding system and equipment capacities suitable for drilling long lateral wells.
In 2016, we saw the further progression of longer lateral wells,
in excess of 25,000 feet of measured depth.We have an important advantage in the super-spec space inwhich brought additional technical challenges. At that our FlexRig3’s and FlexRig5’s are ideally suited for super-spec upgrades, andtime, we have more upgradeable rigs than our competitors. Going forward, we will continue to focus on investing capital to grow the size of our super-spec fleet. During fiscal year 2018, we converted two FlexRig4’s to super-spec capacity and upgraded 52 of our otherbegan delivering rigs to the market that were equipped and capable of drilling these longer lateral wells. The industry would later refer to these rigs as super-spec including 51 FlexRig3’srigs, which have the following specific characteristics: AC drive, minimum 1,500 horsepower drawworks, minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and one FlexRig5. As of September 30, 2018, we held over 40 percent of the super-spec market share in U.S. land drilling. Ourmultiple-well pad capability. Additionally, our competency in design and construction allowsas well as our financial strength enabled us to efficiently upgrade our other existing rigs to super-spec, resulting in what we believe to be the largest fleet of super-spec rigs in the world. As of September 30, 2021, we had 230 super-spec rigs.
In 2017, we introduced our first walking rig by reconfiguring some of our uni-directional skid designed FlexRig® drilling rigs. Since then, we have reconfigured, converted, and our financial strength enables usupgraded a total of 49 FlexRig® drilling rigs to continue such upgrades as long as market demand for such rigs remains high and there remains a supply of economically viable super-spec upgradablewalking rigs. We do these upgrades at our fabrication facility in Houston, Texas. Years of designing and building our fleet of AC drive FlexRigsFlexRig® drilling rigs has given us many competitive benefits. One key advantage is fleet uniformity. We have overseen the design and assembly of all of our AC FlexRigs,FlexRig® drilling rigs, and our different rig classes share many common components. We co-designed the control systems for our rigs and have the right to make any changes or modifications to those systems that we desire. A uniform fleet creates an adaptive environment to reach maximum efficiency for employees, equipment and technology and is critical to our ability to provide consistent, safe and reliable operations in increasingly complex basins. In addition, our fleet has greater scale than any other competitor, which enables us to upgrade our existing FlexRigsFlexRig® drilling rigs to super-spec in a capital efficient way. High levels of uniformity in crew training and rotation as well as parts and supplies improve our cost-effectiveness, and our ability to control and remove safety exposures across a more standard fleet allowsallow us to deliver higher performance in a safer and more reliable manner for the customer. Further, our fleet is supported by a cost-effective Company-owned supply chain that provides standardized materials directly to the rigs from our regional warehouses. A long-standing challenge in our industry is providing high quality and consistent results. In addressing thethis challenge, of providing safe, high quality and consistent results, we utilize process excellence techniques that are developed internally. We provide experienced drilling and maintenance support for our operations, which provides value by reducing nonproductive time in our operations and improving drilling performance through our Rig Systems Monitoring and Support Center of Excellence (“COE”RSMS”) and Remote Operations Centers ("ROCs"). The COE isOur RSMS and ROCs are manned 24 hours a day, seven days a week, with the ability to monitor and detect trends in drilling and drilling services performance onboard our rigs. Our monitoring group within the COERSMS provides real-time help and feedback to our wellsite employees, as well as our customers, to fully optimize our operational performance. Additionally,
our COE has a staff of performance engineers and industry experts that work with our customers to enhance wellbore positioning, drilling program execution and overall drilling performance. The monitoring group and our performance engineers capture our drilling work steps to ensure we havehelp provide high quality and reliable results for our customers.
We currently have
threetwo facilities that provide vertically integrated solutions for drilling rig manufacturing, upgrades, retrofits and modifications, as well as overhauling, recertification, and repairs as it relates to our rigs and equipment. These facilities
all utilize lean manufacturing processes to enhance quality and efficiency as well as provide important insights in the maintenance and wear of equipment on our rigs.
We have a fabricationOur facility located in Galena Park, Texas is primarily utilized for overall rig assembly, overhaul, recommissioning and
assembly facility near Houston, Texas as well as a fabrication facility near Tulsa, Oklahoma. Additionally, we lease an industrialrecertification while our facility near Tulsa, Oklahoma
that we utilizeis primarily utilized for
FlexRig equipment repairsmodular rig component overhauls and
overhauls.repairs.
During fiscal year 2018,2021, we commercializedcontinued to see adoption and growth with our FlexApp services, which include several new software applications that layertechnologically enabled automation solutions. We designed our automation solutions to address challenges within our customers’ businesses as much of the drilling process is heavily dependent on top ofhuman decision making to design, execute and optimize crude oil and natural gas extraction. Utilizing these technologies, we are able to deploy a more science-based solution compared to human decisions and execution, thereby reducing variability and the costs around achieving optimal outcomes. These solutions continue to provide differentiated value for our FlexRig drilling control systems. Thesecustomers through enhanced wellbore quality and placement, improved cost performance and well economics, and better consistency at reduced risk. Our automation focused solutions and applications are enabled by our uniform digital fleet and are designed to provide additional value to our customers’customers' well programs by providing a platform for machine-human collaboration during the drilling process to improve efficiency. The FlexApps can helpOur path to autonomous drilling continues to evolve with several solutions in various stages of commercial testing. All of our technologies play an important role in deployingdeveloping our strategy as we strivehead towards autonomous drilling. The FlexApps that are currently in use include the following:
| | |
Application Name
| | Description
|
FlexTorque™
| | Hardware and software designed to decrease downhole drilling vibration and "slip-stick" during drilling. This increases drilling efficiencies and extends bit and downhole tool life eliminating customers' costly nonproductive time.
|
FlexConnect™
| | Software to optimize slip-to-slip connection time, which reduces customer nonproductive time and improves rig performance consistency across our rig fleet.
|
Flex-Oscillator 2.0™
| | Rig control software that automates drill string rotation during directional "slide" operations, which reduces downhole drag and the potential for stuck pipe. Additionally, it allows for more effective directional drilling.
|
FlexB2D™
| | Software to engage and disengage the bit during connections in an established controlled and consistent manner allowing for better bit and downhole tool life, better drilling parameters and less costly bit trips out of the hole.
|
FlexDrill 1.0™
| | Software licensed from ExxonMobil to maximize the bit's rate of penetration, which we have automated, allowing the drilling control system to achieve the ideal mechanical specific energy at the bit.
|
FlexGuide™
| | Powered by both MOTIVE and MagVAR software that utilizes a drill bit guidance system and geomagnetic survey correction, respectively, allowing for higher quality wellbores with a scalable, repeatable data driven platform approach and a reduction of surveying uncertainty by 50-60% while increasing horizontal well economics and reducing risk.
|
2021 FORM 10-K|10
We have historically offered ancillary services, which are now referred to as FlexServices™FlexServices®. These services include trucking, surface equipment, casing running tool services and pipe rental. Subsequent to September 30, 2021, we sold the assets associated with two lower margin service offerings, trucking and casing running services, which contributed approximately 2.8 percent to our consolidated revenues during fiscal year 2021, in two separate transactions. The sale of our trucking services was completed on November 3, 2021 while the sale of our casing running services was completed on November 15, 2021 for combined cash consideration less costs to sell of $5.8 million in addition to the possibility of future earnout revenue.
Our business largely depends on the level of capital spending by oil and gas companies for exploration and production activities.
The level of capital spending is correlated to oil and gas prices. Oil and gas prices can be volatile at times depending upon both near and long-term supply and demand factors. Sustained increases or decreases in the prices of oil and natural gas generally have a material impact on the exploration and production activities of our customers. As such, significant declines in the prices of oil and natural gas may have a material adverse effect on our business, financial condition and results of operations.
Oil prices have declined significantly since 2014 when prices exceeded $100 per barrel. Oil prices have rebounded modestly from lows below $30 per barrel in early 2016 to range between $50 and $77 per barrel in fiscal year 2018. The decline in prices continued to negatively affect demand for services in fiscal year 2016 but showed some recovery in fiscal years 2017 and 2018. As of September 30,
2018,2021, we had
259137 rigs under contract, compared to
21879 and
118218 rigs under contract as of September 30,
20172020 and
2016,2019, respectively. For further information concerning risks associated with our business, including volatility surrounding oil and natural gas prices and the impact of low oil prices on our business, see Item 1A— “Risk Factors” and Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this Form
10‑10‑K.Our industry is highly competitive, and we strive to differentiate our services based upon the quality of our FlexRigsFlexRig® drilling rigs and our engineering design expertise, operational efficiency, software technologies, and safety and environmental awareness. The number of available rigs generally exceeds demand in many of our markets, resulting in significant price competition. With respect to the super-spec market, however, the industry tends to have utilization closer to 100 percent and higher pricing. We compete against many drilling companies, some of whom are present in more than one of our operating regions. In the United States, we compete with Nabors Industries Ltd., Patterson-UTI Energy, Inc. and many other competitors with regional operations. Internationally, we compete directly with various contractors at each
location where we operate. In the Gulf of Mexico platform rig market, we primarily compete with Nabors Industries Ltd. and Blake International Rigs, LLC.
Our drilling contracts are obtained through competitive bidding or as a result of direct negotiations with customers. Our contracts vary in their terms and rates depending on the nature of the operations to be performed, the duration of the work, the amount and type of equipment and services provided, the geographic areas involved, market conditions and other variables.
OurIn many instances, our contracts
often cover
multi‑multi‑well or pad and multi‑multi‑year projects. Except for a limited number of rigs operated under master agreements, each drilling rig operates under a separate drilling contract.During fiscal year 2018, substantially all of our drilling services were performed on a “daywork” contract basis, under which we charged a rate per day, with the price determined by the location, depth and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. We may also enter into contracts where we charge a fixed rate per foot of hole drilled to a stated depth, with a fixed rate per day for the remainder of the hole. Contracts performed on a “footage” basis generally involve a greater element of risk to the contractor compared to contracts performed on a “daywork” basis. Also, we may enter into “turnkey” contracts under which we charge a fixed sum to deliver a hole to a stated depth and agree to furnish services such as testing, coring and casing the hole which are not normally done on a “footage” basis. “Turnkey” contracts entail varying degrees of risk greater than the usual “footage” contract. We also actively pursue “performance daywork” contracts. These contracts typically have a lower dayrate portion and give us the opportunity to share in the well cost savings based on meeting or exceeding certain key performance indicators that are mutually agreed on by ourselves and our customers.
The duration of our drilling contracts are generally either
“well‑to‑well”“well‑to‑well/pad-to-pad” or for a fixed term. “Well‑to‑“Well‑to‑well” contracts can be terminated at the option of either party upon the completion of drilling of any one well. Fixed-term contracts generally have a minimum term of at least six months up to multiple years. These contracts customarily provide for termination at the election of the customer but may include an “early termination payment” to be paid to us if the contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances such as destruction of a drilling rig, bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us.Contracts generally contain renewal or extension provisions exercisable at the option of the customer at prices mutually agreeable to us and the customer. In most instances, contracts provide for additional payments for mobilization and demobilization of the rig.
Daywork Contracts
Daywork contracts are contracts under which we charge a rate per day, with the price determined by the location, depth and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. During fiscal year 2021, a majority of our drilling services were performed on a “daywork” contract basis.
Footage Contracts
Footage contracts are contracts where we charge a fixed rate per foot of hole drilled to a stated depth, with a fixed rate per day for the remainder of the hole. Contracts performed on a "footage" basis generally involve a greater element of risk to the Company compared to contracts performed on a "daywork" basis.
Lump-sum Contracts
Lump-sum contract are contracts under which we charge a fixed sum to deliver a hole to a stated depth and agree to furnish services such as testing, coring and casing the hole which are not normally done on a "footage" basis. "Lump-sum" contracts entail varying degrees of risk greater than the usual "footage" contract.
2021 FORM 10-K|11
Performance-based Contracts
Performance-based contracts are contracts pursuant to which we are compensated based upon our performance against a mutually agreed upon set of predetermined targets. These contract types are relatively new to the industry and typically have a lower base dayrate, but give us the opportunity to receive additional compensation by meeting or exceeding certain performance targets agreed to by our customers. For example, some performance targets are set based upon days to drill a well or the number of lateral feet drilled in zone per day. We often use our automated technology solutions to assist in achieving the performance targets. The risks associated with these contracts relate to the failure to reach the agreed upon performance targets. If we do not meet these targets, we will not receive additional compensation above what we have received utilizing a "daywork" contract. Based on our operational track record throughout fiscal year 2021 and drilling expertise, our performance-based contracts have produced a positive risk-reward outcome. We are seeing a growing adoption of performance contracts by our customers and we expect this trend to continue.
As of September 30,
20182021 and
2017,2020, our drilling contract backlog
being the expected future dayrate revenue from executed contracts with original terms of 365 days or greater, was
$1.1 billion$572.0 million and
$1.3 billion,$658.0 million, respectively.
The decrease in backlog at September 30, 2018 from September 30, 2017 is primarily due to contract pricing modifications and a change in certain contracts from fixed term to well-to-well related to our international land segment in fiscal year 2018. Approximately
2622.9 percent of the
total September 30,
20182021 backlog is reasonably expected to be
filledfulfilled in fiscal year
20202023 and thereafter.
Included in backlog is early termination revenue expected to be recognized after the periods presented in which early termination notice was received prior to the endSee Item 7—"Management's Discussion and Analysis of
the period. Upon adoptionFinancial Condition and Results of
Accounting Standard Update No. 2014-09, Revenue from Contracts with Customers (Topic 606): Revenue from Contracts with Customers, we will be required to disclose our drilling contract backlog within the Notes to the Consolidated Financial StatementsOperations — Contract Backlog" included in
Part II, Item 8– “Financial Statements and Supplementary Data” of this
report.Form 10-K for additional information pertaining to backlog.The following table sets forth the total backlog by reportable segment as of September 30, 2018 and 2017, and the percentage of the September 30, 2018 backlog reasonably expected to be filled in fiscal year 2020 and thereafter:
| | | | | | | | | |
| | | | | | | | Percentage Reasonably | |
| | Total Backlog | | Expected to be Filled in | |
| | Revenue | | Fiscal Year 2020 | |
Reportable Segment | | 9/30/2018 | | 9/30/2017 | | and Thereafter | |
| | (in billions) | | | |
U.S. Land | | $ | 0.9 | | $ | 0.9 | | 24.9 | % |
Offshore | | | — | | | — | | — | % |
International Land | | | 0.2 | | | 0.4 | | 31.0 | % |
| | $ | 1.1 | | $ | 1.3 | | | |
As noted above, under certain limited circumstances a customer is not required to pay an early termination fee. There may also be instances where a customer is financially unable or refuses to pay an early termination fee. In addition, contract terms could be modified or extended after the initial contract is signed. Accordingly, the actual amount of revenue earned may vary from the backlog reported. For further information, see Item 1A—“Risk Factors — Our current backlog of contract drilling revenue may continue to decline and may not be ultimately realized as fixed‑term contracts may in certain instances be terminated without an early termination payment.”
Employees
One of our core values is striving for a culture that embraces organizational health and actively controlling and removing exposures (“C.A.R.E.”) for the safety and wellbeing of our employees. Our employees actively C.A.R.E. for those around them, as demonstrated through, among other things, employee support of the H&P Way Fund, our Company’s charitable fund that provides assistance to employees and their families experiencing unexpected and unavoidable emergencies. This is fundamental to our commitment to take care of our employees and to make the communities where they live and work better places. We pride ourselves on being a service company and focus on maintaining a service attitude for customers. We have a long history of emphasizing creativity and seek to maintain an innovative spirit in all facets of doing business. Our employees are strong team players who work closely with our customers to deliver value for customers and shareholders. Designing, building, upgrading, deploying, and operating rigs requires hard working teams willing to teach, learn, and communicate to achieve a high level of performance on a consistent and repeatable basis.
As of September 30, 2018,2021, we had 8,7805,444 employees within the United States (12 of whom were part‑time employees) and 997488 employees in our international operations. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be robust. None of our U.S. employees are represented by a union. However, some of our international employees are unionized.
Human Capital Objectives and Programs
We strive to create a culture and work environment that enables us to attract, train, promote, and retain a diverse group of talented employees who together can help us gain a competitive advantage.
Core Values and Culture
"The H&P Way" defines our purpose, core values, and the behaviors that drive our culture. What we endeavor to do is anchored in our purpose, improving lives through efficient and responsible energy. Fostering and maintaining a strong, healthy culture is a key strategic focus. Our core values serve to inform who we are and the way our employees interact with one another, our customers, partners and shareholders. Our core value of Actively C.A.R.E. means that we treat one another with respect. We care about each other, and from a safety perspective, our employees are committed to Controlling and Removing Exposures ("C.A.R.E.") for themselves and others. Our core value of Service Attitude means that we do our part and more for those around us. We consider the needs of others and provide solutions to meet their needs. Our core value of Innovative Spirit means that we constantly work to improve and are willing to try new approaches. We make decisions with the long-term view in mind. Our core value of teamwork means that we listen to one another and work across teams toward a common goal. We collaborate to achieve results and focus on success for our customers and shareholders. Finally, we strive to do the right thing. That means we are honest and transparent. We tackle tough situations, make decisions, and speak up when needed.
Talent Attraction & Retention
Our recruiting practices and decisions on whom we hire are among our most important activities. Our Workforce Staffing team provides full staffing services to ensure consistent staffing levels on our rigs. This team sources, hires, onboards, trains, assigns and reassigns rig-based employees. In downturn years, we maintain relationships with former employees and prioritize recalling our most experienced people for field positions. In fiscal year 2021, we recalled approximately 1,800 employees. In addition, we utilize social media, local job fairs, employee referral bonuses, and educational organizations across the United States to find diverse, motivated and responsible employees.
2021 FORM 10-K|12
Education and Training
We are dedicated to the continual training and development of our employees, especially of those in field operations, to ensure we can develop future managers and leaders from within our organization. Our training starts right at the beginning with on-boarding procedures that focus on safety, responsibility, ethical conduct and inclusive teamwork.
H&P’s strong commitment to our employees’ growth is demonstrated through our formal organizational development team, which oversees talent management, training and development. In addition to career and safety training efforts, the team creates, manages and implements enhancements to development and succession plans, change management initiatives and diversity, equity and inclusion ("DE&I") programs.
H&P offers a variety of training programs ranging from job specific programs to leadership development. Some of the prominent training programs that we offer are:
•New Employment Safety Training - onboarding program for new hires in safety sensitive positions. The purpose of the program is to prepare employees to work safely on our rigs and provide necessary certifications to do so; including all Occupational Safety and Health Administration ("OSHA") and IADC training, as well as Company culture education.
•Short Service Employee - specialized training program that is a continuation of New Employment Introduction basics and is intended to provide the technical on-the-job training guided by a mentor.
•Ethics and Compliance Training – comprised of several specific training programs, including Code of Conduct, Insider Trading, Anti-Discrimination & Harassment, Data Privacy, Trade Compliance, and Anti-Corruption.
•Change Champions - teaches employees to solve complex problems using structured processes, tools and data to drive results while emphasizing leadership and public speaking.
•Leadership Series - accessible online to all leaders and covers a variety of topics related to leading The H&P Way.
Safety Training and Serious Injury and/or Fatality ("SIF") Reduction Program
We are committed to creating a culture highlighted by an Actively Caring workforce. We strive to Actively C.A.R.E. for:
•our own safety and health;
•the safety and health of others; and
•the protection of our environment.
Fundamental to our Actively C.A.R.E. culture is every individual's willingness to provide immediate open feedback to others regarding safe and unsafe work practices and to proactively correct recognized exposures that threaten one's health and safety. Through training and accountability, H&P educates our employees on the negative consequences of taking health and safety risks. Our success will only be determined by demonstrated action and continuous improvement.
Safety Leadership
For more than 20 years, H&P measured safety success the same way other companies in our industry did – the absence of OSHA recordable injuries, declining lost time, restricted duty and medical treatment cases, declining total recordable injury rates ("TRIR") and the number of active rig years worked without an OSHA recordable injury or lost-time injury. We now believe that measuring safety in this manner can be destructive to management’s efforts to build trust with field employees. We have redefined safety success as the Control and Removal of Exposures (C.A.R.E.) for self and others and encourage employees to report near miss incidents with serious, life-altering or fatal injury potential, identifying and reporting serious injury exposures for which employees are personally recognized and rewarding monetarily for exemplifying our Actively C.A.R.E culture. We believe trust is key to organizational health, as well as safety and operational success.
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SIF Strategy
We are committed to controlling and removing SIF exposures on any H&P location or operation. H&P safety data shows that approximately 10 to 15 percent of all OSHA recordable injuries are events in which valuable lessons learned are produced and inform mitigation efforts to reduce potential serious injury in the future. The remaining recordable cases may not provide the necessary learning opportunities to prevent future serious injury. Similarly, the data also indicates that SIF potential incidents, all of which provide information to help prevent future serious injury or fatality, occur approximately 1.5 times more than the traditional TRIR. We continue to track traditional safety metrics like TRIR and lost time injury rates in order to be responsive to client requests and to benchmark against existing industry data but we will have a proportionate response to these antiquated metrics. Our safety success at H&P will be based on key performance indicators related to the controlling and removing of SIF exposure, such as SIF potential and SIF mitigated rates, and our vision for the future of safety at H&P will be guided by these principles.
Diversity, Equity & Inclusion
We believe that creating an environment where our employees feel valued and respected drives engagement, better leverages the unique talents and perspectives of our people to innovate and enhances our ability to attract and retain a diverse workforce. H&P has employed a DE&I specialist, implemented a thriving Women of H&P Employee Resource Group, and established a DE&I Advisory Council with global employee representation. Our commitments are evidenced by formalized policies regarding equal opportunity and a discrimination-free workplace. We are actively tracking diversity data to better understand demographics within the organization.
Employee Benefits, Health and Wellness
H&P values its employees and believes benefit packages are essential to prioritizing the well-being of its staff and offering competitive compensation. Select highlights of our benefits programs include:
•Medical, dental and vision insurance for all full-time employees, and all part-time employees working more than 20 hours per week, and their dependents;
•A 401(k) plan with Company match incentive for all full-time employees, and all part-time employees working more than 20 hours per week;
•Employer paid life insurance benefits, which include a life assistance program, identity theft protection, and travel assistance plan;
•The Employee Assistance Plan, which offers wellness support with counseling, legal assistance, financial coaching, and identity theft resolution;
•The H&P Way Fund, which provides financial assistance to H&P employees during unavoidable emergencies;
•Employee discounts for phone, computer, personal vehicle, car rental, and hotel purchases; and
•An Educational Assistance Plan, which offers reimbursement of tuition fees for any employee pursuing an undergraduate degree and, in some cases, post-graduate degrees.
Insurance and Risk Management
Our operations are subject to a number of operational risks, including personal injury and death, environmental,
cyber, and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us. Furthermore, if a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition and results of operations.
We have indemnification agreements with many of our customers and we also maintain liability and other forms of insurance. In general, our drilling contracts contain provisions requiring our customers to indemnify us for, among other things, pollution and reservoir damage. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts by us, or subcontractors and/or suppliers or by reason of state anti-indemnity laws. Our customers and other third parties may also dispute these indemnification provisions, or we may be unable to transfer these risks to our drilling customers or other third parties by contract or indemnification agreements.
We insure
working land rigs and related equipment at values that approximate the current replacement costs on the inception date of the policies. However, we self-insure large deductibles under these policies. We also carry insurance with varying deductibles and coverage limits with respect to
stacked rigs, offshore platform rigs, and “named wind storm” risk in the Gulf of Mexico.
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We have insurance coverage for comprehensive general liability, automobile liability, workers’ compensation and employer’s liability, and certain other specific risks. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. We retain a significant portion of our expected losses under our workers’ compensation, general liability and automobile liability programs. We self-insure a number of other risks including loss of earnings and business interruption and most cyber risks.interruption. We are unable to obtain significant amounts of insurance to cover risks of underground reservoir damage.
Our insurance may not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations. Our coverage includes aggregate policy limits. As a result, we retain the risk for any loss in excess of these limits. No assurance can be given that all or a portion of our coverage will not be
cancelled,canceled, that insurance coverage will continue to be available at rates considered reasonable or that our coverage will respond to a specific loss. Further, we may experience difficulties in collecting from our insurers or our insurers may deny all or a portion of our claims for insurance coverage.
Our operations are affected from time to time and in varying degrees by foreign and domestic political developments and a variety of federal, state, foreign, regional and local laws, rules and regulations, including those relating to:
• drilling of oil and natural gas wells;
• directional drilling services;
• protection of the environment;
• workplace health and safety;
• labor and employment;
• data privacy;
• taxation;
• exportation or importation of equipment, technology and software; and
• currency conversion and repatriation.
Environmental laws and regulations that apply to our operations include the Clean Air Act, the Clean Water Act, the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), the Resource Conservation and Recovery Act (each, as amended) and similar laws that provide for responses to, and liability for, air emissions, water discharges or releases of oil or hazardous substances into the environment, including damages to natural resources. Applicable environmental laws and regulations also include similar foreign, state or local counterparts to the above-mentioned federal laws, which regulate air emissions, water discharges, and management of hazardous substances and waste. Environmental laws can have a material adverse effect on the drilling industry, including our operations, and compliance with such laws may require us to make significant capital expenditures, such as the installation of costly equipment or operational changes, and may affect the resale values or useful lives of our drilling rigs.
The Occupational Safety and Health Act (“OSHA”) and other similar laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, the Environmental Protection Agency community right-to-know regulations under Title III of CERCLA, the Emergency Planning and Community Right-to-Know Act and similar state statutes and local regulations require that information be maintained about hazardous materials used in our operations and that this information be provided to employees, state and local governments, emergency responders and citizens.
A number of countries actively regulate and control the importation and/or exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government actions and initiatives by OPEC+ may continue to contribute to oil price volatility. In some areas of the world, government activity has adversely affected the amount of exploration and development work done by oil and gas companies and influenced their need for drilling services, and likely will continue to do so.
In addition, we are subject to a variety of national, state, localother U.S. and foreign laws and regulations, including, but not limited to, the U.S. Foreign Corrupt Practices Act and other anti-bribery and anti-corruption laws. The U.S. Foreign Corrupt Practices Act and similar anti-bribery and anti-corruption laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to non-U.S. officials for the purpose of obtaining or retaining business. Failure to comply with applicable laws or regulations or acts of misconduct could subject us to fines, penalties or other sanctions. For more information, see Item 1A— “Risk Factors — Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti‑bribery legislation could adversely affect our business.”
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We are also subject to the jurisdiction of the U.S. Treasury Department’s Office of Foreign Assets Control, the U.S. Commerce Department’s Bureau of Industry and Security, the U.S. Customs and Border Protection and other U.S. and non-U.S. laws and regulations governing the international environmental, healthtrade of goods, services and safetytechnology. Such regulations regarding exports and imports of covered goods or dealings with sanctioned countries, persons or entities include licensing, recordkeeping and reporting requirements. Failure to comply with applicable laws and regulations treatiesrelating to customs, tariffs, sanctions and conventions. export controls may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets. For more information, see Item 1A— “Risk Factors — Government policies, mandates, and regulations specifically affecting the energy sector and related industries, regulatory policies or matters that affect a variety of businesses, taxation polices, and political instability could adversely affect our financial condition and results of operations.”
We are also subject to regulation by numerous other regulatory agencies, including, but not limited to, the U.S. Department of Labor, which sets employment practice standards for workers. In addition, we are subject to certain requirements to contribute to retirement funds or other benefit plans, and laws in some jurisdictions restrict our ability to dismiss employees.
We monitor our compliance with environmentalapplicable governmental rules and regulations in each country of operation and have seen an increase in environmental regulation.operation. We have made and will continue to make the required expenditures to comply with current and future environmentalregulatory requirements. We do not anticipate that compliance with currently applicable environmental rules and regulations and required controls will significantly change our competitive position, capital spending or earnings during 2019, as these regulations are generally imposed on exploration and production companies instead of contract drilling companies.2022. We believe we are in material compliance with applicable environmental rules and regulations and, thatto date, the cost of such compliance ishas not been material to our business or financial condition. For aHowever, future events such as additional laws and regulations, changes in existing laws and regulations or their interpretation or more detailed descriptionvigorous enforcement policies of regulatory agencies, may require additional expenditures by us, which may be material. Specifically, the expansion of the environmental rulesscope of laws or regulations protecting the environment has accelerated in recent years, particularly outside the United States, and regulations applicablewe expect this trend to our operations, seecontinue. Accordingly, there can be no assurance that we will not incur significant compliance costs in the future. See Item 1A— “Risk Factors —Failure to comply with or changes to governmental and environmental laws could adversely affect our business.”
H&P has helped its customers supply energy for more than a century, and we continue to innovate and improve the directionways in which we can provide energy safely, reliably, and efficiently. Through our work and the work of our customers, we have used our unique position and expertise to advance energy production, reliability, and affordability to people across the globe. The Company continues to evolve and refine its comprehensive sustainability strategy rooted in our core value to "do the right thing," as discussed under "— Human Capital Objectives and Programs — Core Values and Culture." Our sustainability strategy uses data to better understand our impacts in areas like emissions, diversity, and safety.
Improving Lives Through Efficient and Responsible Energy
We believe efficient and responsible energy improves lives globally. With a focus on leading-edge technology, we strive to deliver industry-leading efficiency, safety, and value while continuing to reduce our environmental impact.
Society’s general well-being relies on the energy industry to supply the power that sustains and drives our lives. People have relied upon and harnessed energy from resources like fire, water, wind, animals both domesticated and wild, fossil fuels, nuclear, solar, and more, with each having its own unique societal benefits and costs.
Over time, the continued growth of the world’s population highlighted a need to capture more concentrated forms of energy, making a reliance on fossil fuels increasingly central. Over the last several decades, those responsible for producing fossil fuels gained more expertise and became more specialized. A “service sector” developed to supply the most scientific and technologically specialized needs of the oil and gas explorationsector. We provide highly specialized services in this narrow segment of the very broad and constantly evolving energy sector. We continue to innovate in an effort to increase efficiency for our customers and provide continued societal benefits with less impact to the environment.
Focused on Safer and More Efficient Drilling
We provide performance-driven drilling solutions that are intended to make oil and gas recovery safer and more economical or our customers. Focused on the drilling segment of the oil and gas production companiesvalue chain, we work with, we contractprovide the expertise, technology and equipment to drill oil and gas wells. Thewells for our customers - the exploration and production companies("E&P") companies. Our E&P customers then determine whetherif and when to extract those resources from the ground, following completion of the well. Below are summaries of what
H&P and the Fossil Fuel Value Chain
While we do
play an important role in helping our customers make overall production as safe and
what we do not do,efficient as possible, our most critical responsibility is ensuring the
lattersafety of
which is provided because it is often incorrectly assumed that our
operations overlap with explorationemployees and
production, midstream and downstream partsthe employees of
the oil and gas sector in ways they do not.What We Do
| ·
| | Strive to make drilling for oil and gas safer and more efficient
|
| ·
| | Build and renovate drilling rigs at three industrial facilities in Texas and Oklahoma
|
| ·
| | Oversee drilling operations on our rigs on customer sites
|
| ·
| | Drill predominantly on-shore in the U.S.
|
What We Do Not Do
| ·
| | Buy, lease, prepare, manage or restore land on which rigs are located, or have responsibility for the protection of wildlife or biodiversity of our customers’ properties
|
| ·
| | Pump or extract oil or gas from the ground
|
| ·
| | Procure, transport or pump water underground, or treat, store, manage or remove waste water from the drilling sites, or arrange for its disposal
|
| ·
| | Assume responsibility for the prevention of fugitive releases or emissions associated with the oil and gas exploration or production process
|
| ·
| | Engage in oil and gas transport, refining or storage
|
| ·
| | Engage in downstream operations
|
Thus,our customers. Although many of the environmental and safety risks associated with the oil and gas sector fall outside the scope of our operations, we remain committed to utilizing our expertise and areasadvancing our technologies to aid our customers in minimizing personal and environmental risks and maximizing industry sustainability efforts. Our customers are looking specifically to our expertise and technologies to help them minimize their environmental impact, reduce risks, and achieve their ESG performance targets.
2021 FORM 10-K|16
Below is
thereforea description of the
safety of our employees and the employees of our customers. To be successful, we strive to be leaders in innovation, technology, cost competitiveness, safety, customer service, relationship tending, and reputation management. To maintain this leadership edge and generate shareholder value, we invest in our employees, customers, communities, and other stakeholdersroles that H&P plays, in the
ways listed below.Recruiting
Our recruiting practicesoil and decisions on whomgas value chain, as a drilling solutions provider in comparison to hire are among our most important activities. In addition to traditional school recruiting events, we utilize social media and local job fairs across the U.S. to find diverse, motivated and responsible employees.
Education and Training
The employment opportunities we offer are key to successful recruiting. To attract motivated employees, we rely on our organizational development team. This team offers talent management, mentoring programs, change management initiatives, and diversity, inclusion and succession management programs, as well as educational assistance programs and ongoing training and development opportunities.
Health and Welfare
We support our employees’ and their families’ health with full medical, dental, and vision insurance for employees and their families, life insurance and long-term disability plans, and health care and dependent care flexible spending accounts. We foster teamwork and a sense of community amongst our employees through our H&P Way Fundroles that provides assistance to employees and their families experiencing emergencies.
Retirement
We provide a 401(k) plan with a company match.
Safety
All of our safety programs are designed to comply with applicable laws and industry standards as well as to benefit employees, customers and communities. We have a dedicated Health, Safety and Environmental (“HSE”) function overseen by senior executives and implemented at every H&P drilling rig and facility worldwide. Our safety-focused C.A.R.E. program promotes employee and customer safety and well-being. In addition, we incorporate safety features into our rig designs through our Safety by Design program. The success of our safety initiatives, including our C.A.R.E. and Safety by Design programs, and the Company’s performance with respect to safety metrics are important elementsparticipants in other sectors of the compensation of our executives, as discussed further in our proxy statement.
Our Safety by Design program helps us:
oil and gas industry play. | ·
| | Identify
| | | | | | | | | | | |
| H&P: |
•makes drilling for oil safer and work to eliminate hazardsmore efficient; |
•builds and renovates drilling rigs at two industrial facilities in Texas and Oklahoma; |
•oversees drilling operations on its rigs on customer sites; |
•drills predominantly on-shore in the rig design phaseUnited States (86 percent of available rigs are on onshore); |
•makes significant and impactful investments in research and development and new technologies; |
| ·
| | Use leading-edge technology to enhance efficiency
| | | | | | | | | | | |
| OTHER SECTORS OF THE OIL AND GAS INDUSTRY: |
•buy, lease, prepare, manage or restore land or are responsible for the protection of wildlife on or biodiversity of property; |
•engage in hydraulic fracturing; |
•pump oil or gas from the ground; |
•procure, transport or pump water underground, or treat or remove wastewater from the site, or arrange for its disposal; |
•assume responsibility for the prevention of fugitive releases or emissions associated with the oil and thus reduce the numbergas production process; |
•engage in oil and severity of safety risksgas transport, refining or storage; and |
•engage in downstream operations. |
| ·
| | Standardize designs, which can reduce the variability in the types of rigs we use to allow our employees to have a greater familiarity with the rigs than would be achieved if they had to master a wider variety of rig types
|
Human Capital | ·
| | Design and configure loads and interconnects with rig moves in mind. By striving to integrate equipment to the greatest extent possible, we minimize risks associated with moves and risks associated with double handling
|
Our COE promotes process excellence and safety by providing experienced drilling and maintenance real-time support around the clock to our operations. Our COE Call Center and Real-Time Monitoring Groups are staffed with experienced systems technicians who work with field personnel to leverage each group’s knowledge in troubleshooting rig
events. In addition, experienced engineers monitor safety critical alarms and perform daily safety performance and data analysis throughout the fleet.
In the event that an incident does occur, we have developed and implementedFor a comprehensive Emergency Management and Crisis Response Plan to help ensure H&P has the ability to respond promptly and effectively to the most severe adverse situations or crises.
Environmental Management
H&P does not itself lease properties used for the operations of its customers. However, manydescription of our customers operate in regions that have stringent safetyrecruiting practices, education and environmental lawstraining for employees, and regulations, with which we comply as applicable. The standards we employ include:
| ·
| | Applying industry-accepted environmental best practices
|
employee benefits, see "— Human Capital Objectives and Programs" above. | ·
| | Minimizing rig physical footprints, and using technology to configure drilling rigs, where appropriate, for space efficient multi-well pads, all to minimize the impact on the environment in which we and our customers operate
|
Available Information | ·
| | Conversion of many of our rigs to allow partial substitution of cleaner burning natural gas as a fuel source to reduce air emissions
|
| ·
| | Upgrading our drilling rig fleet to utilize AC drive power and control systems which are more energy efficient and have significantly lower noise levels as compared to SCR and mechanical drilling rigs
|
| ·
| | Using a variety of recycling and other initiatives in our facilities and operations to minimize waste
|
Ethics and Compliance
We expect corporate, professional and personal responsibility from each of our employees as well as compliance with high ethical standards to achieve operational excellence. In addition to the corporate governance oversight provided by the Board of Directors and its committees, management observes and enforces our Code of Business Conduct and Ethics (“Code”) described on our website. Our Code provides employees with the tools to make consistent, ethical decisions and emphasizes the duty to report any concerns or violations.
In addition to our Code, we have and enforce a Code of Ethics for Principal Executive Officers and Senior Financial Officers and a Foreign Corrupt Practices Act Compliance Policy.
We believe this focus on finding and getting the best out of our people, our programs, our standards and our technology collectively support our operations, our reputation and our returns.
Available Information
Our website is located at www.hpinc.com.www.helmerichpayne.com. Annual reports on Form 10‑10‑K, quarterly reports on Form 10‑10‑Q, current reports on Form 8‑8‑K, and amendments to those reports, earnings releases, and financial statements are made available free of charge on the investor relations section of our website as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC.Securities and Exchange Commission ("SEC"). The information contained on our website, or accessible from our website, is not incorporated into, and should not be considered part of, this annual report on Form 10‑10‑K or any other documents we file with, or furnish to, the SEC. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Annual reports, quarterly reports, current reports, amendments to those reports, earnings releases, financial statements and our various corporate governance documents are also available free of charge upon written request.
Investors and others should note that we announce material financial information to our investors using our investor relations website
(https:(https://helmerichandpayneinc.gcs-web.com/)ir.helmerichpayne.com/websites/helmerichandpayne/English/0/investor-relations.html), SEC filings, press releases, public conference calls and webcasts. We use these channels as well as social media to communicate with our stockholders and the public about our company, our services and other issues. It is possible that the information we post on social media could be deemed to be material information. Therefore, we encourage investors, the media, and others interested in our company to review the information we post on the social media channels listed on our investor relations website.15
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An investment in our securities involves a variety of risks. In addition to the other information included and incorporated by reference in this
annual reportForm 10-K and the risk factors discussed elsewhere in this
report,Form 10-K, the following risk factors should be carefully considered, as they could have a material adverse effect on our business, financial condition and results of operations. There may be other additional risks, uncertainties and matters not presently known to us or that we believe to be immaterial that could nevertheless have a material adverse effect on our business, financial condition and results of operations.
Our business depends on
| | | | | | | | | | | | | | |
| BUSINESS AND OPERATING RISKS |
| | | | | | | | | | | | | | |
| The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, have adversely affected and are expected to continue to adversely affect our business, financial condition and results of operations. |
Public health crises, pandemics and epidemics, such as the levelCOVID-19 pandemic, have adversely impacted and are expected to continue to adversely impact our operations, the operations of activity inour customers and the global economy, including the worldwide demand for oil and natural gas industry,and the level of demand for our services. Fear of such events has also altered the level of capital spending by oil and gas companies for exploration and production activities and adversely affected the economies and financial markets of many countries (or globally), resulting in an economic downturn that has affected demand for our services. Actions taken to prevent the spread of COVID-19 by governmental authorities around the world, including imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of such facilities and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions, have significantly reduced global economic activity, thereby resulting in lower demand for crude oil. In particular, the travel restrictions in certain countries where we operate, including the closure of their borders to travel into the country, have resulted in an inability to effectively staff or rotate personnel at, and thereby operate, certain of our rigs and could lead to an inability to fulfill our contractual obligations under contracts with customers. Governmental authorities have also implemented multi-step policies with the goal of re-opening various sectors of the economy. However, certain jurisdictions began reopening only to return to restrictions in the face of increases in new COVID-19 cases, while other jurisdictions are continuing to reopen or have completed the reopening process despite increases in COVID-19 cases. Despite the increased availability of vaccines in certain jurisdictions, the COVID-19 pandemic may continue unabated or worsen during the upcoming months, including as a result of the emergence of more infectious strains of the virus, vaccine hesitancy or increased business and social activities, which ismay cause governmental authorities to reconsider restrictions on business and social activities. In the event governmental authorities increase restrictions, the reopening of the economy may be curtailed. We have experienced, and expect to continue to experience, some disruptions to our business operations, as these restrictions have significantly impacted, and may continue to impact, many sectors of the economy. Depressed economic conditions exacerbated by COVID-19 restrictions in one foreign jurisdiction where we operate have led to an increase in community strikes which have resulted in periodic suspensions of our operations. In addition, the volatilityperceived risk of infection and health risk associated with COVID-19, and the illness of many individuals across the globe, has and will continue to alter behaviors of consumers and policies of companies around the world; such altered behaviors and policies have many of the same effects intended by governmental authorities to stop the spread of COVID-19, such as self-imposed or voluntary social distancing, quarantining, and remote work policies. We are complying with local governmental jurisdiction policies and procedures where our operations reside. In some cases, policies and procedures are more stringent in our foreign operations than in our North America operations.
In early March 2020, the increase in crude oil supply resulting from production escalations from OPEC+ combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Consequently, we saw a significant decrease in customer 2020 capital budgets and a corresponding dramatic decline in the demand for land rigs. Although OPEC+ agreed in April 2020 to cut oil production, OPEC+ has been gradually reducing such cuts and in July 2021, agreed to further reduce such cuts on a monthly basis with a goal of phasing out all production cuts towards the end of 2022. There is no assurance that the most recent OPEC+ agreement will be observed by its parties and OPEC+ may change its agreement depending upon market conditions. Although crude oil prices have recovered since March 2020, oil and natural gas prices are expected to continue to be volatile as a result of near-term production instability, the ongoing COVID-19 pandemic, changes in oil and natural gas inventories, industry demand, global and national economic performance, and the actions of OPEC+.
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These events have had, and could continue to have, an adverse impact on numerous aspects of our business, financial condition and results of operations, including, but not limited to, our growth, costs, loss of workers, 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 our securities and trading markets with respect thereto, our ability to access capital markets, asset impairments and other
factors.accounting changes, certain of our customers experiencing bankruptcy or otherwise becoming unable to pay vendors, including us, and the global economy and financial markets generally. The ultimate extent of the impact of COVID-19 and prolonged excess oil supply on our business, financial condition and results of operations will depend largely on future developments, including the duration and spread of COVID-19 within the United States and the parts of the world in which we operate and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the development, availability, timely distribution and acceptance of effective treatments and vaccines worldwide, all of which are highly uncertain and cannot be predicted with certainty at this time.
| | | | | | | | | | | | | | |
| Our business depends on the level of activity in the oil and natural gas industry, which is significantly impacted by the volatility of oil and natural gas prices and other factors. |
Our business depends on the conditions of the land and offshore oil and natural gas industry. Demand for our services and the rates we are able to charge for such services depend on oil and natural gas industry exploration and production activity and expenditure levels, which are directly affected by trends in oil and natural gas prices and market expectations regarding such prices.
Oil prices continued to fluctuate The sharp decline in fiscal year 2018, but have settled into a range between approximately $50 and $77 per barrel. Oil prices began rebounding in February 2016, and we began experiencing increased demand for our services in May 2016. Nevertheless, both the industry’s active rig count and our active rig count have remained below the peak drilling activity level reached in 2014 when oil prices were significantly higher. Asresulting from the COVID-19 pandemic and the activities of November 8, 2018, 236 rigs included in our U.S. Land segment were under contract, of which 146 were fixed term and 90 were well-to-well. In the event oil prices become depressed 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.
2021 FORM 10-K|19
Oil and natural gas prices and production levels,
can beas well as market expectations regarding such prices and production levels, have been volatile,
which has had, and
may in the future have, adverse effects on our business and operations. The volatility in prices and production levels are impacted by many factors beyond our control, including:
| ·
| | the domestic and foreign supply of, and demand for, oil, natural gas and related products;
|
| ·
| | the cost of exploring for, developing, producing and delivering oil and natural gas;
|
•the domestic and foreign supply of, and demand for, oil, natural gas and related products; | ·
| | uncertainty in capital and commodities markets and the ability of oil and natural gas producers to access capital;
|
•the cost of exploring for, developing, producing and delivering oil and natural gas;•uncertainty in capital and commodities markets and the ability of oil and natural gas producers to access capital; | ·
| | expectations about future oil and natural gas prices and production levels;
|
•the availability of and constraints in storage and transportation capacity, including, for example, takeaway constraints experienced in the Permian Basin over the past several years; | ·
| | the availability of and constraints in pipeline, storage and other transportation capacity in the basins in which we operate, including, for example, takeaway constraints experienced in the Permian Basin;
|
•the worldwide economy; | ·
| | actions of The Organization of Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production levels, including announcements of potential changes to such levels;
|
•expectations about future oil and natural gas prices and production levels; | ·
| | the levels of production of oil and natural gas of non-OPEC countries;
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•local and international political, economic, health and weather conditions, especially in oil and natural gas producing countries, including, for example, the impacts of local and international pandemics and other disasters or events such as the global COVID-19 pandemic; | ·
| | the continued development of shale plays which may influence worldwide supply and prices;
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•actions of OPEC, its members and other oil producing nations, such as Russia, relating to oil price and production levels, including announcements of potential changes to such levels; | ·
| | tax policies of the United States and other countries involved in global energy markets;
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•the levels of production of oil and natural gas of non-OPEC countries; | ·
| | political and military conflicts in oil producing regions or other geographical areas or acts of terrorism in the United States or elsewhere;
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•the continued development of shale plays which may influence worldwide supply and prices; | ·
| | technological advances that are related to oil and natural gas recovery or that affect the global demand for energy;
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•tax policies of the United States and other countries involved in global energy markets; | ·
| | the development and exploitation of alternative energy sources;
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•political and military conflicts in oil producing regions or other geographical areas or acts of terrorism in the United States or elsewhere; | ·
| | legal and other limitations or restrictions on exportation and/or importation of oil and natural gas;
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•technological advances that are related to oil and natural gas recovery or that affect the global demand for energy; | ·
| | local and international political, economic and weather conditions, especially in oil and natural gas producing countries;
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•the development, exploitation and market acceptance of alternative energy sources as part of a transition to a lower carbon economy; | ·
| | laws and governmental regulations affecting the use of oil and natural gas; and
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•increased focus by the investment community on sustainability practices in the oil and natural gas industry; | ·
| | the environmental and other laws and governmental regulations affecting exploration and development of oil and natural gas reserves.
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•legal and other limitations or restrictions on exportation and/or importation of oil and natural gas;•laws and governmental regulations affecting the use of oil and natural gas; and
•the environmental and other laws and governmental regulations affecting exploration and development of oil and natural gas reserves.
The level of land and offshore exploration, development and production activity and the prices of oil and natural gas are volatile and are likely to continue to be volatile in the future. Higher oil and natural gas prices do not necessarily translate into increased activity because demand for our services is typically driven by our customers’ expectations of
future commodity prices.prices, as well as our customers' ability to access sources of capital to fund their operating and capital expenditures. However, a sustained decline in worldwide demand for oil and natural gas, as well as excess supply of oil or natural gas coupled with storage and transportation capacity constraints, shutting in of wells or wells being drilled but not completed, prolonged low oil or natural gas prices would likelyor a reduction in the ability of our customers to access capital, has resulted in, and may in the future result in, reduced exploration and development of land and offshore areas and a decline in the demand for our services, which would likelyhas had, and may in the future, have a material adverse effect on our business, financial condition and results of operations.
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| Global economic conditions and volatility in oil and gas prices may adversely affect our business. |
Concerns over global economic conditions,
energy costs, geopolitical issues, supply chain disruptions, inflation, the availability and
volatility in oilcost of credit and
gas prices may adversely affect our business.Globalthe worldwide COVID-19 pandemic have contributed to increased economic conditions and/or volatility in oil and natural gas prices may impact the ability or desire of our customers to maintain or increase spending on exploration and development drilling. Furthermore, our customers, vendors and/or suppliers may be unable to access financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations.uncertainty. An economic slowdown or recession in the United States or in any other country that significantly affects the supply of or demand for oil or natural gas could negatively impact our operations and therefore adversely affect our results. ChallengingGlobal economic conditions have a significant impact on oil and natural gas prices and any stagnation or deterioration in global economic conditions could result in less demand for our services and could cause our customers to reduce their planned spending on exploration and development drilling. Adverse global economic conditions may cause our customers, vendors and/or suppliers to lose access to the financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations. Furthermore, challenging economic conditions may result in certain of our customers experiencing bankruptcy or otherwise becoming unable to pay vendors, including us. TheIn the past, global economic environment in the past hasconditions, and expectations for future global economic conditions, have sometimes experienced significant deterioration in a relatively short period of time and there can be no assurance that the global economic environmentconditions or expectations for future global economic conditions will recover in the near term or not quickly deteriorate again due to one or more factors. These conditions could have a material adverse effect on our business, financial condition and results of operations.
The contract drilling business is highly competitive and an excess of available drilling rigs may adversely affect our rig utilization and profit margins.
The contract drilling business is highly competitive.
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| The drilling services and solutions business is highly competitive, and a surplus of available drilling rigs may adversely affect our rig utilization and profit margins. |
Competition in
contract drilling
services and solutions involves such factors as price, efficiency, condition, type and operational capability of equipment, reputation, operating safety, environmental impact, customer relations, rig availability and excess rig capacity in the industry. Competition is primarily on a regional basis and may vary significantly by region at any particular time. Land drilling rigs can be readily moved from one region to another in response to changes in levels of activity, which could result in an oversupply of rigs in any region, leading to increased price competition.
Development In addition, development of new drilling technology by competitors has increased in recent years, and future improvements in operational efficiency and safety by our competitorswhich could further negatively affect our ability to differentiate our services. Furthermore, in the event that commodity prices decline, the strategy of differentiation may be less effective if the lower demand for drilling and related technology services intensifies price competition and diminishes the importance of other factors.
We periodically seek to increase the prices on our services to offset rising costs,
earn returns on our capital investment and
tootherwise generate higher returns for our stockholders. However, we operate in a very competitive industry and we are not always successful in raising or maintaining our existing prices. With the active rig count below the peak
seenreached in 2014 and many rigs, including highly capable AC rigs, still idle, there is considerable pricing pressure in the industry. Even if we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset rising costs without adversely affecting our activity levels. The inability to maintain our pricing and to increase our pricing as costs increase could have a material adverse effect on our business, financial position, results of operations and cash flows.
The oil and natural gas services
Following periods of downturn in our industry,
in the United States has experienced downturns in demand during the last decade, including a significant downturn that started in 2014 and bottomed out in 2016. Following such a downturn, there may be substantially more drilling rigs available than necessary to meet demand
even as oil and natural gas prices,
as well asand drilling activity, rebound. In the event of a
glutsurplus of available and more competitive drilling rigs, we may continue to experience difficulty in replacing
fixed‑fixed‑term contracts, extending expiring contracts or obtaining new contracts in the spot market, and new contracts may contain lower dayrates and substantially less favorable terms. As such, we may have difficulty sustaining or increasing rig utilization and profit margins in the future,terms, which could have a material adverse effect on our business, financial condition and results of operations. As of September 30, 2021, 136 of our available rigs were not under contract. New technologies may cause our drilling methods and equipment to become less competitive and it may become necessary to incur higher levels of capital expenditures in order to keep pace with the bifurcation of rigsa significant reduction in the drillingdemand for oil and natural gas services, certain of our competitors may engage in bankruptcy proceedings, debt refinancing transactions, management changes, or other strategic initiatives in an attempt to reduce operating costs to maintain a position in the market. This could result in such competitors emerging with stronger or healthier balance sheets and in turn an improved ability to compete with us in the future. We may also see corporate consolidations among our competitors, which could significantly alter industry conditions and competition within the industry, and growth through the buildinghave a material adverse effect on our business, financial condition and results of new drilling rigs and improvement of existing rigs is not assured.
operations.
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| New technologies may cause our drilling methods and equipment to become less competitive and it may become necessary to incur higher levels of capital expenditures in order to keep pace with the disruptive trends in the drilling industry. Growth through the building of new drilling rigs and improvement of existing rigs is not assured. |
The market for our services is characterized by continual technological developments that have resulted in, and will likely continue to result in, substantial improvements in the functionality and performance, including environmental performance, of rigs and equipment. Our customers increasingly demand the services of newer, higher specification drilling rigs.rigs, as well as new and improved technology, such as drilling automation technology and lower-emissions operations and services. This results in a bifurcation of the drilling fleet and is evidenced by the higher specification drilling rigs (e.g., AC rigs) generally operating at higher overall utilization levels and dayrates than the lower specification drilling rigs (e.g., SCR rigs). In addition, a significant number of lower specification rigs are being stacked and/or removed from service. As a result
2021 FORM 10-K|21
Although we take measures to ensure that we develop and use advanced oil and natural gas drilling technology, changes in technology,
or improvements
in competitors’ equipmentby competitors and increasing customer demands for new and improved technology could make our equipment less competitive. There can be no assurance that we will:
| ·
| | have sufficient capital resources to improve existing rigs or build new, technologically advanced drilling rigs;
|
| ·
| | avoid cost overruns inherent in large fabrication projects resulting from numerous factors such as shortages or unscheduled delays in delivery of equipment or materials, inadequate levels of skilled labor, unanticipated increases in costs of equipment, materials and labor, design and engineering problems, and financial or other difficulties;
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•have sufficient capital resources to improve existing rigs or build new, technologically advanced drilling rigs; | ·
| | successfully deploy idle, stacked, new or upgraded drilling rigs;
|
•avoid cost overruns inherent in large fabrication projects resulting from numerous factors such as shortages or unscheduled delays in delivery of equipment or materials, inadequate levels of skilled labor, unanticipated increases in costs of equipment, materials and labor, design and engineering problems, and financial or other difficulties; | ·
| | effectively manage the increased size or future growth of our organization and drilling fleet;
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•successfully deploy idle, stacked, new or upgraded drilling rigs; | ·
| | maintain crews necessary to operate existing or additional drilling rigs; or
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•effectively manage the increased size or future growth of our organization and drilling fleet; | ·
| | successfully improve our financial condition, results of operations, business or prospects as a result of improving existing drilling rigs or building new drilling rigs.
|
•maintain crews necessary to operate existing or additional drilling rigs; or•successfully improve our financial condition, results of operations, business or prospects as a result of improving existing drilling rigs or building new drilling rigs.
In the event that we are successful in developing new technologies for use in our business, there is no guarantee of future demand for those technologies. Customers may be reluctant or unwilling to adopt our new technologies. We may also have difficulty negotiating satisfactory terms for our technology services or may be unable to secure prices sufficient to obtain expected returns on our investment in the research and development of new technologies.
If we are not successful in upgrading existing rigs and equipment or building new rigs in a timely and
cost‑cost‑effective manner suitable to customer needs, demand for our services could decline and we could lose market share. One or more technologies that we may implement in the future may not work as we expect and our business, financial condition, results of operations and reputation could be adversely affected as a result. Additionally, new technologies, services or standards could render some of our services, drilling rigs or equipment obsolete, which could reduce our competitiveness and have a material adverse impact on our business, financial condition and results of operations.Our drilling related operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.
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| Our drilling and technology related operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us. |
Our operations are subject to the many hazards inherent in the business, including inclement weather, blowouts, explosions, well fires, loss of well control,
equipment failure, pollution, and reservoir damage. These hazards could cause significant environmental
and reservoir damage, personal injury and death, suspension of operations, serious damage or destruction of equipment and property and substantial damage to producing formations and surrounding lands and waters. An accident
or other event resulting in significant environmental
or property damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local authorities. Such an accident
or other event and subsequent crisis management efforts could cause us to incur substantial expenses in connection with investigation and remediation as well as cause lasting damage to our
reputation. reputation, loss of customers and an inability to obtain insurance.
Our Offshore DrillingGulf of Mexico operations are also subject to potentially significant risks and liabilities attributable to or resulting from adverse environmental conditions, including pollution of offshore waters and related negative impact on wildlife and habitat, adverse sea conditions and platform damage or destruction due to collision with aircraft or marine vessels. Our Offshore DrillingGulf of Mexico operations may also be negatively affected by a blowout or an uncontrolled release of oil or hazardous substances by third parties whose offshore operations are unrelated to our operations. We operate several platform rigs in the Gulf of Mexico. The Gulf of Mexico experiences hurricanes and other extreme weather conditions on a frequent basis, which may increase with any climate change. See below “— The physical effects of climate change and the regulation of greenhouse gases and climate change could have a negative impact on our business.” Damage caused
by high winds and turbulent seas could potentially curtail operations on our platform rigs for significant periods of time until the damage can be repaired. Moreover, even if our platform rigs are not directly damaged by such storms, we may experience disruptions in operations due to damage to customer platforms and other related facilities in the area. We also ownlease 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 and could be exposed to damage or disruption by hurricanes and other extreme weather conditions, including coastal flooding, which in turn could affect our business, financial condition and results of operations.
2021 FORM 10-K|22
It is customary in our business to have mutual indemnification agreements with customers on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel, subcontractors, and property. In general, our drilling contracts contain provisions requiring our customers to indemnify us for, among other things, pollution and reservoir damage. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts by us, our subcontractors and/or supplierssuppliers. Additionally, certain states, including Texas, New Mexico, Wyoming, and Louisiana, have enacted statutes generally referred to as "oilfield anti-indemnity acts," which expressly limit certain indemnity agreements contained in or by reason of state anti‑indemnity laws. related to indemnification in contracts, and could expose the Company to financial loss. Furthermore, other states may enact similar oilfield anti-indemnity acts.
Our customers and other third parties may also dispute, or be unable to meet, their contractual indemnification obligations to us. Accordingly, we may be unable to transfer these risks to our customers and other third parties by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition and results of operations.
We insure
working land rigs and related equipment at values that approximate the current replacement cost on the inception date of the policies.
However, we self-insure large deductibles under these policies. We also carry insurance with varying deductibles and coverage limits with respect to
stacked rigs, offshore platform rigs, and “named wind storm” risk in the Gulf of Mexico.
We In addition, we have insurance coverage for comprehensive general liability, automobile liability, workers’ compensation and employer’s liability, and certain other specific risks. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. In some cases, we self-insure large deductibles on certain insurance policies. We retain a significant portion of our expected losses under our workers’ compensation, general liability and automobile liability programs. The Company self‑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.
If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition and results of operations. Our insurance will not in all situations provide sufficient funds to protect us from all losses and liabilities that could result from our operations. Our coverage includes aggregate policy limits. As a result, we retain the risk for any loss in excess of these limits. No assurance can be given that all or a portion of our coverage will not be cancelled during fiscal year 2019, that insurance coverage will continue to be available at rates considered reasonable or that our coverage will respond to a specific loss. 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.
The physical effects of climate change
If a significant accident or other event occurs and the regulation of greenhouse gases and climate changeis not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition and results of operations.
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| Our business is subject to cybersecurity risks. |
Our operations depend on effective and secure information technology systems. Threats to information technology systems, including as a result of cyberattacks and cyber incidents, continue to grow. Cybersecurity risks could include, but are not limited to, ransomware attacks, malicious software, attempts to gain unauthorized access to our data and the unauthorized release, corruption or loss of our data and personal information, interruptions in communication, loss of our intellectual property or theft of our FlexRig® and other sensitive or proprietary technology, loss or damage to our data delivery systems, or other cybersecurity and infrastructure systems, including our property and equipment. In response to the COVID-19 pandemic, the Company moved to a "remote work" model for office personnel in March 2020, and in 2021, the Company introduced full-time or part-time remote work as a permanent option for select employees. A significant number of our office employees work remotely. Remote work relies heavily on the use of remote networking and online conferencing services that enable employees to work outside of our corporate infrastructure and, in some cases, use their own personal devices, which exposes the Company to additional cybersecurity risks, including unauthorized access to sensitive information as a result of increased remote access and other cybersecurity related incidents.
These cybersecurity risks could:
•disrupt our rig operations including operational technologies as well as our corporate information technology systems,
•negatively impact our ability to compete,
•enable the theft or misappropriation of funds,
•cause the loss, corruption or misappropriation of proprietary or confidential information,
•expose us to litigation, and
•result in injury to our reputation, downtime, loss of revenue, and increased costs to prevent, respond to or mitigate cybersecurity events.
2021 FORM 10-K|23
It is possible that our business, financial and other systems could be compromised, which could go unnoticed for a prolonged period of time. While various procedures and controls are being utilized to mitigate exposure to such risk, there can be no assurance that the procedures and controls that we implement, or which we cause third party service providers to implement, will be sufficient to protect our systems, information or other property. Additionally, customers as well as other third parties upon whom we rely 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. 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.
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| Our acquisitions, dispositions and investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition. |
We continually seek opportunities to maximize efficiency and value through various transactions, including purchases or sales of assets, businesses, investments, or joint venture interests. For example, in November 2018 and August 2019, we completed the acquisitions of Angus Jamieson Consulting and DrillScan Energy SAS, respectively. These strategic transactions, among others, are intended to (but may not) result in the realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or income, or the reduction of risk. Acquisition transactions may use cash on hand or be financed by additional borrowings or by the issuance of our common stock. These transactions may also affect our liquidity, consolidated results of operations and consolidated financial condition.
These transactions also involve risks, and we cannot ensure that:
•any acquisitions we attempt will be completed on the terms announced, or at all;
•any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated benefits;
•any acquisitions would be successfully integrated into our operations and internal controls;
•the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, or that we will appropriately quantify the exposure from known risks;
•any disposition would not result in decreased earnings, revenue, or cash flow;
•use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other uses; or
•any dispositions, investments, or acquisitions, including integration efforts, would not divert management resources.
We have allocated a portion of the purchase price of certain acquisitions to goodwill and other intangible assets. Generally, the amount allocated to goodwill is the excess of the purchase price over the net identifiable assets acquired. At September 30, 2021, we had goodwill of $45.7 million and other intangible assets, net of $73.8 million. If we experience future negative changes in our business climate or our results of operations such that we determine that goodwill or intangible assets are impaired, we will be required to record impairment charges with respect to such assets.
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| 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. From time to time, we or our customers or supplying vendors become involved in disputes over infringement of intellectual property rights relating to equipment or technology owned or used by us. As a result, we may lose access to important equipment or technology, be required to cease use of some equipment or technology, be forced to modify our drilling rigs or technology, or be required to pay license fees or royalties for the use of equipment or technology. In addition, we may lose a competitive advantage in the event we are unsuccessful in enforcing our rights against third parties, 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 operations.
2021 FORM 10-K|24
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| Unexpected events could disrupt our business and adversely affect our results of operations. |
Unexpected or unanticipated events, including, without limitation, computer system disruptions, unplanned power outages, fires or explosions at drilling rigs, natural disasters such as hurricanes and tornadoes, war or terrorist activities, supply disruptions, failure of equipment, changes in laws and/or regulations impacting our businesses, pandemic illness and other unforeseeable circumstances that may arise from our increasingly connected world or otherwise, could adversely affect our business.
It is not possible for us to predict the occurrence or consequence of any such events. However, any such events could create unforeseen liabilities, reduce our ability to provide drilling and related technology services, reduce demand for our services, or make it more difficult or costly to provide services, any of which may ultimately have a material adverse effect on our business, financial condition and results of operations.
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| Reliance on management and competition for experienced personnel may negatively impact our operations or financial results. |
We greatly depend on the efforts of our executive officers and other key employees to manage our operations. Similarly, we utilize highly skilled personnel in operating and supporting our businesses and in developing new technologies. In times of high utilization, it can be difficult to find and retain qualified individuals and, during the recent period of sustained declines in oil and natural gas prices, there have been reductions in the oil field services workforce, both of which could result in higher labor costs. We may also face a loss of workers and labor shortages as a result of vaccine mandates or requirements and enforcement of other COVID-19 regulations in jurisdictions where we operate. The loss of members of management or the inability to attract and retain qualified personnel could have a material adverse effect on our business, financial condition and results of operations. In addition, the unexpected loss of members of management, qualified personnel or a significant number of employees due to disease, including COVID-19, disability, or death, could have a detrimental effect on us.
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| The loss of one or a number of our large customers could have a material adverse effect on our business, financial condition and results of operations. |
In fiscal year 2021, we received approximately 50 percent of our consolidated operating revenues from our ten largest drilling services and solutions customers and approximately 23 percent of our consolidated operating revenues from our three largest customers (including their affiliates). If one or more of our larger customers terminated their contracts, failed to renew existing contracts with us, or refused to award us with new contracts, it could have a material adverse effect on our business, financial condition and results of operations. Further, consolidation among oil and natural gas exploration and production companies may reduce the number of available customers.
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| Our current backlog of drilling services and solutions revenue may continue to decline and may not be ultimately realized as fixed‑term contracts and may, in certain instances, be terminated without an early termination payment. |
Fixed‑term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. Even if an early termination payment is owed to us, a customer may be unable or may refuse to pay the early termination payment. We also may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, such as depressed market conditions. As of September 30, 2021, our drilling services backlog was approximately $572.0 million for future revenues under firm commitments. Our drilling services backlog may decline over time as existing contract term coverage may not be offset by new term contracts or price modifications for existing contracts, as a result of any number of factors, such as low or declining oil prices and capital spending reductions by our customers. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse impact on our business, financial condition and results of operations.
2021 FORM 10-K|25
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| Our contracts with national oil companies may expose us to greater risks than we normally assume in contracts with non-governmental customers. |
We currently own and operate rigs and have deployed technology under contracts with foreign national oil companies. In the future, we may expand our international solutions operations and enter into additional, significant contracts with national oil companies. The terms of these contracts may contain non-negotiable provisions and may expose us to greater commercial, political, operational and other risks than we assume in other contracts. Foreign contracts may expose us to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, or under certain conditions that may not provide us with an early termination payment. We can provide no assurance that increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted, or the amount of technology deployed, to national oil companies with commensurate additional contractual risks. Risks that accompany contracts with national oil companies could ultimately have a material adverse impact on our business, financial condition and results of operations.
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| Our drilling services operating expense includes fixed costs that may not decline in proportion to decreases in rig utilization and dayrates. |
Our drilling services operating expense includes all direct and indirect costs associated with the operation, maintenance and support of our drilling equipment, which is often not affected by changes in dayrates and utilization. During periods of reduced revenue and/or activity, certain of our fixed costs (such as depreciation) may not decline and often we may incur additional costs. During times of reduced utilization, reductions in costs may not be immediate as we may incur additional costs associated with maintaining and cold stacking a rig, or we may not be able to fully reduce the cost of our support operations in a particular geographic region due to the need to support the remaining drilling rigs in that region. Accordingly, a decline in revenue due to lower dayrates and/or utilization may not be offset by a corresponding decrease in drilling services and solutions expense, which could have a material adverse impact on our business, financial condition and results of operations.
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| We depend on a limited number of vendors, some of which are thinly capitalized, and the loss of any of which could disrupt our operations. |
Certain key rig components, parts and equipment are either purchased from or fabricated by a limited number of vendors, and we have limited long‑term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply, the acquisition of a vendor by a competitor, increased demands in the industry or other reasons beyond our control. Similarly, certain key rig components, parts and equipment are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from us or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, downturn in the energy industry, supply chain disruptions, or reduction or unavailability of credit. If we are unable to procure certain of such rig components, parts or equipment, our ability to maintain, improve, upgrade or construct drilling rigs could be impaired, which could have a material adverse effect on our business, financial condition and results of operations.
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| Shortages of drilling equipment, supplies or other key materials could adversely affect our operations. |
The drilling services and solutions business is highly cyclical. During periods of increased demand for drilling services and solutions and periods of supply chain disruption, including as a result of COVID-19, delays in delivery and shortages of drilling equipment and supplies can occur. Suppliers may experience quality control issues as they seek to rapidly increase production of equipment and supplies necessary for our operations. Additionally, suppliers may seek to increase prices for equipment and supplies, which we are unable to pass through to our customers, either due to contractual obligations or market constraints in the drilling services and solutions business. These risks are intensified during periods when the industry experiences significant new drilling rig construction or refurbishment. Additionally, in recent months, there have been a number of disruptions and delays across the global supply chain, which have created a tightening of supplies and shortages in a number of areas, including basic raw materials. Any such delays or shortages could have a material adverse effect on our business, financial condition and results of operations.
2021 FORM 10-K|26
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| Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility. |
Certain of our international employees are unionized, and efforts may be made from time to time to unionize other portions of our workforce. We may in the future be subject to strikes or work stoppages and other labor disruptions in connection with unionization efforts or renegotiation of existing contracts with unions representing our international employees. For example, worker strikes of short duration are common in Argentina and our operations have experienced such strikes in the past. Additional unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs, reduce our revenues or limit our operational flexibility.
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| Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations. |
Since our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse effect on our business, financial condition and results of operations.
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| Our business and results of operations may be adversely affected by foreign political, economic and social instability risks, foreign currency restrictions and devaluation, and various local laws associated with doing business in certain foreign countries. |
We currently have drilling operations in South America (primarily Argentina and Colombia) and the Middle East. In the future, we may further expand the geographic reach of our operations. As a result, we are exposed to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of social unrest, strikes, terrorism, war, kidnapping of employees, nationalization, forced negotiation or modification of contracts, difficulty resolving disputes (including technology disputes) and enforcing contract provisions, expropriation of equipment as well as expropriation of oil and gas exploration and drilling rights, taxation policies, foreign exchange restrictions and restrictions on repatriation of income and capital, currency rate fluctuations, increased governmental ownership and regulation of the economy and industry in the markets in which we operate, economic and financial instability of national oil companies, and restrictive governmental regulation, bureaucratic delays and general hazards associated with foreign sovereignty over certain areas in which operations are conducted.
South American countries, in particular, have historically experienced uneven periods of economic growth, as well as recession, periods of high inflation and general economic and political instability. From time to time, these risks have impacted our business. For example, in Argentina, while our dayrate is denominated in U.S. dollars, we are paid in Argentine pesos. The Argentine branch of one of our second-tier subsidiaries then remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars. Argentina also has a history of implementing currency controls, which restrict the conversion and repatriation of U.S. dollars, including controls implemented from September 2019 through 2021. As a result of these currency controls, our ability to remit funds from our Argentine subsidiary to its U.S. parent has been limited. Argentina’s economy is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100% in the most recent three-year period based on inflation data published by the respective governments. Nonetheless, all of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. For fiscal year 2021, we experienced aggregate foreign currency losses of $5.4 million in Argentina. Our aggregate foreign currency losses across all of our operations for fiscal years 2021 and 2020 were $5.3 million and $8.8 million, respectively. However, in the future, we may incur larger currency devaluations, foreign exchange restrictions or other difficulties repatriating U.S. dollars from Argentina or elsewhere, which could have a material adverse impact on our business, financial condition and results of operations.
Additionally, there can be no assurance that there will not be changes in local laws, regulations and administrative requirements or the interpretation thereof, which could have a material adverse effect on the profitability of our operations or on our ability to continue operations in certain areas. Because of the impact of local laws, our future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we have limited control or hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. There can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable.
The future occurrence of one or more international events arising from the types of risks described above could have a material adverse impact on our business, financial condition and results of operations.
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| Covenants in our debt agreements restrict our ability to engage in certain activities. |
Our current debt agreements pertaining to certain long‑term unsecured debt and our unsecured revolving credit facility contain, and our future financing arrangements likely will contain, various covenants that may in certain instances restrict our ability to, among other things, incur, assume or guarantee additional indebtedness, incur liens, sell or otherwise dispose of all or substantially all of our assets, enter into new lines of business, and merge or consolidate. In addition, our credit facility requires us to maintain a funded leverage ratio (as defined therein) of less than or equal to 50 percent and certain priority debt (as defined therein) may not exceed 17.5 percent of our net worth (as defined therein). Such restrictions may limit our ability to successfully execute our business plans, which may have adverse consequences on our operations.
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| We may be required to record impairment charges with respect to our drilling rigs and other assets. |
We evaluate our drilling rigs and other assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Lower utilization and dayrates adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates may result in the recognition of impairment charges if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of an asset group may not be recoverable. Drilling rigs in our fleet may become impaired in the future if oil and gas prices 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 2021 and 2020, we recognized impairment charges of $70.9 million and $563.2 million, respectively, related to tangible assets and equipment. If we experience future negative changes in our business climate such that we determine that one or more of our asset groups are impaired, we will be required to record additional impairment charges with respect to such asset groups.
Any impairment could have a material adverse effect on our consolidated financial statements. The facts and circumstances included in our impairment assessments are described in Part II, Item 8—"Financial Statements and Supplementary Data."
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| A downgrade in our credit ratings could negatively impact our cost of and ability to access capital. |
Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by major U.S. credit rating agencies. Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, commodity pricing levels, industry conditions and other considerations, including the impact of COVID-19. A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.
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| Our ability to access capital markets could be limited. |
From time to time, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health or market perceptions of the drilling and overall oil and gas industry, the liquidity of the capital markets and other factors, including the impact of COVID-19. 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.
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| Our marketable securities may lose significant value due to credit, market and interest rate risks. |
The value of our marketable securities and our investment in ADNOC Drilling Company P.J.S.C are subject to general credit, liquidity, market and interest rate risks, which may be exacerbated by unusual events, such as the COVID-19 pandemic and political instability. A significant loss in value of our investments would negatively impact our debt ratio and financial strength.
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| We may not be able to generate cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations. |
Our ability to make future scheduled payments on or to refinance our debt obligations, including any future debt obligations, depends on our financial position, results of operations and cash flows. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal and interest on our indebtedness. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investment decisions and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness. Furthermore, these alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial position at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would be a default (if not waived) and would likely result in a reduction of our credit rating, which could harm our ability to seek additional capital or restructure or refinance our indebtedness.
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| Changes in the method of determining the London Interbank Offered Rate, or the replacement of the London Interbank Offered Rate with an alternative reference rate, may adversely affect interest expense related to outstanding debt. |
Amounts drawn under our current debt agreements, including the 2018 Credit Facility (as defined herein), may bear interest at rates based on the London Interbank Offered Rate (“LIBOR”). On July 27, 2017, the United Kingdom's Financial Conduct Authority (the "FCA"), which regulates LIBOR, announced that it intends to phase out LIBOR as a benchmark by the end of 2021. On November 30, 2020, ICE Benchmark Administration ("IBA"), the administrator of LIBOR, with the support of the United States Federal Reserve and the FCA, announced a plan to consult on ceasing publication of U.S. dollar LIBOR on December 31, 2021 for only the one week and two month U.S. dollar LIBOR tenors, and on June 30, 2023 for all other U.S. dollar LIBOR tenors, which the FCA subsequently confirmed on March 5, 2021. The U.S. Federal Reserve concurrently issued a statement advising banks to stop new U.S. dollar LIBOR issuances by the end of 2021. Such announcements indicate that the continuation of LIBOR on the current basis cannot and will not be guaranteed after 2021. The 2018 Credit Facility provides for a mechanism to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of U.S. dollar LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the U.S. dollar LIBOR interest rate. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions (the"ARRC"), has proposed a new index calculated by short term repurchase agreements, backed by Treasury securities called the Secured Overnight Financing Rate ("SOFR") as an alternative to LIBOR for use in contracts that are currently indexed to U.S. dollar LIBOR and has proposed a paced market transition plan to SOFR. On July 29, 2021, the ARRC formally recommended SOFR as its preferred alternative replacement rate for U.S. dollar LIBOR. Although SOFR appears to be the preferred replacement rate for U.S. dollar LIBOR at this time, it is not presently known whether SOFR or any other alternative reference rates that have been proposed will attain market acceptance as replacements of U.S. dollar LIBOR. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of U.S. dollar LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could adversely affect the cost of our borrowings and interest expense related to outstanding floating-rate debt and could have an adverse effect on our financial condition, results of operations and cash flows.
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| LEGAL AND REGULATORY RISKS |
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| The physical effects of climate change and the regulation of greenhouse gases and climate change could have a negative impact on our business. |
The physical and regulatory effects of climate change
and a global transition to a low carbon economy could have a negative impact on our operations, our customers’ operations and the overall demand for our
products.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.
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We are aware of the increasing focus of local, state, regional, national and international regulatory bodies on GHG emissions and climate change issues. Legislation to regulate GHG emissions has periodically been introduced in the U.S. Congress and such legislation may be proposed or adopted in the future. In addition, in December 2015, the U.S.United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (the “UNFCCC”) in Paris, France in creating an agreement (the “Paris Agreement”) that requires member countries to review and “represent a progression” in their intended nationally determined GHG contributions, which set GHG emission reduction goals every five years beginning in 2020. The agreement entered into full force in November 2016. On June 1, 2017, the President ofEffective November 4, 2020, the United States announced that the U.S. planned to withdrawStates' withdrawal from the Paris Agreement, which had been announced by President Trump in June 2017, took effect. However, in January 2021, President Biden signed an instrument reversing this withdrawal and to seek negotiations to either reenterthe United States officially rejoined the Paris Agreement on different terms or establish a newFebruary 19, 2021.
framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The aim of the Paris Agreement wasis to hold the increase in the average global temperature to well below 2ºC (3.6ºF) above pre-industrial levels with efforts to limit the rise to 1.5ºC (2.7ºF) to protect against the more severe consequences of climate change forecasted by scientific studies. These consequences include increased coastal flooding, droughts and associated wild fires,wildfires, heavy precipitation events, stresses on water supply and agriculture, increased poverty, and negative impacts on health. In connection with the decision to adopt the Paris Agreement, the UNFCCC invited the Intergovernmental Panel on Climate Change (the “IPCC”) to prepare a special report focused on the impacts of an increase in the average global temperature of 1.5ºC above pre-industrial levels and related GHG emission pathways. The 2018 IPCC Report concludes that the measures set forth in the Paris Agreement are insufficient and that more aggressive targets and measures will be needed. The 2018 IPCC Report indicates that GHGs must be reduced from 2010 levels by 45 percent by 2030 and 100 percent by 2050 to prevent global warming of 1.5ºC above pre-industrial levels.
The IPCC's 2021 Report focusing on the physical science basis of climate change further concluded that an immediate and large-scale reduction in GHG emissions is necessary to limit global warming to 1.5ºC above pre-industrial levels.
It is not possible at this time to predict the timing and effect of climate change or
to predict the effect of the Paris Agreement or whether additional GHG legislation, regulations or other measures will be
adopted.adopted at the federal, state or local levels. However, more aggressive efforts by governments and non-governmental organizations to reduce GHG emissions appear likely based on the findings set forth in the 2018
and 2021 IPCC
ReportReports and any such future laws and regulations could result in increased compliance costs,
or additional operating
restrictions.restrictions or affect the demand for our customers' products and, accordingly, our services. For example, a coalition of over 20 governors of U.S. states formed the United States Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have committed to advance the objectives of the Paris Agreement at the state or local level as well. To this end, the California governor issued an executive order on September 23, 2020 ordering actions to pursue GHG emissions reductions, including a direction to the California State Air Resources Board to develop and propose regulations to require increasing volumes of new zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the sale of new gasoline vehicles by 2035. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse impact on our business, financial condition and results of operations. Further, to the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of or access to capital. Climate change and GHG regulation could also negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide. An increased focus by the public on the reduction of GHG emissions as well as the results of the physical impacts of climate change could affect the demand for our customers’ products and have a negative effect on our business.
Beyond financial and regulatory impacts, the projected severe effects of climate change have the potential to directly affect our facilities and operations and those of our customers. See above “—Our drilling and technology related operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.”Our business is subject to cybersecurity risks.
Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Cybersecurity risks could include, but are not limited to, malicious software, attempts to gain unauthorized access to our data and the unauthorized release, corruption or loss of our data and personal information, interruptions in communication, loss of our intellectual property or theft of our FlexRig and other sensitive or proprietary technology (which could have a negative impact on our ability to compete), loss or damage to our data delivery systems, or other electronic security, including with our property and equipment. These cybersecurity risks could disrupt our operations, negatively impact our ability to compete and result in injury to our reputation, downtime, loss of revenue, and increased costs to prevent, respond to or mitigate cybersecurity events. It is possible that our business, financial and other systems could be compromised, which could go unnoticed for a prolonged period of time. While various procedures and controls can be utilized to mitigate exposure to such risk, cyber incidents and attacks are evolving and unpredictable. Additionally, customers or third parties upon whom we rely face similar threats, which could directly or indirectly impact our business and operations. The occurrence of a cyber-incident or attack could have a material adverse effect on our business, financial condition and results of operations.
Our acquisitions, dispositions and investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We continually seek opportunities to maximize efficiency and value through various transactions, including purchases or sales of assets, businesses, investments, or joint venture interests. For example, in December 2017, we completed the acquisition of Magnetic Variation Services, LLC. We also completed a merger transaction with MOTIVE
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Drilling Technologies, Inc. in June 2017. These strategic transactions, among others, are intended to (but may not) result in the realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or income, or the reduction of risk. Acquisition transactions may use cash on hand or be financed by additional borrowings or by the issuance of our common stock. These transactions may also affect our liquidity, consolidated results of operations and consolidated financial condition.
These transactions also involve risks, and we cannot ensure that:
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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 attempt will be completed on the terms announced, or at all;provide. |
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| | any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated benefits;
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| | any acquisitions would be successfully integrated into our operations and internal controls;
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| | the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, including under the FCPA, or that we will appropriately quantify the exposure from known risks;
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| | any disposition would not result in decreased earnings, revenue, or cash flow;
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| | use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other uses; or
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| | any dispositions, investments, or acquisitions, including integration efforts, would not divert management resources.
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We have allocated a portion of the purchase price of certain acquisitions to goodwill and other intangible assets. Generally, the amount allocated is the excess of the purchase price over the net identifiable assets acquired. At September 30, 2018, we had goodwill of $64.8 million and other intangible assets of $73.2 million. If we experience future negative changes in our business climate or our results of operations such that we determine that goodwill or intangible assets are impaired, we will be required to record impairment charges with respect to such assets.
During the fourth quarter of fiscal year 2018, we recorded goodwill and intangible assets impairment losses of $5.6 million related to the TerraVici reporting unit, one of our technology reporting units, which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018. Our goodwill impairment analysis performed on our remaining technology reporting units in the fourth quarter of fiscal years 2018 and 2017 did not result in impairment charges.
Technology disputes could negatively impact our operations or increase our costs.
Drilling rigs use proprietary technology and equipment which can involve potential infringement of a third party’s rights, or a third party’s infringement of our rights, including patent rights. The majority of the intellectual property rights relating to our drilling rigs and technology services are owned by us or certain of our supplying vendors. However, in the event that we or one of our supplying vendors becomes involved in a dispute over infringement of intellectual property rights relating to equipment owned or used by us, we may lose access to important equipment or technology, be required to cease use of some equipment or technology be forced to modify our drilling rigs or technology, or be required to pay license fees or royalties for the use of equipment or technology. In addition, we may lose a competitive advantage in the event we are unsuccessful in enforcing our rights against third parties. As a result, any technology disputes involving us or our customers or vendors could have a material adverse impact on our business, financial condition and results of operations.
Unexpected events could disrupt our business and adversely affect our results of operations.
Unexpected or unanticipated events, including, without limitation, computer system disruptions, unplanned power outages, fires or explosions at drilling rigs, natural disasters such as hurricanes and tornadoes, war or terrorist activities, supply disruptions, failure of equipment, changes in laws and/or regulations impacting our businesses, pandemic illness and other unforeseeable circumstances that may arise from our increasingly connected world or otherwise, could adversely affect our business. It is not possible for us to predict the occurrence or consequence of any such events. However, any such events could create unforeseen liabilities, reduce our ability to provide drilling and related technology services, reduce demand for our services, or make it more difficult or costly to provide services, any of which may ultimately have a material adverse effect on our business, financial condition and results of operations.
Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti‑bribery legislation could adversely affect our business.
The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti‑bribery laws in other jurisdictions, including the United Kingdom Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti‑bribery laws may conflict with local customs and practices and impact our business. Although we have programs in place requiring compliance with anti‑bribery legislation, any failure to comply with the FCPA or other anti‑bribery legislation could subject us to civil and criminal penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operation. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs or other assets.
New legislationSeveral political and regulatory initiatives relatingauthorities, governmental bodies, and environmental groups devote resources to campaigns aimed at eradicating 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.
fracking. We do not engage in any hydraulic fracturing activities. However, it is a common practice in our industry for our customers to recover natural gas and oil from shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations using water, sand and other additives pumped under high pressure into the formation. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure, waste disposal and/or well construction requirements on oil and gas development, including hydraulic fracturing operations, or otherwise seek to ban fracturing activities altogether. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Members of the U.S. Congress are analyzing, and a number of federal agencies are analyzing, or have historically been requested to review, and, under the current administration, may be requested to review again, a variety of environmental issues associated with hydraulic fracturing and the possibility of more stringent regulation. At September 30, 2021, we had approximately 17 rigs placed on federal land and four rigs in federal waters. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide. For example, the Environmental Protection Agency has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels. Widespread regulation significantly restricting or prohibiting hydraulic fracturing or other drilling activity by our customers could have a material adverse impact on our business, financial condition and results of operations.
Further, we conduct drilling activities in numerous states, including Oklahoma, where seismic activity may occur. In recent years, Oklahoma has experienced an increase in earthquakes. Although the extent of any correlation has been and remains the subject of studies of both federal and state agencies, some parties believe that there is a correlation between hydraulic fracturing related activities and the increased occurrence of seismic activity. As a result, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing activities. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques, operational delays or increased operating and compliance costs in the production of oil and natural gas from shale plays, added difficulty in performing hydraulic fracturing, and potentially a decline in the completion of new oil and gas wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide.
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
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| Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti‑bribery legislation could adversely affect our business. |
The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti‑bribery laws in other jurisdictions, including the United Kingdom Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to non-U.S. officials for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti‑bribery laws may conflict with local customs and practices and impact our business. Although we have programs in place requiring compliance with anti‑bribery legislation, any failure to comply with the FCPA or other anti‑bribery legislation could subject us to civil and criminal penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operation. In addition, investors could negatively view potential violations, inquiries or allegations of misconduct under the FCPA or similar laws, which could adversely affect our reputation and the market for our shares. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs or other assets.
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| Our business is subject to complex and evolving laws and regulations regarding privacy and data protection. |
The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs. In the normal course of business, we and our third-party partners may collect, process, and store data that is subject to those specific laws and regulations governing personal data.
Complying with varying jurisdictional requirements is becoming increasingly complex and could increase the costs and difficulty of compliance, and violations of applicable data protection laws, including but not limited to the European Union General Data Protection Regulation (“GDPR”) and the California Consumer Privacy Act (“CCPA”), could result in significant penalties.
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The GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the European Union. As interpretation and enforcement of the GDPR evolves, it creates a range of new compliance obligations, which could cause us to incur costs or require us to change our business practices in a manner adverse to our business. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover or up to $20.0 million Euro, which may materially adversely affect our business, reputation, results of operations, and cash flows.
The CCPA, which came into effect on January 1, 2020, gives California residents specific rights in relation to their personal information, requires that companies take certain actions, including notifications for security incidents and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could cause us to change our business practices, with the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.
Non-compliance with these and other data protection laws could expose us to regulatory investigations, which could result in fines and penalties. In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations.
We could also be subject to litigation from persons or corporations allegedly affected by data protection violations. In addition, we are also subject to the possibility of cyber incidents or attacks, potentially resulting in a violation of the laws mentioned above. Any violation of these laws or harm to our reputation could have a material adverse effect on our business, financial condition, results of operations and prospects.
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| Government policies, mandates, and regulations specifically affecting the energy sector and related industries, regulatory policies or matters that affect a variety of businesses, taxation polices, and political instability could adversely affect our financial condition and results of operations. |
Energy production and trade flows are subject to government policies, mandates, regulations, and trade agreements. Governmental policies affecting the energy industry, such as taxes, tariffs, duties, price controls, subsidies, incentives, foreign exchange rates, economic sanctions and import and export restrictions, can influence the viability and volume of production of certain commodities, the volume and types of imports and exports, whether unprocessed or processed commodity products are traded, and industry profitability. For example, the decision of the U.S. government to impose tariffs on certain Chinese imports and the resulting retaliation by the Chinese government imposing a 1025 percent tariff on U.S. liquefied natural gas have disrupted aspects of the energy market. Disruptions of this sort can affect the price of oil and natural gas and may cause our customers to change their plans for exploration and production levels, in turn reducing the demand for our services. Moreover, many countries, including the United States, control the import and export of certain goods, services and technology and impose related import and export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. In particular, U.S. sanctions are targeted against certain countries that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities.
Future government policies may adversely affect the supply of, demand for, and prices of oil and
natural gas, restrict our ability to do business in existing and target markets, and adversely affect our business, financial condition and results of operations.
The laws and regulations concerning import and export activity, recordkeeping and reporting, including customs, export controls and economic sanctions, are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Ongoing economic challenges may increase some governments’ efforts to enact, enforce, amend or interpret laws and regulations as a method to increase revenue. Shipments can be delayed and denied import or export for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal or regulatory requirements governing international trade could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
Our business, financial condition and results of operations could be affected by political instability and by changes in other governmental policies, mandates, regulations, and trade agreements, including monetary, fiscal and environmental policies, laws, regulations, acquisition approvals, and other activities of governments, agencies, and similar organizations. These risks include, but are not limited to, changes in a country’s or region’s economic or political conditions, local labor conditions and regulations, safety and environmental regulations, reduced protection of intellectual property rights, changes in the regulatory or legal environment, restrictions on currency exchange activities, currency exchange fluctuations, burdensome taxes and tariffs, enforceability of legal agreements and judgments, adverse tax, administrative agency or judicial outcomes, and regulation or taxation of greenhouse gases. International risks and uncertainties, including changing social and economic conditions as well as terrorism, political hostilities, and war, could limit our ability to transact business in these markets and could adversely affect our business, financial condition and results of operations.
Legal claims and litigation could have a negative impact on our business.
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| Legal claims and litigation could have a negative impact on our business. |
The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. We design much of our own equipment and fabricate and upgrade such equipment in facilities that we operate. We also design and develop our own technology. If such equipment or technology fails to perform as expected, or if we fail to maintain or operate the equipment properly, there could be personal injuries, property damage, and environmental contamination, which could result in claims against us. Our ownership and use of proprietary technology and equipment could also result in infringement of intellectual property claims against us. See above “— Technology disputes could negatively impact our operations or increase our costs." The Company also owns and operates a large fleet of motor vehicles, which creates an increased exposure to motor vehicle accidents. Also, we may be subject, and have been subject in the past, to litigation resulting from accidents involving motor vehicles. These lawsuits have resulted, and may result in the future, in the payment of substantial settlements or damages and increases in our insurance costs. In addition, during periods of depressed market conditions we may be subject to an increased risk of our customers, vendors, former employees and others initiating legal proceedings against us. Further, actions or decisions we have taken or may take as a consequence of COVID-19 may result in investigations, litigation or legal claims against us. Lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations. Any litigation or claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.Reliance on management and competition for experienced personnel may negatively impact our operations or financial results.
We greatly depend on the efforts of our executive officers and other key employees to manage our operations. The loss of members of management could have a material effect on our business. Similarly, we utilize highly skilled personnel in operating and supporting our businesses. In times of high utilization, it can be difficult to retain, and in some cases find, qualified individuals, which may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Additionally, during the recent period of sustained declines in oil and natural gas prices, there was a significant decline in the oil field services workforce. This has reduced the available skilled labor force available to the energy industry, which could also result in higher labor costs. An inability to obtain or find a sufficient number of qualified personnel could have a material adverse effect on our business, financial condition and results of operations.
The loss of one or a number of our large customers could have a material adverse effect on our business, financial condition and results of operations.
In fiscal year 2018, we received approximately 50 percent of our consolidated operating revenues from our ten largest contract drilling customers and approximately 24 percent of our consolidated operating revenues from our three largest customers (including their affiliates). If one or more of our larger customers terminated their contracts, failed to renew existing contracts with us, or refused to award us with new contracts, it could have a material adverse effect on our business, financial condition and results of operations. Further, consolidation among oil and natural gas exploration and production companies may reduce the number of available customers.
Our current backlog of contract drilling revenue may continue to decline and may not be ultimately realized as fixed‑term contracts may, in certain instances, be terminated without an early termination payment.
Fixed‑term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be
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| 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. |
paid to us. Even if an early termination payment is owed to us, a customer may be unable or may refuse to pay the early termination payment. We also may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, such as depressed market conditions. As of September 30, 2018, our contract drilling backlog was approximately $1.1 billion for future revenues under firm commitments. Our contract drilling backlog may decline over time as existing contract term coverage may not be offset by new term contracts or price modifications for existing contracts, as a result of any number of factors, such as low or declining oil prices and capital spending reductions by our customers. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse impact on our business, financial condition and results of operations.
Our contracts with national oil companies may expose us to greater risks than we normally assume in contracts with non-governmental customers.
We currently own and operate rigs and have deployed technology under contracts with foreign national oil companies. In the future, we may expand our international land operations and enter into additional, significant contracts with national oil companies. The terms of these contracts may contain non-negotiable provisions and may expose us to greater commercial, political, operational and other risks than we assume in other contracts. Foreign contracts may expose us to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, or under certain conditions that may not provide us with an early termination payment. We can provide no assurance that increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted, or the amount of technology deployed, to national oil companies with commensurate additional contractual risks. Risks that accompany contracts with national oil companies could ultimately have a material adverse impact on our business, financial condition and results of operations.
Our contract drilling expense includes fixed costs that may not decline in proportion to decreases in rig utilization and dayrates.
Our contract drilling expense includes all direct and indirect costs associated with the operation, maintenance and support of our drilling equipment, which is often not affected by changes in dayrates and utilization. During periods of reduced revenue and/or activity, certain of our fixed costs (such as depreciation) may not decline and often we may incur additional costs. During times of reduced utilization, reductions in costs may not be immediate as we may incur additional costs associated with maintaining and cold stacking a rig, or we may not be able to fully reduce the cost of our support operations in a particular geographic region due to the need to support the remaining drilling rigs in that region. Accordingly, a decline in revenue due to lower dayrates and/or utilization may not be offset by a corresponding decrease in contract drilling expense, which could have a material adverse impact on our business, financial condition and results of operations.
We depend on a limited number of vendors, some of which are thinly capitalized, and the loss of any of which could disrupt our operations.
Certain key rig components, parts and equipment are either purchased from or fabricated by a single or limited number of vendors, and we have no long‑term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply, the acquisition of a vendor by a competitor, increased demands in the industry or other reasons beyond our control. Similarly, certain key rig components, parts and equipment are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from us or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, downturn in the energy industry or reduction or unavailability of credit. If we are unable to procure certain of such rig components, parts or equipment, our ability to maintain, improve, upgrade or construct drilling rigs could be impaired, which could have a material adverse effect on our business, financial condition and results of operations.
Shortages of drilling equipment and supplies could adversely affect our operations.
The contract drilling business is highly cyclical. During periods of increased demand for contract drilling services, delays in delivery and shortages of drilling equipment and supplies can occur. Suppliers may experience quality control issues as they seek to rapidly increase production of equipment and supplies necessary for our operations. Additionally, suppliers may seek to increase prices for equipment and supplies, which we are unable to pass through to
our customers, either due to contractual obligations or market constraints in the contract drilling business. These risks are intensified during periods when the industry experiences significant new drilling rig construction or refurbishment. Any such delays or shortages could have a material adverse effect on our business, financial condition and results of operations.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our international employees are unionized, and efforts may be made from time to time to unionize other portions of our workforce. We may in the future be subject to strikes or work stoppages and other labor disruptions in connection with unionization efforts or renegotiation of existing contracts with unions representing our international employees. Additional unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs, reduce our revenues or limit our operational flexibility.
We may be required to record impairment charges with respect to our drilling rigs and other assets.
We evaluate our drilling rigs and other assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Lower utilization and dayrates adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates may result in the recognition of impairment charges if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of an asset group may not be recoverable. Drilling rigs in our fleet may become impaired in the future if market conditions deteriorate or if oil and gas prices decline further or remain low for a prolonged period. For example, in fiscal years 2018 and 2016, we recognized impairment charges of $17.5 million and $6.3 million, respectively, related to tangible assets and equipment.
Any impairment could have a material adverse effect on our consolidated financial statements. The facts and circumstances included in our impairment assessments are described in Part II, Item 8— “Financial Statements and Supplementary Data.”
We may have additional tax liabilities and/or be limited in our use of net operating losses and tax credits.
We are subject to income taxes in the United States and numerous other jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes and other tax liabilities. In the ordinary course of our business, there are many transactions and calculations where the ultimate tax determination is uncertain. We are regularly audited by tax authorities. Although we believe our tax estimates are reasonable, the final determination of tax audits and any related litigation could be materially different than what is reflected in income tax provisions and accruals. An audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows in the period or periods challenged. Tax rates in the various jurisdictions in which our subsidiaries are organized and conduct their operations may change significantly as a result of political or economic factors beyond our control. It is also possible that future changes to tax laws (including tax treaties in any of the jurisdictions that we operate in) could impact our ability to realize the tax savings recorded to date. Our ability to benefit from our deferred tax assets depends on us having sufficient future taxable income to utilize our net operating loss and tax credit carryforwards before they expire. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”(“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, 2018,2021, we have not experienced an ownership change and, therefore, our utilization of our net operating loss carryforwards was not subject to an annual limitation.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 our pre-change net operating loss carryforwards to offset future taxable income maymight be subject to limitations, which could potentially result in increased future tax liability to us. Furthermore, our acquisition of MOTIVE caused MOTIVE to undergo an ownership change and, as a result, the pre-change net operating losses of MOTIVE are subject to limitation under Section 382; however, based on the amount of such net operating losses subject to the limitation, we do not expect that the application of the Section 382 limitation will have a material impact on our overall future tax liabilities. In addition, at the state level, there may be periods during which the use of net operating loss carryforwards is suspended or otherwise limited, which could accelerate or permanently increase state taxes owed. In any case, our net operating loss andfuture tax credit carryforwards are subject to review and potential disallowance upon audit by
the tax authorities of the jurisdictions where these tax attributes are incurred.liabilities. Additionally, our future effective tax rates could be adversely affected by changes in tax laws (including tax treaties) or their interpretation.
On December 22, 2017, the President of the United States signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred tointerpretation, such as the Tax Cuts and Jobs Act (the “Tax Reform Act”) that significantly reformsproposals by the Code. The Tax Reform Act, among other things, (i) permanently reducesBiden administration to increase the U.S. corporate income tax rate (ii) repealsand increase the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, (v) imposes new limitations on the deductibility of interest expense, (vi) imposes a type of minimum tax designed to reduce the benefits derived from intercompany transactions and payments that result in base erosion, and (vii) provides for more general changes to theU.S. taxation of corporations, including changes to cost recovery rules. These tax law changes could have the effect of causing us to incur incomeinternational business operations.
Our deferred tax liability
sooner than we otherwise would have incurred such liability or, in certain cases,associated with property, plant and equipment is significant, which could
cause us to incurmaterially increase the amount of cash income
tax liabilitytaxes that we
might otherwise not have incurred,pay in the
absence of these tax law changes. Additionally, the Tax Reform Act is complexfuture and,
subject to interpretation. The presentation ofthus, adversely affect our
financial condition andcash flows. Our future capital expenditures, our results of operations
is based upon our current interpretationand changes in income tax laws could significantly impact the timing of the
provisions contained in the Tax Reform Act. In the future, the Treasury Departmentreversal of our deferred tax liabilities and the
Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Reform Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could adversely affect our financial position, income tax provision, net income, or cash flows.We may reduce or suspend our dividend in the future.
We have paid a quarterly dividend for many years. Our most recent, quarterly dividend was $0.71 per share. In the future, our Board of Directors may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position the Company for long‑term success. The declarationtiming and amount of our future dividends is atcash income taxes. While management intends to minimize our income taxes payable in future years to the discretionextent possible, the amount and timing of our Board of Directors and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board of Directors deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. There can be no assurance that we will not reduce our dividend or that we will continue to pay a dividend in the future.
A downgrade in our credit ratings could negatively impact our cost of and ability to access capital.
Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by major U.S. credit rating agencies. Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, commodity pricing levels and other considerations. A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.
Our ability to access capital markets could be limited.
From time to time, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by, among other things, oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health of the drilling and overall oil and gas industry, and the liquidity of the capital markets. Many of the factors that affect our ability to access capital marketsincome taxes ultimately paid are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations.
Our securities portfolio may lose significant value due to a decline in equity prices and other market‑related risks, thus impacting our debt ratio and financial strength.
At September 30, 2018, we had a portfolio of securities with a total fair value of approximately $82.5 million, consisting of Ensco plc (“Ensco”) and Schlumberger, Ltd. The total fair value of the portfolio of securities was $70.2 million at September 30, 2017. The portfolio is recorded at fair valuebased on the balance sheet with changes in unrealized after‑tax value reflected in the equity section of the balance sheet. However, where a decline in fair value below our cost basis is consideredaforementioned factors as well as others and are subject to be other than temporary, the change in value is recorded as a charge through earnings. During the fourth quarter of fiscal year 2016, we determined that a loss was other‑than‑temporary and we recognized a $26.0 million
2021 FORM 10-K|33
impairment charge. No impairment charges were recognized in fiscal year 2017 or 2018. At November 8, 2018, the fair value of the portfolio decreased to approximately $68.5 million.
Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.
Since our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse effect on our business, financial condition and results of operations.
Our business and results of operations may be adversely affected by foreign political, economic and social instability risks, foreign currency restrictions and devaluation, and various local laws associated with doing business in certain foreign countries.
We currently have drilling operations in South America and the Middle East. In the future, we may further expand the geographic reach of our operations. As a result, we are exposed to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of social unrest, strikes, terrorism, war, kidnapping of employees, nationalization, forced negotiation or modification of contracts, difficulty resolving disputes (including technology disputes) and enforcing contract provisions, expropriation of equipment as well as expropriation of oil and gas exploration and drilling rights, taxation policies, foreign exchange restrictions and restrictions on repatriation of income and capital, currency rate fluctuations, increased governmental ownership and regulation of the economy and industry in the markets in which we operate, economic and financial instability of national oil companies, and restrictive governmental regulation, bureaucratic delays and general hazards associated with foreign sovereignty over certain areas in which operations are conducted.
South American countries, in particular, have historically experienced uneven periods of economic growth, as well as recession, periods of high inflation and general economic and political instability. From time to time, these risks have impacted our business. For example, on June 30, 2010, the Venezuelan government expropriated 11 rigs and associated real and personal property owned by our Venezuelan subsidiary. Prior thereto, we also experienced currency devaluation losses in Venezuela and difficulty repatriating U.S. dollars to the United States. Today, our contracts for work in foreign countries generally provide for payment in U.S. dollars. However, in Argentina, while our dayrate is denominated in U.S. dollars, we are paid in Argentine pesos. The Argentine branch of one of our second-tier subsidiaries then remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars. Argentina also has a history of implementing currency controls, which restrict the conversion and repatriation of U.S. dollars. These controls were not in place during this past fiscal year.
Argentina’s economy is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period based on inflation data published by the respective governments. Nonetheless, all of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations.
For fiscal year 2018, we experienced aggregate foreign currency losses of $3.6 million in Argentina. Our aggregate foreign currency losses for fiscal year 2018 and 2017 were $4.0 million and $7.1 million, respectively. However, in the future, we may incur larger currency devaluations, foreign exchange restrictions or other difficulties repatriating U.S. dollars from Argentina or elsewhere, which could have a material adverse impact on our business, financial condition and results of operations.
Additionally, there can be no assurance that there will not be changes in local laws, regulations and administrative requirements or the interpretation thereof, which could have a material adverse effect on the profitability of our operations or on our ability to continue operations in certain areas. Because of the impact of local laws, our future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we have limited control or hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. While we believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can
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| Failure to comply with or changes to governmental and environmental laws could adversely affect our business. |
be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable.
During fiscal year 2018, approximately 9.6 percent of our consolidated operating revenues were generated from the international contract drilling business and approximately 96.0 percent of the international operating revenues were from operations in South America. Substantially all of the South American operating revenues were from Argentina and Colombia. The future occurrence of one or more international events arising from the types of risks described above could have a material adverse impact on our business, financial condition and results of operations.
Failure to comply with or changes to governmental and environmental laws could adversely affect our business.
Many aspects of our operations are subject to various laws and regulations in the jurisdictions where we operate, including those relating to drilling practices and comprehensive and frequently changing laws and regulations relating to the safety and to the protection of human health and the environment. Environmental laws apply to the oil and gas industry including those regulating air emissions, discharges to water, and the transport, storage, use, treatment, disposal and remediation of, and exposure to, solid and hazardous wastes and materials. These laws can have a material adverse effect on the drilling industry, including our operations, and compliance with such laws may require us to make significant capital expenditures, such as the installation of costly equipment or operational changes, and may affect the resale values or useful lives of our drilling rigs. If we fail to comply with these laws and regulations, we could be exposed to substantial administrative, civil and criminal penalties, delays in permitting or performance of projects and, in some cases, injunctive relief. Violations of environmental laws may also result in liabilities for personal injuries, property and natural resource damage and other costs and claims. In addition, environmental laws and regulations in the United States impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of drilling rigs, we may be deemed to be a responsible party under these laws and regulations.
Additional legislation or regulation and changes to existing legislation and regulation may reasonably be anticipated, and the effect thereof on our operations cannot be predicted. The expansion of the scope of laws or regulations protecting the environment has accelerated in recent years, particularly outside the United States, and we expect this trend to continue. To the extent new laws are enacted or other governmental actions are taken that prohibit or restrict drilling in areas where we operate or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or the drilling industry, in particular, our business or prospects could be materially adversely affected.
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| RISKS RELATED TO OUR COMMON STOCK AND CORPORATE STRUCTURE |
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| We may reduce or suspend our dividend in the future. |
We
have paid a quarterly dividend for many years. Our most recent quarterly dividend was $0.25 per share. In the future, our Board of Directors may,
not be ablewithout advance notice, determine to
generate cashreduce or suspend our dividend in order to
service allmaintain 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
indebtedness,Board of Directors and
may be forced to take other actions to satisfy our obligations.Our ability to make future scheduled payments on or to refinance our debt obligations, including any future debt obligations, dependswill depend on our financial position,condition, results of operations, cash flows, prospects, industry conditions, capital requirements and cash flows. Weother factors and restrictions our Board of Directors deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness or uncertainty, such as the current downturn as a result of the COVID-19 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.
2021 FORM 10-K|34
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| The market price of our common stock may be highly volatile, and investors may not be able to resell shares at or above the price paid. |
The trading price of our common stock may be volatile. Securities markets worldwide experience significant price and volume fluctuations. This market volatility, as well as other general economic, market or political conditions, could reduce the market price of our common stock in spite of our operating or financial performance. The following factors, in addition to other factors described in this “Risk Factors” section and elsewhere in this Form 10-K, may have a significant impact on the market price of our common stock:
•changes in customer needs, expectations or trends and our ability to maintain a levelrelationships with key customers;
•our ability to implement our business strategy;
•changes in our capital structure, including the issuance of cash flowsadditional debt;
•public announcements (including the timing of these announcements) regarding our business, financial performance and prospects or new products or services, product enhancements, technological advances or strategic actions, such as acquisitions, restructurings or significant contracts, by our competitors or us;
•trading activity in our stock, including portfolio transactions in our stock by us, our executive officers and directors, and significant stockholders or trading activity that results from operating activities sufficient to permit us to pay the principal and interest on our indebtedness. If our cash flows and capital resources are insufficient to fund our debt service obligations,ordinary course rebalancing of stock indices in which we may be forced to reduce or delay investment decisions and capital expenditures, sell assets, seek additional capital or restructure or refinanceincluded;
•short-interest in our indebtedness. Furthermore, these alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial position at such time. Any refinancing of our debtcommon stock, which could be at higher interest ratessignificant from time to time;
•our inclusion in, or removal from, any stock indices;
•investor perception of us and may require us to comply with more onerous covenants,the industry and markets in which could further restrict our business operations. Any failure to make payments of interest and principalwe operate;
•increased focus by the investment community on our outstanding indebtedness on a timely basis would be a default (if not waived) and would likely result in a reduction of our credit rating, which could harm our ability to seek additional capital or restructure or refinance our indebtedness.Covenants in our debt agreements restrict our ability to engage in certain activities.
Our current debt agreements pertaining to certain long‑term unsecured debt and our unsecured revolving credit facility contain, and our future financing arrangements likely will contain, various covenants that may in certain instances restrict our ability to, among other things, incur, assume or guarantee additional indebtedness, incur liens, sell or otherwise dispose of assets, enter into new lines of business, and merge or consolidate. In addition, our credit facility requires us to maintain a funded leverage ratio (as defined therein) of less than 50 percent and certain priority debt (as
defined therein) may not exceed 17.5 percent of our net worth (as defined therein). Such restrictions may limit our ability to successfully execute our business plans, which may have adverse consequences on our operations.
Certain provisions of our corporate governing documents could make an acquisition ofsustainability practices at our company more difficult.
and in the oil and natural gas industry generally;
•changes in earnings estimates or buy/sell recommendations by securities analysts;
•whether or not we meet earnings estimates of securities analysts who follow us;
•regulatory or legal developments in the United States and foreign countries where we operate; and
•general financial, domestic, international, economic, and market conditions, including overall fluctuations in the U.S. equity markets.
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| Certain provisions of our corporate governing documents could make an acquisition of our company more difficult. |
The following provisions of our charter documents, as currently in effect, and Delaware law could discourage potential proposals to acquire us, delay or prevent a change in control of us or limit the price that investors may be willing to pay in the future for shares of our common stock:
| ·
| | our certificate of incorporation permits our Board of Directors to issue and set the terms of preferred stock and to adopt amendments to our bylaws;
|
| ·
| | our bylaws contain restrictions regarding the right of stockholders to nominate directors and to submit proposals to be considered at stockholder meetings;
|
•our certificate of incorporation permits our Board of Directors to issue and set the terms of preferred stock and to adopt amendments to our bylaws; | ·
| | our bylaws restrict the right of stockholders to call a special meeting of stockholders; and
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•our bylaws contain restrictions regarding the right of stockholders to nominate directors and to submit proposals to be considered at stockholder meetings; | ·
| | we are subject to provisions of Delaware law which restrict us from engaging in any of a broad range of business transactions with an “interested stockholder” for a period of three years following the date such stockholder became classified as an interested stockholder.
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•we are subject to provisions of Delaware law which restrict us from engaging in any of a broad range of business transactions with an “interested stockholder” for a period of three years following the date such stockholder became classified as an interested stockholder.2021 FORM 10-K|35
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| 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. |
There have been intensifying efforts within the investment community (including investment advisors, investment fund managers, sovereign wealth funds, public pension funds, universities and individual investors) to promote the divestment of, or limit investment in, the stock of companies in the oil and gas industry. There has also been pressure on lenders and other financial services companies to limit or curtail financing of companies in the oil and gas industry. Because we operate within the oil and gas industry, if these efforts continue or expand, our stock price and our ability to raise capital may be negatively impacted.
Members of the investment community are increasing their focus on ESG practices and disclosures by public companies, including practices and disclosures related to climate change and sustainability, DE&I initiatives, and heightened governance standards. As a result, we may continue to face increasing pressure regarding our ESG disclosures and practices. These pressures have intensified recently in connection with the COVID-19 pandemic, significant societal events and the Biden Administration’s efforts to mitigate climate change. Additionally, members of the investment community may screen companies such as ours for ESG disclosures and performance before investing in our stock. Over the past few years, there has also been an acceleration in investor demand for ESG investing opportunities, and many large institutional investors have committed to increasing the percentage of their portfolios that are allocated towards ESG investments. With respect to any of these investors, our ESG disclosures and efforts may not satisfy the investor requirements or their requirements may not be made known to us. If we or our securities are unable to meet the ESG standards or investment criteria set by these investors and funds, we may lose investors or investors may allocate a portion of their capital away from us, our cost of capital may increase, and our stock price may be negatively impacted.
Item 1B. UNRESOLVED STAFF COMMENT
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| ITEM 1B. UNRESOLVED STAFF COMMENTS |
We have received no written comments regarding our periodic or current reports from the staff of the SEC that were issued 180 days or more preceding the end of fiscal year 20182021 and that remain unresolved.
Item 2. PROPERTIES
Contract
Drilling
Services and Solutions Operations
Our property consists primarily of drilling rigs and ancillary equipment. We own substantially all of the equipment used in our businesses. For further information on the status of our drilling fleet, see Item 1—
“Business.“Business — Drilling Fleet.”
Real Property
Our corporate headquarters is in leased office space and is located at 1437 South Boulder Avenue, Tulsa, Oklahoma, 74119.
We own or lease office and yard space to support our ongoing
operations. These includeoperations, including field and district offices in
Texas, Oklahoma, Louisiana, Mississippi, Colorado, Wyoming, North Dakota, Ohio, Pennsylvania, Colombia, Argentina,the United States and
Bahrain.internationally. In addition, we have a fabrication and assembly facility
near Houston,in Galena Park, Texas as well as
a fabrication facility and a maintenance and overhaul facility near Tulsa, Oklahoma.
We also own severala limited number of commercial real estate properties located in Tulsa, Oklahoma for investment purposes. Our real estate investments are located exclusively within Tulsa, Oklahoma, and include a shopping center multi-tenant industrial warehouse properties, and undeveloped real estate.
Item 3. LEGAL PROCEEDINGS
Venezuela Expropriation
Our wholly‑owned subsidiaries, Helmerich & Payne International Drilling Co. | | | | | | | | | | | | | | |
| ITEM 3. LEGAL PROCEEDINGS |
See Note 16—Commitments and Helmerich & Payne de Venezuela, C.A. filed a lawsuit in the United States District CourtContingencies to our Consolidated Financial Statements 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 ofinformation regarding 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.legal proceedings.
Item 4. MINE SAFETY DISCLOSURES
| | | | | | | | | | | | | | |
| ITEM 4. MINE SAFETY DISCLOSURES |
30
2021 FORM 10-K|36
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 |
Market Information and Dividends
The principal market on which our common stock is traded is the New York Stock Exchange under the symbol “HP.” As of November 8,
2018,2021, there were
394410 record holders of our common stock as listed by our transfer agent’s records.
We have paid quarterly cash dividends on our common stock during the past two fiscal years. Payment of future dividends will depend on earnings and other factors.
The following performance graph reflects the yearly percentage change in our cumulative total stockholder return on common stock as compared with the cumulative total return on the S&P 500 Index and the S&P 1500 Oil and Gas Drilling600 Index. All cumulative returns assume an initial investment of $100, the reinvestment of dividends and are calculated on a fiscal year basis ending on September 30 of each year.
| | | | | | | | | | | | |
| | | | INDEXED RETURNS |
| | Base Period | | Years Ending |
Company / Index | | Sep 13 | | Sep 14 | | Sep 15 | | Sep 16 | | Sep 17 | | Sep 18 |
Helmerich & Payne, Inc. | | 100 | | 213.72 | | 107.52 | | 160.53 | | 130.54 | | 119.00 |
S&P 500 Index | | 100 | | 142.89 | | 142.02 | | 163.93 | | 194.44 | | 187.00 |
S&P 1500 Oil & Gas Drilling Index | | 100 | | 103.39 | | 44.91 | | 47.75 | | 40.37 | | 55.00 |
PHLX Oil Service Index | | 100 | | 100.00 | | 62.00 | | 66.00 | | 58.00 | | 62.00 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | INDEXED RETURNS |
| Base Period | | Years Ending |
| Company / Index | Sep 2016 | | Sep 2017 | | Sep 2018 | | Sep 2019 | | Sep 2020 | | Sep 2021 |
| Helmerich & Payne, Inc. | 100.00 | | 82.00 | | 111.00 | | 72.00 | | 38.00 | | 58.00 |
| S&P 600 Index | 100.00 | | 120.00 | | 144.00 | | 130.00 | | 120.00 | | 189.00 |
| Dow Jones U.S. Select Oil Equipment & Services Index | 100.00 | | 93.00 | | 95.00 | | 49.00 | | 24.00 | | 42.00 |
| Philadelphia Stock Exchange Oil Service Sector Index | 100.00 | | 88.00 | | 94.00 | | 44.00 | | 22.00 | | 40.00 |
2021 FORM 10-K|37
The above performance graph and related information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Exchange Act, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such a filing.
Information required by this item regarding our
stock portfoliomarketable securities may be found in, and is incorporated by reference to, Item 7—
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Stock Portfolio Held” included in this Form 10‑K.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”Operations — Liquidity and Item 8—“Financial Statements and Supplementary Data”Capital Resources — Investing Activities — Marketable Securities” included in this Form 10‑10‑K.
Five‑year Summary of Selected Financial Data
| | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | 2015 | | 2014 | |
| | (in thousands except per share amounts) | |
Statements of Operations Selected Data | | | | | | | | | | | | | | | | |
Operating revenues | | $ | 2,487,268 | | $ | 1,804,741 | | $ | 1,624,332 | | $ | 3,161,702 | | $ | 3,715,968 | |
Depreciation and amortization | | | 583,802 | | | 585,543 | | | 598,587 | | | 608,039 | | | 523,984 | |
Selling, general and administrative | | | 200,619 | | | 151,002 | | | 146,183 | | | 134,712 | | | 135,273 | |
Income (loss) from continuing operations | | | 493,010 | | | (127,863) | | | (52,990) | | | 420,474 | | | 706,610 | |
Loss from discontinued operations | | | (10,338) | | | (349) | | | (3,838) | | | (47) | | | (47) | |
Net income (loss) | | | 482,672 | | | (128,212) | | | (56,828) | | | 420,427 | | | 706,563 | |
| | | | | | | | | | | | | | | | |
Per Share Data | | | | | | | | | | | | | | | | |
Basic earnings (loss) per share from continuing operations | | | 4.49 | | | (1.20) | | | (0.50) | | | 3.88 | | | 6.52 | |
Basic loss per share from discontinued operations | | | (0.10) | | | — | | | (0.04) | | | — | | | — | |
Basic earnings (loss) per share | | | 4.39 | | | (1.20) | | | (0.54) | | | 3.88 | | | 6.52 | |
Diluted earnings (loss) per share from continuing operations | | | 4.47 | | | (1.20) | | | (0.50) | | | 3.85 | | | 6.44 | |
Diluted loss per share from discontinued operations | | | (0.10) | | | — | | | (0.04) | | | — | | | — | |
Diluted earnings (loss) per share | | | 4.37 | | | (1.20) | | | (0.54) | | | 3.85 | | | 6.44 | |
| | | | | | | | | | | | | | | | |
Cash dividends declared per common share | | | 2.82 | | | 2.80 | | | 2.78 | | | 2.75 | | | 2.63 | |
| | | | | | | | | | | | | | | | |
Balance Sheet Data | | | | | | | | | | | | | | | | |
Property, plant and equipment, net | | | 4,857,382 | | | 5,001,051 | | | 5,144,733 | | | 5,563,170 | | | 5,188,544 | |
Total assets (1) | | | 6,214,867 | | | 6,439,988 | | | 6,832,019 | | | 7,147,242 | | | 6,725,316 | |
Long term debt | | | 493,968 | | | 492,902 | | | 491,847 | | | 492,443 | | | 39,502 | |
Debt to capital ratio (2) | | | 10.1 | % | | 10.6 | % | | 9.7 | % | | 9.1 | % | | 0.8 | % |
Net working capital (3) | | | 412,566 | | | 325,016 | | | 292,857 | | | 316,070 | | | 408,931 | |
| (1)
| | Total assets for all years include amounts related to discontinued operations. Our Venezuelan subsidiary was classified as discontinued operations on June 30, 2010, after the seizure of our drilling assets in that country by the Venezuelan government.
| | | | | | | | | | | |
| ITEM 6. (REMOVED AND RESERVED) |
| (2)
| | The debt to capital ratio is calculated by dividing total debt by total capitalization (total debt plus shareholders’ equity). The debt to capital ratio is not a measure of operating performance or liquidity defined by U.S. GAAP and may not be comparable to similarly titled measures presented by other companies.
|
Removed and reserved. | (3)
| | Net working capital is calculated as current assets, excluding cash and short-term investments, less current liabilities.
|
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | |
| ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion should be read in conjunction with Part I of this Form
10‑10‑K as well as the Consolidated Financial Statements and related notes thereto included in Part II, Item 8— “Financial Statements and Supplementary Data” of this Form 10‑10‑K. Our future operating results may be affected by various trends and factors which are beyond our control. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual ReportForm 10-K under “Cautionary Note regarding Forward-Looking Statements” and Item 1A--1A— “Risk Factors.” Accordingly, past results and trends should not be used by investors to anticipate future results or trends.Executive Summary
2021 FORM 10-K|38
Helmerich & Payne, Inc.
(“H&P,” which, together with its subsidiaries, is identified as the “Company,” “we,” “us,” or “our,” except where stated or the context requires otherwise) through its operating subsidiaries provides performance-driven drilling
servicessolutions and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. As of September 30,
2018,2021, our drilling rig fleet included a total of
390273 drilling rigs. Our
contract drillingreportable operating business segments consist of the
U.S. LandNorth America Solutions segment with
350236 rigs, the Offshore
Gulf of Mexico segment with
8seven offshore platform rigs and the International
LandSolutions segment with
3230 rigs as of September 30,
2018.2021. At the close of fiscal year
2018,2021, we had
259137 contracted rigs, of which
15373 were under a
fixed termfixed-term contract and
10664 were working well-to-well, compared to
21879 contracted rigs at
the same time during the prior year. As the U.S. land drilling industry recovered from an all-time low of approximately 380 active rigs in the summer of 2016 to over 1,000 rigs as of September 30,
2018, we led the way in reactivating rigs in the United States and gained significant market share in the process. We believe that our success during this time frame is validation of the capabilities of our land drilling fleet and our decisions during the downturn to prepare for an eventual improvement in the business, and our ability to deliver best-in-class field performance and customer satisfaction.2020. Our long-term strategy remains focused on innovation, technology, safety, operational excellence and reliability. As we move forward, we believe that our advanced uniform rig fleet,
technology offerings, financial strength,
long term contract backlog and strong customer and employee base position us very well to
respond to continued cyclical and often times volatile market conditions and take advantage of future opportunities.
Market Outlook
Our revenues are derived from the capital expenditures of companies involved in the exploration, development and production of crude oil and natural gas (“E&Ps”).
At the core,Generally, the level of capital expenditures is dictated by current and expected future prices of crude oil and natural gas, which are determined by various supply and demand factors. Both commodities have historically been, and we expect them to continue to be, cyclical and highly volatile.
With respect to
U.S. Land Drilling,North America Solutions, the resurgence of oil and natural gas production coming from the United States brought about by unconventional shale drilling for oil has significantly impacted the supply of oil and natural
gas.gas and the type of rig utilized in the U.S. land drilling industry. The advent of unconventional drilling
for oil in the United States began in
earnest inearly 2009 and continues to evolve as E&Ps drill longer lateral
wells.wells with tighter well spacing. During this time, we designed, built and delivered
to the market new technology AC drive rigs
(FlexRigs) to the market at a fast pace,(FlexRig®), substantially growing our fleet. The pace of progress of unconventional drilling
was interruptedover the years has been cyclical and volatile, dictated by
a decrease in crude oil
prices in late 2014 from $106 per barrel in June 2014and natural gas price fluctuations, which at times have proven to
below $30 per barrel in early 2016.Late in 2017, crude oil prices began to recover, along with the level of activity in unconventional drilling. be dramatic.
Throughout this time, the length of the lateral section of wells drilled in the
U.S.United States has continued to grow. The progression of longer lateral wells has required many of the
industries’industry’s rigs to be upgraded to certain specifications in order to meet the technical challenges of drilling longer lateral wells. The upgraded rigs meeting those specifications are commonly referred to in the industry as super-spec rigs and have the following specific characteristics: AC
Drive,drive, minimum of 1,500 horsepower drawworks,
minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and multiple-well pad capability.
Beginning in 2018, we saw
The technical requirements of drilling longer lateral wells often necessitate the
demanduse of super-spec rigs and even when not required for shorter lateral wells, there is a strong customer preference for super-spec
due to the drilling efficiencies gained in utilizing a super-spec rig. As a result, there has been a structural decline in the use of non-super-spec rigs
increase, as crude oil ranged between $59 and $66 per barrel. During 2018,across the
demand for super-spec rigs continued to increase and we benefitted by gaining market shareindustry. However, as a result of having
a large super-spec fleet, we gained market share and became the largest
provider of super-spec
fleetrigs in the
industry and having the largest number of rigs that could readily and economically be upgraded to the super-spec classification. During fiscal year 2018, we converted two FlexRig4’s to super-spec capacity and upgraded 52 of our other rigs to super-spec, including 51 FlexRig3’s and one FlexRig5. As of September 30, 2018, we held over 40 percent of the super-spec market share in U.S. land drilling. Due to our financial strength, we are in the position to continue to upgrade rigs to super-spec as long as market demand for such rigs remains high and we have a supply of economically viable super-spec upgradable rigs. Thus far in fiscal year 2019, crude oil prices have fallen from recent highs, but are still higher than the average price when exploration and production companies set their 2018 capital budgets. Accordingly, we expect higher levels of exploration and production capital expenditures by our customers in 2019.industry. As such, we expect the demand for super-spec rigs to remain elevated and robust well into fiscal year 2019, andbelieve we are well positioned to continuerespond to upgradevarious market conditions.
In early March 2020, the increase in crude oil supply resulting from production escalations from the Organization of the Petroleum Exporting Countries and other oil producing nations ("OPEC+") combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Specifically, during calendar year 2020, crude oil prices fell from approximately $60 per barrel to the low-to-mid-$20 per barrel range, lower in some cases, which resulted in customers decreasing their 2020 capital budgets nearly 50 percent from calendar year 2019 levels. There was a corresponding dramatic decline in the demand for land rigs, such that the overall rig count for calendar year 2020 averaged roughly 430 rigs, significantly lower than in calendar year 2019, which averaged approximately 940 rigs.
2021 FORM 10-K|39
We experienced much of our rig count decline during the second and third quarters of fiscal year 2020 as our North American Solutions active rig count declined from 195 rigs at December 31, 2019 to super-speca low of 47 rigs in August 2020. However, during the fourth quarter of fiscal year 2020, the market experienced a stabilization of crude oil prices in the $40 per barrel range and subsequently crude oil prices moved toward $50 per barrel as our customers set their capital budgets for calendar year 2021. More recently, crude oil prices have continued to meetincrease, reaching more than $70 per barrel. That said, however, we do not expect rig activity to move in tandem with crude oil prices to the same extent as it has historically. This is primarily due to a large portion of our customers’ needs. In addition, therecustomers having a more disciplined approach to their operations and capital spending. We expect a majority will maintain their activity levels in accordance with their capital budgets for 2021, which were set during a time when crude oil prices were lower and will not adjust spending levels higher as crude oil prices move higher. Along with stabilization of crude prices during the fourth quarter of fiscal year 2020, our rig activity began to increase, and increased more significantly during the first and second quarters of fiscal year 2021. Our North America Solutions active rig count has more than doubled from 47 rigs in August 2020 to 127 rigs at September 30, 2021. We do anticipate further increases in our rig count for the remainder of calendar year 2021 as customers prepare for 2022 operations based upon the expectation that the level of capital spending will be more opportunities driven by our marketing effortshigher in calendar year 2022 than it was in calendar year 2021.
Utilization for our nonsuper-spec FlexRig® fleet peaked in late calendar year 2018 with 216 of 221 super-spec rigs (e.g. FlexRig4) to returnworking (98 percent utilization); however, the subsequent decline in the demand for land rigs resulted in customers idling a large portion of our super-spec FlexRig® fleet. At September 30, 2021, we had 105 idle super-spec rigs out of our FlexRig® fleet of 230 super-spec rigs (54 percent utilization).
Collectively, our other business segments, Offshore Gulf of Mexico and International Solutions, are exposed to the market, targeting on customer programs thatsame macro commodity price environment affecting our North America Solutions segment; however, activity levels in the International Solutions segment are also subject to other various geopolitical and financial factors specific to the countries of our operations. While we do not require super-spec capabilitiesexpect much change in our Offshore Gulf of Mexico segment, we see opportunities for improvement in our International Solutions segment, but those will likely occur on a more extended timeline compared to what we have experienced in the North America Solutions segment.
H&P recognizes the uncertainties and canconcerns caused by the COVID-19 pandemic; however, we have managed the Company over time to be offeredin a position of strength both financially and operationally when facing uncertainties of this magnitude. The COVID-19 pandemic has had a significant financial impact on the Company, including increased costs as a result of labor shortages and logistics constraints. The global response to coping with the pandemic resulted in a drop in demand for crude oil, which, when combined with a more than adequate supply of crude oil, resulted in a sharp decline in crude oil prices, causing our customers to have pronounced pullbacks in their operations and planned capital expenditures. The direct impact of COVID-19 on H&P's operations has created some challenges that we believe the Company is adequately addressing to ensure a robust continuation of our operations albeit at a lower price point while still exceedingactivity level.
The health and safety of all H&P stakeholders - our return hurdles. employees, customers, and vendors - remain a top priority at the Company. Accordingly, H&P has implemented additional policies and procedures designed to protect the well-being of our stakeholders and to minimize the impact of COVID-19 on our ongoing operations. We are also seeing growing interest from customersadhering to enter into multi-year contracts. IfCenter for Disease Control guidelines for evaluating actual and potential COVID-19 exposures and we are complying with local governmental jurisdiction policies and procedures where our operations reside; in some instances, policies and procedures are more stringent in our foreign operations than in our North America operations and this resulted in a complete suspension, for a certain period of time, of all drilling operations in at least one foreign jurisdiction.
In the
market remains strongUnited States, the Company is an ‘essential critical infrastructure’ company as defined by the Department of Homeland Security and the
supply of economically viable super-specCybersecurity and Infrastructure Security Agency and, as such, continues to operate rigs
is depleted, the potential for newly built rigs in the industry may return, but we expect that much higher levels of pricing and
term contract coverage will be required before the industry sees significant capital deployed for new build rigs.In our International Land Drilling segment, we believe that our market leading position in the Neuquén basin of Argentina may provide opportunities for ustechnology solutions, providing valuable services to deploy additional AC rigs from the United States. We have seen periodic spot market work for our deeper drilling 3,000 horsepower rigs in Northern Argentina. Spot market contracts do not have a defined term and operate on a well-by-well basis. In fiscal year 2018, we reactivated four rigs in Colombia with renewed interest in the deeper drilling 3,000 horsepower rigs as well as our two FlexRig3 rigs. We expect Colombia to be a relatively stable market in fiscal year 2019 with potential upside. Overall, we have seen an increase in tendering activity from our customers in support of the international market resultingglobal energy infrastructure.
Since the COVID-19 outbreak began, no rigs have been fully shut down (other than temporary shutdowns for disinfecting) and such measures to disinfect facilities have not had a significant impact on service. We believe our service levels are unchanged from higherpre-pandemic levels.
From a financial perspective, we believe the Company is well positioned to continue as a going concern even through a more protracted disruption caused by COVID-19, oil oversupply and low oil prices. We believehave taken measures to reduce costs and capital expenditures to levels that our international land operations are a potential area of growth over the next several years, but acknowledge that such growth may be more sporadic than what we expect in the U.S. market.At this time, our Offshore Drilling operations are expected to report relatively stable utilization and cash flows in the upcoming fiscal year. We anticipate one or more of our platform rigs could either be stacked or placed onbetter reflect a lower margin stack rate towards the end of fiscal year 2019.
Recent Developments
Acquisitions
On December 8, 2017,activity environment.
The actions we completed an acquisition (“MagVAR Acquisition”) of an unaffiliated company, Magnetic Variation Services, LLC (“MagVAR”), which is now a wholly-owned subsidiary of the Company. The operations for MagVAR are included within our other non-reportable business segments. Through comprehensive 3D geomagnetic reference modeling, MagVAR provides measurement while drilling (“MWD”) survey corrections by identifying and quantifying MWD tool measurement errors in real-time, greatly improving directional drilling performance and wellbore placement. Founded in 2010, MagVAR will maintain its headquarters in Colorado.
At the effective time of the MagVAR Acquisition, MagVAR shareholders received aggregate cash consideration of $47.9 million, net of customary closing adjustments, and certain management members received restricted stock awards covering 213,904 shares of Helmerich & Payne, Inc. common stock. At closing, $6.0 million of the cash consideration was placed in escrow, to be released to the sellers twelve months after the acquisition closing date. Transaction costs related to the MagVAR Acquisition incurredtook during fiscal year 2018 were2020 included a reduction to the annual dividend of approximately $1.2$200 million, and are recordeda reduction of approximately $145 million in the Consolidated Statementsfiscal year 2020 capital spend, a reduction of Operations withinover $50 million in fixed operational overhead, and a reduction of selling, general and administrative expense.
On June 2, 2017,expenses of more than $25 million on an annualized basis. The culmination of these cost-saving initiatives resulted in a $16 million restructuring charge during fiscal year 2020.
Further, we completed a merger transaction (“MOTIVE Merger”) pursuanttook additional steps in fiscal year 2021 to whichreduce our cost structure. These measures will result in an unaffiliated drilling technology company, MOTIVE Drilling Technologies, Inc., a Delaware corporation (“MOTIVE”), was mergedestimated annualized savings of more than $10 million with the full benefit expected to be realized in calendar year 2022. We anticipate further cost reductions going forward; however, implementation of future cost initiatives will be incremental and into our wholly-owned subsidiary Spring Merger Sub, Inc., a Delaware corporation. MOTIVE survivedare anticipated to be realized over the transaction and is now a wholly-owned subsidiary of the Company. MOTIVE has a proprietary Bit Guidance System™ that is an algorithm-driven system that considers the total economic consequences of directional drilling decisions and is designednext few quarters. These cost reduction measures could lead to consistently lower drilling costs through more efficient drilling and increased hydrocarbon production through smoother wellbores and more accurate well placement. Given our strong and longstanding technology and innovation focus, we believe the technology will continue to advance and provide further benefits for the industry.
additional restructuring charges in future periods.2021 FORM 10-K|40
At September 30, 2021, the effective timeCompany had cash and cash equivalents and short-term investments of$1.1 billion and availability under the 2018 Credit Facility (as defined herein) of $750 million. On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the MOTIVE Merger, MOTIVE shareholders received aggregate cash consideration of $74.3 million, net of customary closing adjustments. During fiscal year 2018, MOTIVE shareholders received additional cash consideration of $10.6 million in an earnout payment and may be eligible to receive up to an additional $12.5 million in potential earnout payments based on future performance. Transaction costs related to the MOTIVE Merger incurred during fiscal year 2017 were $3.2 million and are recorded in the Consolidated Statements of Operations within selling, general and administrative expense.
Additional information regarding the MagVAR and MOTIVE acquisitions is described in Note 3--Business Combinations to our consolidated financial statements. The operations for MagVAR and MOTIVE are included within our other non-reportable business segments. The MagVAR and MOTIVE Mergers were accounted for asoutstanding 4.65% unsecured senior notes due 2025 (the "2025 Notes") at a business combinationredemption price calculated in accordance with Accounting Standards Codification (“ASC”) 805, Business Combinations, which requires the assets acquiredindenture governing the 2025 Notes, plus accrued and liabilities assumedunpaid interest on the 2025 Notes to be recorded at their acquisition date fair values.
Impairments
Consistentredeemed. On September 29, 2021, we issued $550.0 million aggregate principal amount of our 2.90% unsecured senior notes due 2031 (the "2031 Notes"). The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021. The proceeds from the offering of the 2031 Notes were used to redeem the 2025 Notes. On October 27, 2021, we redeemed all of the outstanding 2025 Notes. The associated make-whole premium and accrued interest of $58.1 million and the write off of the unamortized discount and debt issuance costs of $3.7 million will be recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 redemption. Subsequent to the redemption, our policy, we evaluate our drilling rigs and related equipment for impairment whenever events or changes in circumstances indicatenear-term liquidity was approximately $1.3 billion. We currently do not anticipate the carrying value of these assets may exceed the estimated undiscounted future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessmentneed to draw on the future marketability2018 Credit Facility. See “—Liquidity and Capital Resources—Senior Notes—2.90% Senior Notes due 2031” below and Note 7—Debt to our Consolidated Financial Statements for more information.
As part of
specific rigs’ asset group. Given the
continued low utilization within our International FlexRig4 asset group and twoCompany's normal operations, we regularly monitor the creditworthiness of our
domesticcustomers and
international conventional rigs’ asset groups, together with the continuedvendors, screening out those that we believe have a high risk of failure to honor their counter-party obligations either through payment or delivery of
new, more capable rigs, we considered these economic factorsgoods or services. We also perform routine reviews of our accounts receivable and other amounts owed to
be indicators that these rigs’ asset groups may potentially be impaired.us to assess and quantify the ultimate collectability of those amounts. At September 30, 2021 and September 30, 2020, the Company had a net allowance against its accounts receivable of $2.1 million and $1.8 million, respectively.
The nature of the COVID-19 pandemic is inherently uncertain, and as a result, the Company is unable to reasonably estimate the duration and ultimate impacts of the pandemic, including the timing or level of any subsequent recovery. As a result, the Company cannot be certain of the degree of impact on the Company’s business, results of operations and/or financial position for future periods.
Treasury and Investments
Senior Notes Offering and Redemption of 4.65% Senior Notes due 2025
On September 29, 2021, we completed our offering of $550.0 million aggregate principal amount of the 2031 Notes. We received net proceeds from the offering of the 2031 Notes of approximately $545.1 million, after deducting the initial purchasers’ discounts and commissions and offering expenses. In October 2021, the net proceeds from the offering were principally used to redeem all $487.1 million aggregate principal amount of our outstanding 2025 Notes. See “—Liquidity and Capital Resources—Senior Notes—2.90% Senior Notes due 2031” below and Note 7—Debt to our Consolidated Financial Statements for more information.
On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 4.65% unsecured senior notes due 2025 (the "2025 Notes") at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. On September 29, 2021, we issued $550.0 million aggregate principal amount of our 2.90% unsecured senior notes due 2031 (the "2031 Notes"). The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021. The proceeds from the offering of the 2031 Notes were used to redeem the 2025 Notes. On October 27, 2021, we redeemed all of the outstanding 2025 Notes. The associated make-whole premium and accrued interest of $58.1 million and the write off of the unamortized discount and debt issuance costs of $3.7 million will be recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 redemption. See “—Liquidity and Capital Resources—Senior Notes—4.65% Senior Notes due 2025” below and Note 7—Debt to our Consolidated Financial Statements for more information.
Credit Facility Maturity Extension
On April 16, 2021, lenders with $680.0 million of commitments under the 2018 we performed impairment testingCredit 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. The remaining $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.
2021 FORM 10-K|41
ADNOC and Helmerich & Payne Strategic Alliance
During September 2021, the Abu Dhabi National Oil Company ("ADNOC") and its subsidiary ADNOC Drilling Company P.J.S.C ("ADNOC Drilling") and the Company jointly announced a strategic alliance, through which ADNOC Drilling acquired eight of our International FlexRig4 asset group,FlexRig® land rigs for $86.5 million. Following this transaction, H&P made a $100.0 million cornerstone investment in ADNOC Drilling's initial public offering subject to a three-year lock up period. Our investment is classified within Investments in our Consolidated Balance Sheets as of September 30, 2021. ADNOC Drilling’s IPO completed on October 3, 2021 and our $100.0 million investment represents 159.7 million shares of ADNOC Drilling, equivalent to a one percent ownership stake.
We will account for our investment in ADNOC Drilling prospectively, after the IPO date of October 3, 2021, as a marketable equity security with a readily determinable fair value. Fair value will be measured using a market approach on a recurring basis and is categorized using the fair value hierarchy. Any changes in such values will be reflected in net income. The availability of inputs observable in the market depends on a variety of factors, including the type of instrument, whether the instrument is actively traded and other characteristics particular to the transaction, which hasincludes the effect of the lock-up period.
This alliance is intended to further drive ADNOC Drilling's growth and expansion as well as enhance their rig-based operational performance by providing them access to our world-class FlexRig® fleet and leveraging our expertise and technologies. Additionally, this alliance facilitates our goal of allocating capital international, particularly in the Middle East and North Africa region, by accelerating our access to the attractive and fast-growing Abu Dhabi market as a key platform for further regional expansion.
The eight rigs had an aggregate net book value of $63.0 million. We concluded that$55.6 million and were recorded as assets held-for-sale in our Consolidated Balance Sheets as of September 30, 2021. The rigs' fair value less estimated cost to sell of $29.0 million, including approximately $24.0 million of cash costs to be incurred, approximated their net book values at September 30, 2021. Two of the eight rigs were already located in the U.A.E where ADNOC Drilling is domiciled with the remaining six rigs to be shipped from the United States. As part of the sales agreement, the rigs will be delivered and commissioned in stages over a twelve-month period subject to acceptance upon successful completion of final inspection on customary terms and conditions. No rigs have been delivered to ADNOC Drilling as of September 30, 2021.
Property, Plant and Equipment
Sale of Offshore Rig
During the first quarter of fiscal year 2021, we closed on the sale of an offshore platform rig within our Offshore Gulf of Mexico operating segment for total consideration of $12.0 million with an aggregate net book value of
the asset group$2.8 million, resulting in a gain of $9.2 million, which is
recoverable through estimated undiscounted future cash flows with a surplusincluded within (gain) loss on sale of
approximately 23 percent. The most significant assumptions used inassets on our
undiscounted cash flow model include: timing on awardsConsolidated Statements of
future drilling contracts, oil prices, operating dayrates, operating costs, rig reactivation costs, drilling rig utilization, revenue efficiency, estimated remaining economic useful life and net proceeds received upon future sale/disposition. The assumptions are consistent with the Company’s internal budgets and forecasts for future years. These significant assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. Although we believe the assumptions used in our analysis are reasonable and appropriate and the asset group weighted average of expected future undiscounted net cash flows exceeds the net book value of the asset group as ofOperations during the fiscal year
2018 year-end impairment evaluation, different assumptions and estimates could materially impact the analysis and our resulting conclusion.Atended September 30, 2018, we engaged2021.
Assets Held-for-Sale
In March 2021, the Company's leadership continued the execution of the current strategy, which was initially introduced in 2019, focusing on operating various types of highly capable upgraded rigs and phasing out the older, less capable fleet. As a
third party independent accounting firm who performedresult, the Company has undertaken a
market valuation, utilizingplan to sell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the
market approach, on twomajority of
our domestic and international conventional rigs’ asset groups, which
have aggregate netwere previously decommissioned, written down and/or held as capital spares. The book values of
$9.0those assets were written down to $13.5 million,
and $15.2 million, respectively. We concluded thatwhich represents the fair
values of these two asset groups exceed the net book values by approximately 64 percentvalue less estimated cost to sell, and
141 percent, respectively, andwere reclassified as
such, no impairment was recorded. The significant assumptionsheld-for-sale in the
valuation exercise are classified as Level 2second and
Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures.During the fourththird quarter of fiscal year 2018, after ceasing operations in Ecuador, within our International Land segment,2021. As a result, we entered into a sales negotiation with respect to the six conventional rigs, within a separated international conventional rigs’ asset group, with net book values of $20.8 million, present in the country, pursuant to which the rigs, together with associated equipment and machinery would be sold to a third party to be recycled. Certain components of these rigs with an $8.5 million net book value, that are not subject to the sale agreement, will be transferred to the United States to be utilized on other FlexRigs with high activity and demand. The sales transaction was completed in November 2018. We recordedrecognized a non-cash impairment charge of $9.2$56.4 million, ($7.0 million, net of tax, or $0.06 per diluted share), which is includedduring the fiscal year ended September 30, 2021, in Asset Impairment Charge on the Consolidated Statement of Operations. During the year ended September 30, 2021, we completed the sale of a portion of the assets with a net book value of $6.5 million that were originally classified as held-for-sale during the second and third quarter of fiscal year 2021.
During the fiscal year ended September 30, 2021, we formalized a plan to sell assets related to two of our lower margin service offerings, trucking and casing running services, which contributed approximately 2.8 percent to our consolidated revenue during fiscal year 2021, all within our North America Solutions segment. The combined net book values of these assets of $23.2 million were written down to their combined fair value less estimated cost to sell of $8.8 million, and were reclassified as held-for-sale in the Consolidated Balance Sheets as of September 30, 2021. As a result, we recognized a non-cash impairment charge of $14.4 million in the Consolidated Statement of Operations during the year ended September 30, 2021.
Subsequent to September 30, 2021, we closed on the sale of these assets in two separate transactions. The sale of our trucking services was completed on November 3, 2021 while the sale of our casing running services was completed on November 15, 2021 for combined cash consideration less costs to sell of $5.8 million in addition to the possibility of future earnout revenue.
2021 FORM 10-K|42
Restructuring
During the second quarter of fiscal year 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 restructuring are primarily comprised of one-time severance benefits to employees who were involuntarily terminated. The termination date of some of the employees extend beyond September 30, 2021, and such employees are required to render service through their respective termination date in order to receive the one-time severance benefit. During the third quarter of fiscal year 2021, we commenced a voluntary separation program at our local office in Argentina for which we incurred one-time severance charges for employees who were voluntarily terminated. Total costs incurred related to our IT reorganization and our Argentina separation program were $1.5 million for the fiscal year ended September 30, 2018.2021.
Additionally, we continue to take measures to lower our cost structure based on activity levels. During fiscal year 2021, we incurred $4.5 million in one-time moving related expenses primarily due to the downsizing and relocation of our Houston assembly facility and various storage yards used for idle rigs. This together with additional restructuring activities that could result from our in-process cost management review could result in additional restructuring charges throughout the year.
Drilling contract backlog is the expected future dayrate revenue from executed contracts. We calculate backlog as the total expected revenue from fixed-term contracts and do not include any anticipated contract renewals or expected performance bonuses as part of its calculation. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. In addition to depicting the total expected revenue from fixed-term contracts, backlog is indicative of expected future cash flow that the Company expects to receive regardless of whether a customer honors the fixed-term contract to expiration of a contract or decides to terminate the contract early and pay an early termination payment. In the event of an early termination payment, the timing of the recognition of backlog and the total amount of revenue may differ; however, the overall associated cash flow is preserved. As such, management finds backlog a useful metric for future planning and budgeting, whereas investors consider it useful in estimating future revenue and cash flows of the Company. As of September 30, 2021 and 2020, our contract drilling backlog was $572.0 million and $658.0 million, respectively. These amounts do not include any anticipated contract renewals or expected performance bonuses. The decrease in backlog at September 30, 2021 from September 30, 2020 is primarily due to prevailing market conditions causing a decline in the number of longer term drilling contracts executed. Approximately 22.9 percent of the September 30, 2021 total backlog is reasonably expected to be fulfilled in fiscal year 2023 and thereafter.
Fixed-term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term. As a result
of the
remaining rig withindepressed market conditions and negative outlook for the
same asset group, not to be disposed of, was written down resultingnear term, beginning in
an additional impairment charge of $1.4 million ($1.0 million, net of tax, or $0.01 per diluted share).Furthermore, during the fourthsecond quarter of fiscal year 2018, within2020, certain of our U.S. Land segment, management committedcustomers, as well as those of our competitors, opted to a planrenegotiate or early terminate existing drilling contracts. Such renegotiations included requests to auction several previously decommissioned rigs during fiscal year 2019. As a result, we wrote them down to their estimated fair values.lower the contract dayrate in exchange for additional terms, temporary stacking of the rig, and other proposals. We recorded a non-cash impairment charge of $5.7recognized $7.7 million ($4.2and $73.4 million net of tax, or $0.04 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statements of Operationsearly termination revenue associated with term contracts for the fiscal yearyears ended September 30, 2018.
2021 and 2020, respectively. 36
The following table sets forth the total backlog by reportable segment as of September 30, 2021 and 2020, and the percentage of the September 30, 2021 backlog reasonably expected to be fulfilled in fiscal year 2023 and thereafter: | | | | | | | | | | | | | | | | | |
| (in millions) | September 30, 2021 | | September 30, 2020 | | Percentage Reasonably Expected to be Fulfilled in Fiscal Year 2023 and Thereafter |
| North America Solutions | $ | 429.6 | | | $ | 542.4 | | | 17.4 | % |
| Offshore Gulf of Mexico | 17.2 | | | 16.7 | | | — | |
| International Solutions | 125.2 | | | 98.9 | | | 45.1 | |
| | $ | 572.0 | | | $ | 658.0 | | | |
The early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. In some limited circumstances, such as sustained unacceptable performance by us, no early termination payment would be paid to us. Early terminations could cause the actual amount of revenue earned to vary from the backlog reported. See Item 1A—"Risk Factors—Our current backlog of drilling services and solutions revenue may continue to decline and may not be ultimately realized as fixed‑term contracts and may, in certain instances, be terminated without an early termination payment” within this Form 10-K regarding fixed term contract risk. Additionally, see Item 1A—"Risk Factors—The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, have adversely affected and are expected to continue to adversely affect our business, financial condition and results of operations" within this Form 10-K.
2021 FORM 10-K|43
During the fourth quarter of fiscal year 2018, and as part of our annual goodwill impairment test, we performed a detailed assessment of the TerraVici technology reporting unit, where $4.7 million goodwill was allocated. We determined that the estimated fair value of this reporting unit was less than its carrying amount and recorded goodwill impairment losses of $4.7 million ($3.5 million, net of tax, or $0.03 per diluted share). In addition, we recorded an intangible asset impairment loss of $0.9 million ($0.7 million, net of tax, or $0.01 per diluted share). These impairment losses are included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018. Our goodwill impairment analysis performed on our remaining technology reporting units in the fourth quarter of fiscal years 2018 and 2017 did not result in impairment charges.
Results of Operations for the Fiscal Years Ended September 30, 2018 and 2017
| | | | | | | | | | | | | | |
Results of Operations for the Fiscal Years Ended September 30, 2021 and 2020 |
Consolidated Results of Operations
All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Except as specifically discussed, the following results of operations pertain only to our continuing operations.
Net Income (Loss)Our net incomeLoss We reported a loss from continuing operations of $337.5 million ($3.14 loss per diluted share) from operating revenues of $1.2 billion for the fiscal year 2018 was $482.7ended September 30, 2021 compared to a loss from continuing operations of $496.4 million ($4.39 earnings4.62 loss per diluted share), compared with from operating revenues of $1.8 billion for the fiscal year ended September 30, 2020. Included in the net loss for the fiscal year ended September 30, 2021 is income of $11.3 million ($0.10 per diluted share) from discontinued operations. Including discontinued operations, we recorded a net loss of $128.2$326.2 million ($1.203.04 loss per share) for fiscal year 2017. Net income in fiscal year 2018 and net loss in fiscal year 2017 include after-tax income from early termination revenue associated with drilling contracts terminated prior to the expiration of their fixed term of $12.6 million ($0.12 per share) and $20.2 million ($0.18 per share), respectively. Net income in fiscal year 2018 and net loss in fiscal year 2017 include after‑tax gains from the sale of assets of $16.7 million ($0.15 per diluted share) and $14.3for the fiscal year ended September 30, 2021 compared to a net loss of $494.5 million ($0.134.60 loss per diluted share), respectively. Additionally, net income in for the fiscal year 2018 and net loss in fiscal year 2017 includes after-tax income from a tax benefit of $477.2 million ($4.36 per diluted share) and a tax benefit of $56.7 million ($0.52 per diluted share), respectively.ended September 30, 2020.
Revenue Consolidated operating revenues were $2.5$1.2 billion in fiscal year 20182021 and $1.8 billion in fiscal year 2017,2020, including early termination revenue of $17.1$7.7 million and $29.4$73.4 million in each respective fiscal year. Excluding early termination revenue, operating revenue increased $694.8 milliondecreased $0.5 billion in fiscal year 20182021 compared to fiscal year 2017. Oil prices steeply declined from over $106 per barrel in June 2014 to below $30 per barrel in early 2016. During the second half of calendar year 2016, oil prices increased and fluctuated within a $42 to $54 per barrel price range for most of fiscal year 2017. However, during the second half of fiscal year 2018, oil prices were mostly in the $62 to $77 per barrel price range. Primarily as a result of the impact of oil prices on drilling activity by exploration and production companies during that time frame, the number of revenue days in our U.S. Land segment totaled 77,9802020. The decrease in fiscal year 2018, compared to 57,120 in2021 from fiscal year 2017.Asset Impairment Management monitors industry market conditions impacting its long‑lived assets, intangible assets2020 was driven by lower activity, lower early termination revenue, and goodwill. When required, an impairment analysis is performed to determine if any impairment exists. During the fourth quarter of fiscal year 2018, and after ceasing operations in Ecuador, we entered into a sales negotiation with respect to the six conventional rigs present in the country, pursuant to which the rigs, together with associated equipment and machinery, would be sold to a third party to be recycled. As a result, we recorded a non-cash impairment charge of $9.2 million. The remaininglower average rig within the same asset group, not to be disposed of, was written down resulting in an additional impairment charge of $1.4 million ($1.0 million, net of tax, or $0.01 per diluted share). Additionally, during the fourth quarter of fiscal year 2018, management committed to a plan to auction several previously decommissioned rigs during fiscal year 2019. As a result, we wrote them down to their estimated fair values and we recorded a non-cash impairment charge of $5.7 million. Furthermore, during the fourth quarter of fiscal year 2018, we recorded goodwill and intangible assets impairment losses of $5.6 million related to the TerraVici technology reporting unit. The fiscal year 2018 asset impairment charges are included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018. We did not record any impairment in fiscal year 2017.
Interest and Dividend Income Interest and dividend income was $8.0 million and $5.9 million in fiscal years 2018 and 2017, respectively. The higher income in fiscal year 2018 was primarily due to higher earnings on available cash equivalents and short-term investments.
pricing.
Direct Operating Expenses, Excluding Depreciation and AmortizationDirect operating expenses in fiscal year 20182021 were $1.7$1.0 billion, compared with $1.2 billion in fiscal year 2017.2020. The increasedecrease in fiscal year 20182021 from fiscal year 20172020 was primarily attributable to athe previously mentioned lower activity levels, partially offset by fixed overhead costs and higher level of activity inrig recommissioning expenses, as we reactivated rigs across fiscal year 2018.2021. General and Administrative Expense General and administrative expenses totaled $200.6 million in fiscal year 2018 and $151.0 million in fiscal year 2017. During fiscal year 2018, we incurred transaction costs of $1.2 million related to our acquisition of MagVAR. Additionally, increased employee general and administrative headcount, primarily as a result of the acquisition of MagVAR and MOTIVE, caused an increase in employee compensation costs, including taxes, benefits and stock-based compensation, compared to fiscal year 2017.
Depreciation and Amortization Depreciation and amortization expense was $583.8$419.7 million in fiscal year 20182021 and $585.5$481.9 million in fiscal year 2017.2020. The decrease in depreciation and amortization during fiscal year ended September 30, 2021 compared to fiscal year ended September 30, 2020 was primarily attributable to the lower carrying cost of our impaired assets as well as ongoing low levels of capital expenditures. Depreciation and amortization includes amortization of intangible assets of $5.4 million and $1.1$7.2 million in fiscal years 20182021 and 2017, respectively,2020, and abandonments of equipment of $27.7$2.0 million and $42.6$4.0 million in fiscal years 20182021 and 2017,2020, respectively. In
Research and DevelopmentFor the fiscal years ended September 30, 2021 and 2020, we incurred $21.7 million and $21.6 million, respectively, of research and development expenses.
Selling, General and Administrative Expense Selling, general and administrative expenses increased to $172.2 million in the fiscal year 2018, depreciation expense also includes $9.7ended September 30, 2021 compared to $167.5 million of accelerated depreciation for components on rigs that are planned for conversionin the fiscal year ended September 30, 2020. The $4.7 million increase in fiscal year 2019. Depreciation2021 compared to fiscal year 2020 is primarily due to higher accrued variable compensation expense exclusiveand professional service fees.
Asset Impairment During the fiscal year ended September 30, 2021, we undertook a plan to sell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the majority of abandonmentswhich were previously decommissioned, written down and/or held as capital spares. This resulted in an impairment charge of $56.4 million ($43.3 million, net of tax, or $0.40 per diluted share. During the fiscal year ended September 30, 2021, we formalized a plan to sell assets related to two of our lower margin service offerings, trucking and accelerated depreciation, increased one percentcasing running services, all within our North America Solutions segment. The combined book values of these assets were written down to $8.8 million, which represents their combined fair value less cost to sell, and were reclassified as held-for-sale in the Consolidated Balance Sheets as of September 30, 2021. As a result, we recognized a non-cash impairment charge of $14.4 million ($10.9 million, net of tax, or $0.10 per diluted share). Comparatively, during the fiscal year ended September 30, 2020, we recorded an asset impairment charge of $563.2 million ($437.5 million, net of tax, or $5.21 per diluted share) resulting from impairment of several assets including rotational inventory, property, plant and equipment, and goodwill.
Restructuring ChargesDuring the fiscal years ended September 30, 2021 and 2020, we incurred $5.9 million and $16.0 million, respectively, in restructuring charges. The charges incurred during the fiscal year ended September 30, 2021 included $1.5 million in one-time severance benefits paid to employees who were voluntarily or involuntarily terminated primarily as a result of the reorganization of our IT operations coupled with charges of $4.5 million primarily related to the relocation of our Houston assembly facility and the downsizing of our storage yards used for idle rigs. The charges incurred during the fiscal year ended September 30, 2020 were primarily comprised of $19.5 million in one-time severance benefits to employees who were voluntarily or involuntarily terminated, offset by a benefit of $3.5 million related to forfeitures and modifications of stock-based compensation awards.
2021 FORM 10-K|44
Interest and Dividend Income Interest and dividend income was $10.3 million and $7.3 million in fiscal years 2021 and 2020, respectively. The increase in interest and dividend income in fiscal year 20182021 was primarily due to $3.2 million of interest income received from fiscal year 2017. As the drilling markets continuedU.S. Department of the Treasury related to recover during fiscal year 2017, we began abandoning older rig components that were replaceda tax refund, partially offset by upgrades to our rig fleet to meet customer demands for additional capabilities. This trend continued in fiscal year 2018.lower interest rates.
Interest Expense Interest expense net of amounts capitalized, totaled $24.3$24.0 million in fiscal year 20182021 and $19.7$24.5 million in fiscal year 2017.2020. Interest expense is primarily attributable to fixed‑rate debt outstanding. Capitalized interest was $0.4 million and $0.3 million in fiscal years 2018 and 2017, respectively. All of the capitalized interest is attributable to our rig upgrade and rig construction programs. Income Taxes We had an income tax benefit of $477.2$103.7 million in fiscal year 20182021 compared to an income tax benefit of $56.7$140.1 million in fiscal year 2017.2020. The effective income tax rate was (3,012.3)23.5 percent in fiscal year 20182021 compared to 30.722.0 percent in fiscal year 2017.2020. The effective tax rate for fiscal year 2018 was impacted by income tax adjustments related to the reduction of the federal statutory corporate income tax rate as part of the Tax Reform Act, which was enacted on December 22, 2017, and an increase in the deferred state income tax rate. In addition, effective tax rates differ from the U.S. federal statutory rate (24.5(21.0 percent for fiscal year 2018years 2021 and 35.0 percent for fiscal year 2017)2020) due to non-deductible permanent items, and state and foreign income taxes. taxes, and adjustments to the deferred state income tax rate.
Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated, and necessary allowances are provided. The carrying
valuevalues of the net deferred tax assets
isare based on management’s judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future. See Note 8—Income Taxes to our Consolidated Financial Statements for additional income tax disclosures.
Research and Development During fiscal years 2018 and 2017, we incurred $18.2 million and $12.0 million, respectively, of research and development expenses. The increase in expense is primarily related to the acquisitions of MOTIVE and MagVAR given that a portion of their ongoing expenses are classified as research and development. We anticipate research and development expenses to continue during fiscal year 2019.
Discontinued OperationsExpenses incurred within the country of Venezuela are reported as discontinued operations. In March 2016, the Venezuelan government implemented the previously announced plans for a new foreign currency exchange system. Our wholly-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 taking of our Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. In March 2016, the Venezuelan government implemented the previously announced plans for a new foreign currency exchange system. Activity within discontinued operations for both fiscal years 20172021 and 20182020 is primarily a result of the impact of exchange rate fluctuations on remainingdue to the remeasurement of an uncertain tax liability.
North America Solutions
The following table presents certain information with respect to our North America Solutions reportable segment:
| | | | | | | | | | | | | | | | | |
| (in thousands, except operating statistics) | 2021 | | 2020 | | % Change |
| Operating revenues | $ | 1,026,364 | | | $ | 1,474,380 | | | (30.4) | % |
| Direct operating expenses | 773,507 | | | 942,277 | | | (17.9) | |
| Segment gross margin | 252,857 | | | 532,103 | | | (52.5) | |
| | | | | |
| Depreciation and amortization | 392,415 | | | 438,039 | | | (10.4) | |
| Research and development | 21,811 | | | 20,699 | | | 5.4 | |
| Selling, general and administrative expense | 51,089 | | | 53,714 | | | (4.9) | |
| Asset impairment charge | 70,850 | | | 406,548 | | | (82.6) | |
| Restructuring charges | 3,868 | | | 7,005 | | | (44.8) | |
| Segment operating loss | $ | (287,176) | | | $ | (393,902) | | | (27.1) | |
| | | | | |
Operating Statistics1: | | | | | |
| Average active rigs | 107 | | | 134 | | | (20.1) | |
| Number of active rigs at the end of period | 127 | | | 69 | | | 84.1 | |
| Number of available rigs at the end of period | 236 | | | 262 | | | (9.9) | |
| Reimbursements of "out-of-pocket" expenses | $ | 113,897 | | | $ | 171,455 | | | (33.6) | |
(1)These operating metrics allow investors to analyze the various components of segment financial results in country assetsterms of activity, utilization and liabilities.other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. Beginning in the first quarter of fiscal year 2021, these operating metrics replaced previously used per day metrics. As a result, prior year comparative information is also provided above.
Segment Gross Margin The North America Solutions segment gross margin was $252.9 million for the fiscal year ended September 30, 2021 compared to $532.1 million for the fiscal year ended September 30, 2020. The decrease was primarily driven by lower activity levels, lower early termination revenue, lower average rig pricing, and higher rig recommissioning expenses. Revenues were $1.0 billion and $1.5 billion in fiscal year 2021 and 2020, respectively. The decrease in operating revenue is primarily due to the factors mentioned above. Included in revenues for fiscal year 2021 is early termination revenue of $5.8 million2021 FORM 10-K|45
U.S. Land Operations Segment
| | | | | | | | | |
| | 2018 | | 2017 | | % Change |
| | (in thousands, except operating statistics) |
Operating revenues | | $ | 2,068,195 | | $ | 1,439,523 | | 43.7 | % |
Direct operating expenses | | | 1,348,533 | | | 984,205 | | 37.0 | |
Selling, general and administrative expense | | | 58,157 | | | 50,712 | | 14.7 | |
Depreciation | | | 505,112 | | | 499,486 | | 1.1 | |
Asset impairment charge | | | 5,695 | | | — | | 100.0 | |
Segment operating income (loss) | | $ | 150,698 | | $ | (94,880) | | (258.8) | |
Operating Statistics (1): | | | | | | | | | |
Revenue days | | | 77,980 | | | 57,120 | | 36.5 | % |
Average rig revenue per day | | $ | 23,411 | | $ | 22,607 | | 3.6 | |
Average rig expense per day | | $ | 14,182 | | $ | 14,623 | | (3.0) | |
Average rig margin per day | | $ | 9,229 | | $ | 7,984 | | 15.6 | |
Number of rigs at end of period | | | 350 | | | 350 | | — | |
Rig utilization | | | 61 | % | | 45 | % | 35.6 | |
| (1)
| | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $242,617 and $148,218 for fiscal years 2018 and 2017, respectively.
|
Operating Income (Loss) Incompared to $68.8 million during fiscal year 2018, the U.S. Land segment had operating income of $150.7 million compared to an operating loss of $94.9 million in fiscal year 2017. Included in U.S. land revenues for fiscal years 2018 and 2017 is approximately $17.1 million and $24.5 million, respectively, from early termination of fixed‑term contracts. Fixed‑2020. Fixed‑term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term (except in limited circumstances including sustained unacceptable performance by us).
Revenue Excluding early termination revenue of $219 and $428 per day for fiscal years 2018 and 2017, respectively, average revenue per day for Direct operating expenses decreased to $773.5 million during the fiscal year 2018 increased by $1,013ended September 30, 2021 as compared to $23,192 from $22,179 in$942.3 million during the fiscal year 2017. Our activity increased year-over-year in responseended September 30, 2020 primarily due to higher commodity prices resulting in a 36.5 percent increase in revenue days when comparingthe factors mentioned above.
Depreciation Depreciation expense decreased to $392.4 million during the fiscal year 2018ended September 30, 2021 as compared to $438.0 million during the fiscal year 2017. Direct Operating Expenses Direct rig expense increased to $1.3 billion in fiscal year 2018 from $984.2 million in fiscal year 2017. This increase wasended September 30, 2020. The decrease is primarily attributable to increased activity. Additionally, we implemented a wage increase for our field personnel in some regions in April 2018.
Generalthe absence of depreciation on the 71 rigs that were reclassified as held-for-sale during the second and Administrative Expense Inthird quarters of fiscal year 2018,general2021 and administrative expense increased 14.7 percent comparedrig impairments during fiscal year 2020, in addition to 2017.ongoing low levels of capital expenditures.
Asset Impairment ChargeDuring the fiscal year ended September 30, 2021, we undertook 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. This change was primarily driven by an increase in employee headcount, which resulted in an increase in employee compensation, including taxes, benefits and stock-based compensation.Asset Impairment Chargeimpairment charge of $56.4 million ($43.3 million, net of tax, or $0.40 per diluted share. During the fourth quarter of fiscal year 2018, management committed toended September 30, 2021, we formalized a plan to auction several previously decommissioned rigs during fiscal year 2019.sell assets related to two of our lower margin service offerings, trucking and casing running services, all within our North America Solutions segment. The combined net book values of these assets were written down to $8.8 million, which represents their combined fair value less cost to sell, and were reclassified as held-for-sale in the Consolidated Balance Sheets as of September 30, 2021. As a result, we wrote these rigs down to their estimated fair values and recordedrecognized a non-cash impairment charge of $5.7$14.4 million which($10.9 million, net of tax, or $0.10 per diluted share). Comparatively, during the fiscal year ended September 30, 2020, we recorded an impairment charge of $406.5 million ($313.7 million, net of tax, or $3.76 per diluted share) resulting from our impairment of our Domestic Conventional, FlexRig3, and FlexRig4 asset groups, in addition to our in-progress drilling equipment, rotational inventory and goodwill.
Restructuring ChargesFor the fiscal years ended September 30, 2021 and 2020, we incurred $3.9 million and $7.0 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. The charges incurred during the fiscal year ended September 30, 2020 were primarily comprised of $10.0 million in one-time severance benefits to employees who were voluntarily or involuntarily terminated, offset by a benefit of $3.0 million related to forfeitures and modifications of stock-based compensation awards.
Offshore Gulf of Mexico
The following table presents certain information with respect to our Offshore Gulf of Mexico reportable segment:
| | | | | | | | | | | | | | | | | |
| (in thousands, except operating statistics) | 2021 | | 2020 | | % Change |
| Operating revenues | $ | 126,399 | | | $ | 143,149 | | | (11.7) | % |
| Direct operating expenses | 97,249 | | | 119,371 | | | (18.5) | |
| Segment gross margin | 29,150 | | | 23,778 | | | 22.6 | |
| | | | | |
| Depreciation | 10,557 | | | 11,681 | | | (9.6) | |
| Selling, general and administrative expense | 2,624 | | | 3,365 | | | (22.0) | |
| Restructuring charges | — | | | 1,254 | | | (100.0) | |
| Segment operating income | $ | 15,969 | | | $ | 7,478 | | | 113.5 | |
| | | | | |
Operating Statistics1: | | | | | |
| Average active rigs | 4 | | | 5 | | | (20.0) | |
| Number of active rigs at the end of period | 4 | | | 5 | | | (20.0) | |
| Number of available rigs at the end of period | 7 | | | 8 | | | (12.5) | |
| Reimbursements of "out-of-pocket" expenses | $ | 27,388 | | | $ | 30,436 | | | (10.0) | |
(1)These operating metrics allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. Beginning in the first quarter of fiscal year 2021, these operating metrics replaced previously used per day metrics. As a result, prior year comparative information is included in Asset Impairment Charge onalso provided above.
Segment Gross MarginDuring the Consolidated Statementfiscal year ended September 30, 2021, the Offshore Gulf of OperationsMexico segment gross margin was $29.2 million compared to a gross margin of $23.8 million for the fiscal year ended September 30, 2018.Depreciation Depreciation includes charges for abandoned equipment of $26.3 million and $42.2 million in fiscal years 2018 and 2017, respectively. In fiscal year 2018, depreciation expense also includes $9.7 million of accelerated depreciation for components on rigs that are scheduled for conversion in fiscal year 2019. As the drilling markets continued to recover during fiscal year 2017, we began abandoning older rig components to meet customer demands for additional capabilities. This trend continued in fiscal year 2018. Excluding the abandonments and accelerated depreciation, depreciation in fiscal year 2018 increased from fiscal year 2017.
Utilization Rig utilization increased to 61 percent in fiscal year 2018 from 45 percent in fiscal year 2017. The total number of available rigs at both September 30, 2018 and September 30, 2017 was 350.
At September 30, 2018, 232 out of 350 existing rigs in the U.S. Land segment were generating revenue. Of the 232 rigs generating revenue, 136 were under fixed‑term contracts, and 96 were working well-to-well. At November 9, 2018, the number of existing rigs under fixed‑term contracts in the segment was 141 and the number of rigs working in the spot market was 95.
Offshore Operations Segment
| | | | | | | | | |
| | 2018 | | 2017 | | % Change |
| | (in thousands, except operating statistics) |
Operating revenues | | $ | 142,500 | | $ | 136,263 | | 4.6 | % |
Direct operating expenses | | | 101,477 | | | 96,593 | | 5.1 | |
Selling, general and administrative expense | | | 4,507 | | | 3,705 | | 21.6 | |
Depreciation | | | 10,392 | | | 11,764 | | (11.7) | |
Segment operating income | | $ | 26,124 | | $ | 24,201 | | 7.9 | |
Operating Statistics (1): | | | | | | | | | |
Revenue days | | | 2,036 | | | 2,277 | | (10.6) | % |
Average rig revenue per day | | $ | 35,331 | | $ | 34,332 | | 2.9 | |
Average rig expense per day | | $ | 26,009 | | $ | 23,172 | | 12.2 | |
Average rig margin per day | | $ | 9,322 | | $ | 11,160 | | (16.5) | |
Number of rigs at end of period | | | 8 | | | 8 | | — | |
Rig utilization | | | 70 | % | | 74 | % | (5.4) | |
| (1)
| | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $20,279 and $21,578 for fiscal years 2018 and 2017, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.
|
Operating Income In fiscal year 2018, the Offshore segment had operating income of $26.1 million compared to operating income of $24.2 million in fiscal year 2017.
Revenue Average rig revenue per day increased in fiscal year 2018 compared to fiscal year 2017 primarily due to several rigs moving to higher pricing from previous standby or other special dayrates. During April 2018, a previously idle rig commenced work on a customer’s platform.
Direct Operating Expenses Average rig expense increased to $26,009 per day in fiscal year 2018 from $23,172 per day in fiscal year 2017.2020. This increase was primarily attributable to rig start-up expenses and unfavorable adjustments to self-insurance expenses related to workers’ compensation.
Depreciation Depreciationdriven by the absence of $4.2 million of bad debt expense decreasedthat was incurred during the fiscal year ended September 30, 2020. We had an 11.7 percent decrease in operating revenue during the fiscal year 2018 compared to fiscal year 2017. This change was primarily driven by two rigs becoming fully depreciated during fiscal year 2018.
Utilization During the second quarter of fiscal year 2017, we sold one of our offshore rigs. Atended September 30, 2018, six of our eight platform rigs were contracted compared to five of the eight available platform rigs at September 30, 2017.
International Land Operations Segment
| | | | | | | | | |
| | 2018 | | 2017 | | % Change |
| | (in thousands, except operating statistics) |
Operating revenues | | $ | 238,356 | | $ | 212,972 | | 11.9 | % |
Direct operating expenses | | | 177,938 | | | 163,486 | | 8.8 | |
Selling, general and administrative expense | | | 3,658 | | | 3,088 | | 18.5 | |
Depreciation | | | 46,826 | | | 53,622 | | (12.7) | |
Asset impairment charge | | | 10,617 | | | — | | 100.0 | |
Segment operating loss | | $ | (683) | | $ | (7,224) | | (90.5) | |
Operating Statistics (1): | | | | | | | | | |
Revenue days | | | 6,696 | | | 4,951 | | 35.2 | % |
Average rig revenue per day | | $ | 33,830 | | $ | 40,979 | | (17.4) | |
Average rig expense per day | | $ | 24,211 | | $ | 29,761 | | (18.7) | |
Average rig margin per day | | $ | 9,620 | | $ | 11,218 | | (14.2) | |
Number of rigs at end of period | | | 32 | | | 38 | | (15.8) | |
Rig utilization | | | 49 | % | | 36 | % | 36.1 | |
| (1)
| | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $11,828 and $10,074 for fiscal years 2018 and 2017, respectively. Also excluded are the effects of currency revaluation income and expense.
|
Operating Loss The International Land segment had an operating loss of $0.7 million for fiscal year 2018 compared to an operating loss of $7.2 million for fiscal year 2017.
Revenue Our activity has increased primarily in response to higher commodity prices. We experienced a 35.2 percent increase in revenue days when comparing fiscal year 2018 to fiscal year 2017. The average number of active rigs was 18.2 during fiscal year 2018 compared to 13.6 during fiscal year 2017.
Direct Operating Expenses Although direct operating expenses increased in fiscal year 2018 to $177.9 million from $163.5 million in fiscal year 2017, the average rig expense per day decreased by $5,550, an 18.7 percent decrease as2021 compared to the fiscal year 2017 average rig expense. Includedended September 30, 2020. The decrease in direct operating expenses are foreign currency transaction losses of $4.0 million and $6.0 million for fiscal years 2018 and 2017, respectively. The losses arerevenue is primarily due to an ongoing devaluationlower activity levels partially offset by the mix of the Argentine peso beginning in December 2015.
Depreciation Depreciation expenserigs working as compared to being on standby or mobilization rates. Direct operating expenses decreased 12.7 percent into $97.2 million during the fiscal year 2018ended September 30, 2021 as compared to $119.4 million during the fiscal year 2017. Thisended September 30, 2020. The decrease was due to several rig components in Argentina that became fully depreciatedprimarily driven by the factors described above.
2021 FORM 10-K|46
Restructuring ChargesWe did not incur any restructuring charges during the fiscal year 2018. Asset Impairment Chargeended September 30, 2021. During the fourthfiscal year ended September 30, 2020, we incurred $1.3 million in restructuring charges. Charges incurred during the fiscal year ended September 30, 2020 primarily consisted of employee termination benefits that resulted from our reduction in staffing levels.
International Solutions
The following table presents certain information with respect to our International Solutions reportable segment:
| | | | | | | | | | | | | | | | | |
| (in thousands, except operating statistics) | 2021 | | 2020 | | % Change |
| Operating revenues | $ | 57,917 | | | $ | 144,185 | | | (59.8) | % |
| Direct operating expenses | 68,672 | | | 124,791 | | | (45.0) | |
| Segment gross margin | (10,755) | | | 19,394 | | | (155.5) | |
| | | | | |
| Depreciation | 2,013 | | | 17,531 | | | (88.5) | |
| Selling, general and administrative expense | 8,028 | | | 4,565 | | | 75.9 | |
| Asset impairment charge | — | | | 156,686 | | | (100.0) | |
| Restructuring charges | 207 | | | 2,980 | | | (93.1) | |
| Segment operating loss | $ | (21,003) | | | $ | (162,368) | | | (87.1) | |
| | | | | |
Operating Statistics1: | | | | | |
| Average active rigs | 5 | | | 13 | | | (61.5) | |
| Number of active rigs at the end of period | 6 | | | 5 | | | 20.0 | |
| Number of available rigs at the end of period | 30 | | | 32 | | | (6.3) | |
| Reimbursements of "out-of-pocket" expenses | $ | 6,693 | | | $ | 10,099 | | | (33.7) | |
(1)These operating metrics allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. Beginning in the first quarter of fiscal year 2018, after ceasing operations in Ecuador, we entered into2021, these operating metrics replaced previously used per day metrics. As a sales negotiation with respect to six conventional rigs, with net book values of $20.8result, prior year comparative information is also provided above.
Segment Gross Margin The International Solutions segment gross margin was $(10.8) million present in the country, pursuant to which the rigs, together with associated equipment and machinery, would be sold to a third party to be recycled. Certain components of these rigs with an $8.5 million net book value, that are not subject to the sale agreement, will be transferred to the United States to be utilized on other FlexRigs with high activity and demand. The sales transaction was completed in November 2018. We recorded a non-cash impairment charge of $9.2 million ($7.0 million, net of tax, or $0.06 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018 related2021 compared to these rigs. As a result,gross margin of $19.4 million for the remaining rig withinfiscal year ended September 30, 2020. The change was primarily driven by lower activity levels coupled with fixed minimum levels of country overhead during the same asset group, notfiscal year ended September 30, 2021. We had a 59.8 percent decrease in operating revenue during the fiscal year ended September 30, 2021 compared to be disposed of,the fiscal year ended September 30, 2020. The decrease in operating revenue is primarily due to lower activity levels. Direct operating expenses decreased to $68.7 million during the fiscal year ended September 30, 2021 as compared to $124.8 million during the fiscal year ended September 30, 2020 and was written down resulting indriven by the factors described above.
Asset Impairment ChargeDuring the fiscal year ended September 30, 2021, we recorded no impairment charges. Comparatively, during the fiscal year ended September 30, 2020, we recorded an additional impairment charge of $1.4$156.7 million ($1.0123.8 million, net of tax, or $0.01$1.45 per diluted share).Utilization Utilization increased resulting from 36 percentour impairment of our International Conventional, FlexRig
®3, and FlexRig®4 asset groups, in addition to rotational inventory. Restructuring ChargesFor the fiscal years ended September 30, 2021 and 2020, we incurred $0.2 million and $3.0 million in restructuring charges, respectively. During the fiscal year 2017 to 49 percentended September 30, 2021, we commenced a voluntary separation program at our local office in Argentina for which we incurred one-time severance charges for employees who were voluntarily terminated. Charges incurred during the fiscal year 2018. The increase was driven by the increaseended September 30, 2020 primarily consisted of employee termination benefits that resulted from our reduction in rig activity as discussed above.staffing levels.
2021 FORM 10-K|47
Results of our other operations, excluding corporate selling, general and administrative costs, corporate restructuring, and corporate depreciation, are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | % Change | |
| | (in thousands, except operating statistics) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | % Change |
Operating revenues | | $ | 38,217 | | $ | 15,983 | | 139.1 | % | Operating revenues | $ | 43,304 | | | $ | 49,114 | | | (11.8) | % |
Direct operating expenses | | | 44,390 | | | 18,552 | | 139.3 | | Direct operating expenses | 50,064 | | | 41,027 | | | 22.0 | |
| Gross margin | | Gross margin | (6,760) | | | 8,087 | | | (183.6) | |
| | Depreciation | | Depreciation | 1,426 | | | 1,241 | | | 14.9 | |
| Research and development | | Research and development | 127 | | | 946 | | | (86.6) | |
Selling, general and administrative expense | | | 15,801 | | | 1,756 | | 799.8 | | Selling, general and administrative expense | 1,205 | | | 1,237 | | | (2.6) | |
Depreciation and amortization | | | 8,332 | | | 5,124 | | 62.6 | | |
Asset impairment charge | | | 5,637 | | | — | | 100.0 | | |
Operating loss | | $ | (35,943) | | $ | (9,449) | | 280.4 | | |
| Restructuring charges | | Restructuring charges | 186 | | | 260 | | | (28.5) | |
| Operating income (loss) | | Operating income (loss) | $ | (9,704) | | | $ | 4,403 | | | (320.4) | |
Operating Loss Other operationsGross MarginOn October 1, 2019, we elected to capitalize a new Captive insurance company to insure the deductibles for our domestic workers’ compensation, general liability and automobile liability claims programs, and to continue the practice of insuring deductibles from the Company's international casualty and rig property programs. Direct operating expenses consisted primarily of adjustments to accruals for estimated losses of $12.6 million and $16.4 million allocated to the Captive and rig and casualty insurance premiums of $21.9 million and $6.7 million during the fiscal years ended September 30, 2021 and 2020, respectively. The decrease in fiscal year 2018 had an operating loss of $35.9 million comparedestimated losses is primarily due to an operating loss of $9.4 million in fiscal year 2017. The change was primarily drivenactuarial valuation adjustments by our third-party actuary as well as lower activity levels. Intercompany premium revenues recorded by the acquisitionCaptive during the fiscal years ended September 30, 2021 and 2020 amounted to $35.4 million and $36.9 million, respectively, which were eliminated upon consolidation.
| | | | | | | | | | | | | | |
Results of Operations for the Fiscal Years Ended September 30, 2020 and 2019 |
A discussion of MagVAR in December 2017 and twelve full monthsour results of operations of MOTIVE, which was acquired in June 2017. Refer to Note 3—Business Combinations of the Consolidated Financial Statements for additional disclosures. Asset Impairment Charge During the fourth quarter of fiscal year 2018, we recorded goodwill and intangible assets impairment losses of $5.6 million related to the TerraVici technology reporting unit where $4.7 million goodwill was allocated. This impairment loss is included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018.
Results of Operation for the Fiscal Years Ended September 30, 2017 and 2016
Consolidated Results of Operations
All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Except as specifically discussed, the following results of operations pertain only to our continuing operations.
Net Loss Our net loss for fiscal year 2017 was $128.2 million ($1.20 loss per share) compared to a net loss of $56.8 million ($0.54 loss per share) for fiscal year 2016. Net loss in fiscal years 2017 and 2016 includes after-tax income from early termination revenue associated with drilling contracts terminated prior to the expiration of their fixed term of $20.2 million ($0.18 per share) and $139.3 million ($1.29 per share), respectively. Net loss in fiscal years 2017 and 2016 includes after‑tax gains from the sale of assets of $14.3 million ($0.13 per share) and $6.1 million ($0.06 per share), respectively. Included in our fiscal year 2016 net loss is an after‑tax loss of $15.9 million ($0.15 loss per share) from an other‑than‑temporary impairment of our marketable equity security position in Atwood Oceanics, Inc. (“Atwood”). Net loss in fiscal year 2016 also includes an after‑tax loss of $12.0 million ($0.11 loss per share) from the settlement of litigation and a $3.8 million loss ($0.04 loss per share) from discontinued operations.
Revenue Consolidated operating revenues were $1.8 billion in fiscal year 2017 and $1.6 billion in fiscal year 2016, including early termination revenue of $29.4 million and $219.0 million in each respective fiscal year. Primarily as a result of the impact of oil prices on drilling activity by exploration and production companies during that time frame, the number of revenue days in our U.S. Land segment totaled 57,120 in fiscal year 2017 and 36,984 in fiscal year 2016.
Interest and Dividend Income Interest and dividend income was $5.9 million and $3.2 million in fiscal year 2017 and 2016, respectively. The higher income in fiscal year 2017 was primarily due to higher earnings on available cash equivalents and short-term investments.
Direct Operating Expenses Direct operating costs in fiscal year 2017 were $1.2 billion and $0.9 billion in fiscal year 2016. The increase in fiscal year 2017 from fiscal year 2016 was primarily due to an increase in drilling activity.
General and Administrative Expense General and administrative expenses totaled $151.0 million in fiscal year 2017 and $146.2 million in fiscal year 2016. During fiscal year 2017, we incurred transaction costs of $3.2 million related to our acquisition of MOTIVE. In addition, bonuses paid to employees increased in fiscal year 2017.
Depreciation and Amortization Depreciation and amortization expense was $585.5 million in fiscal year 2017 and $598.6 million in fiscal year 2016. Depreciation and amortization includes abandonments of equipment of $42.6 million in fiscal year 2017 and $39.3 million in fiscal year 2016. Additionally, we recorded impairment charges on rig and rig related equipment of $6.3 million in fiscal year 2016. Depreciation expense, exclusive of abandonments, decreased three percent in fiscal year 2017 from fiscal year 2016. The decrease is primarily due to relatively lower levels of capital expenditures during fiscal year 2017 and legacy assets reaching the end of their depreciable lives. Abandonments were primarily due to the abandonment of used drilling equipment in both fiscal years.
Interest Interest expense net of amounts capitalized totaled $19.7 million in fiscal year 2017 and $22.9 million in fiscal year 2016. Interest expense is primarily attributable to fixed‑rate debt outstanding. There was a favorable adjustment to interest expense of $5.2 million in fiscal year 2017 related to the reversal of previously booked uncertain tax positions where the statute of limitations had expired. Capitalized interest was $0.3 million and $2.8 million in fiscal years 2017 and 2016, respectively. All of the capitalized interest is attributable to our rig construction and upgrade program.
Income Taxes We had an income tax benefit of $56.7 million in fiscal year 2017 compared to an income tax benefit of $19.7 million in fiscal year 2016. The effective income tax rate was 30.7 percent in fiscal year 2017 and 27.1 percent in fiscal year 2016. Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets is based on management’s judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future. See Note 8—Income Taxes to our Consolidated Financial Statements for additional income tax disclosures.
Research and Development During fiscal years 2017 and 2016, we incurred $12.0 million and $10.3 million, respectively, of research and development expenses primarily related to the ongoing development of the rotary steerable system tools.
U.S. Land Operations Segment
| | | | | | | | | |
| | 2017 | | 2016 | | % Change |
| | (in thousands, except operating statistics) |
Operating revenues | | $ | 1,439,523 | | $ | 1,242,462 | | 15.9 | % |
Direct operating expenses | | | 984,205 | | | 603,800 | | 63.0 | |
Selling, 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 (1): | | | | | | | | | |
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 | |
| (1)
| | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $148,218 and $82,337 for fiscal years 2017 and 2016, respectively.
|
Operating Income (Loss) In fiscal year 2017, the U.S. Land segment had an operating loss of $94.9 million compared to operating income of $74.1 million in fiscal year 2016. Included in U.S. land revenues for fiscal years 2017 and 2016 is approximately $24.5 million and $219.0 million, respectively, from early termination of fixed-term contracts.
Revenue Excluding early termination revenue of $428 and $5,921 per day for fiscal years 2017 and 2016, respectively, average revenue per day for fiscal year 2017 decreased by $3,269 to $22,179 from $25,448 in fiscal year 2016. Our activity increased year-over-year in response to higher commodity prices, resulting in a 54 percent increase in revenue days when comparing fiscal year 2017 to fiscal year 2016. However, legacy term contracts at high dayrates made up a lower proportion of our fiscal year 2017 activity due to continued contract expirations. Further, newly contracted rigs which made up a majority of our fiscal year 2017 activity were priced at relatively lower levels which reflected depressed market conditions.
Direct Operating Expenses The average rig expense per day increased to $14,623 in fiscal year 2017 from $14,117 in fiscal year 2016. This increase was primarily attributable to start-up expenses related to rigs returning to work during fiscal year 2017.
Depreciation Depreciation includes charges for abandoned equipment of $42.2 million and $38.8 million in fiscal years 2017 and 2016, respectively. Included in abandonments in fiscal year 2017 are older rig components that were replaced by upgrades to our rig fleet to meet customer demands for additional capabilities. Included in abandonments in fiscal year 2016 is the retirement of used drilling equipment. Excluding the abandonments, depreciation in fiscal year 2017 decreased from fiscal year 2016, primarily due to relatively low levels of capital expenditures during fiscal year 2017 and fiscal year 2016 and certain legacy assets reaching the end of their depreciable lives in fiscal year 2017 and fiscal year 2016.
Asset Impairment ChargeDuring fiscal year 2016, we recorded an asset impairment charge in the U.S. Land segment of $6.3 million to reduce the carrying value of rig and rig related equipment classified as held for sale to their estimated fair values, based on expected sales prices.
Utilization Rig utilization increased to 45 percent in fiscal year 2017 from 30 percent in fiscal year 2016. The total number of rigs at September 30, 2017 was 350 compared to 348 rigs at September 30, 2016. The net increase is due to two new FlexRigs completed in fiscal year 2017 and included in our operating statistics.
At September 30, 2017, 197 out of 350 existing rigs in the U.S. Land segment were generating revenue. Of the 197 rigs generating revenue, 100 were under fixed-term contracts, and 97 were working in the spot market.
Offshore Operations Segment
| | | | | | | | | |
| | 2017 | | 2016 | | % Change |
| | (in thousands, except operating statistics) |
Operating revenues | | $ | 136,263 | | $ | 138,601 | | (1.7) | % |
Direct operating expenses | | | 96,593 | | | 106,983 | | (9.7) | |
Selling, 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 (1): | | | | | | | | | |
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) | |
| (1)
| | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $21,578 and $23,138 for fiscal years 2017 and 2016, respectively. The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.
|
Operating Income In fiscal year 2017, the Offshore segment had operating income of $24.2 million compared to operating income of $15.7 million in fiscal year 2016.
Revenue Average rig revenue per day and average rig margin per day increased in fiscal year 2017 compared to fiscal year 2016 primarily due to receiving full pricing during fiscal year 2017 after receiving lower pricing while on standby or other special dayrates during fiscal year 2016.
Depreciation Depreciation decreased slightly by 5.9 percent in fiscal year 2017 compared to fiscal year 2016 due to the sale of a rig during fiscal year 2017 and some assets becoming fully depreciated during the year.
Direct Operating Expenses Direct operating expense in fiscal year 2017 decreased by 9.7 percent compared to fiscal year 2016. This decrease was primarily due to two less rigs working during the year.
International Land Operations Segment
| | | | | | | | | |
| | 2017 | | 2016 | | % Change |
| | (in thousands, except operating statistics) |
Operating revenues | | $ | 212,972 | | $ | 229,894 | | (7.4) | % |
Direct operating expenses | | | 163,486 | | | 183,969 | | (11.1) | |
Selling, 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 (1): | | | | | | | | | |
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) | |
| (1)
| | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑pocket” expenses of $10,074 and $20,458 for fiscal years 2017 and 2016, respectively. Also excluded are the effects of currency revaluation income and expense.
|
Operating Loss The International Land segment had an operating loss of $7.2 million for fiscal year 2017 compared to an operating loss of $14.1 million for fiscal year 2016.
Revenue Excluding early termination revenue of $955 per day in fiscal year 2017, the average rig margin per day for fiscal year 2017 compared to fiscal year 2016 decreased by $143 to $10,263. Low oil prices continued to have a negative effect on customer spending. As a result, we experienced an 8 percent decrease in revenue days when
comparing fiscal year 2017 to fiscal year 2016. The average number of active rigs was 13.6 during fiscal year 2017 compared to 14.7 during fiscal year 2016.
Direct Operating Expenses Although direct operating expenses decreased in fiscal year 2017 to $163.5 million from $184.0 million in fiscal year 2016, the average rig expense per day increased $1,123 or 4 percent as2020 compared to the fiscal year 2016 average rig expense. Includedended September 30, 2019 is included in direct operating expenses are foreign currency transaction lossesPart II, Item 7— "Management's Discussion and Analysis of $6.0 millionFinancial Condition and $9.8 millionResults of Operations" of ourAnnual Report on Form 10-K for fiscal years 2017 and 2016, respectively. Thethe fiscal year 2016 losses were primarily due to a devaluation ofended September 30, 2020, filed with the Argentine peso in December 2015.
Depreciation Depreciation decreased slightlySecurities and Exchange Commission ("SEC") on November 20, 2020, and is incorporated by 6.1 percent in fiscal year 2017 compared to fiscal year 2016 due to some assets becoming fully depreciated during the year.
Other Operations
Results of our other operations, excluding corporate selling, general and administrative costs and corporate depreciation, are as follows:
| | | | | | | | | |
| | 2017 | | 2016 | | % Change |
| | (in thousands, except operating statistics) |
Operating revenues | | $ | 15,983 | | $ | 13,275 | | 20.4 | % |
Direct operating expenses | | | 18,552 | | | 16,132 | | 15.0 | |
Selling, general and administrative expense | | | 1,756 | | | 194 | | 805.2 | |
Depreciation and amortization | | | 5,124 | | | 4,440 | | 15.4 | |
Operating loss | | $ | (9,449) | | $ | (7,491) | | 26.1 | |
Operating Loss Other operations in fiscal year 2017 had an operating loss of $9.4 million compared to an operating loss of $7.5 million in fiscal year 2016. The change was primarily driven by the acquisition of MOTIVE in June 2017. Refer to Note 3—Business Combinations of the Consolidated Financial Statements for additional disclosures.
reference into this Form 10-K.
| | | | | | | | | | | | | | |
| Liquidity and Capital Resources |
Liquidity and Capital Resources
Sources of Liquidity
Our sources of available liquidity include existing cash balances on hand, cash flows from operations, and availability under
our credit facility.the 2018 Credit Facility. Our liquidity requirements include meeting ongoing working capital needs, funding our capital expenditure projects, paying dividends declared, and repaying our outstanding indebtedness. Historically, we have financed operations primarily through internally generated cash flows. During periods when internally generated cash flows are not sufficient to meet liquidity needs, we
willmay utilize cash on hand, borrow from available credit sources, access capital markets or sell our
portfolio securities.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‑short‑term money market and debt securities. These investments can include U.S. Treasury securities, U.S. Agency issued debt securities, corporate bonds and commercial paper, certificates of deposit and money market funds. We have continued to reinvest maturities and earnings during fiscal years 2018 and 2017. The securities are recorded at fair value.We may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity as necessary, fund our additional purchases, exchange or redeem
Senior Notes,senior notes, or repay any amounts under
our credit facility.the 2018 Credit Facility. Our ability to access the debt and equity capital markets depends on a number of factors, including our credit rating, market and industry conditions and market perceptions of our industry, general economic conditions, our revenue backlog and our capital expenditure commitments.
The effects of the COVID-19 pandemic and the oil price collapse in 2020 have had significant adverse consequences for general economic, financial and business conditions, as well as for our business and financial position and the business and financial position of our customers, suppliers and vendors and may, among other things, impact our ability to generate cash flows from operations, access the capital markets on acceptable terms or at all and affect our future need or ability to borrow under the 2018 Credit Facility. In addition to our potential sources of funding, the effects of such global events may impact our liquidity or need to alter our allocation or sources of capital, implement additional cost reduction measures and further change our financial strategy. Although the COVID-19 pandemic and the oil price collapse could have a broad range of effects on our sources and uses of liquidity, the ultimate effect thereon, if any, will depend on future developments, which cannot be predicted at this time.
2021 FORM 10-K|48
Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling rigs under contract, the
dayratesrevenue we receive under those contracts, the efficiency with which we operate our drilling units, the timing of collections on outstanding accounts receivable, the timing of payments to our vendors for operating costs, and capital
expenditures.expenditures, all of which was impacted by the COVID-19 pandemic and the oil price collapse in 2020. As our revenues increase, operating net working capital is typically a use of capital, while conversely, as our revenues decrease, operating net working capital is typically a source of capital. To date, general inflationary trends have not had a material effect on our operating margins.
As of September 30, 2018,2021, we had $284.4$917.5 million of cash and cash equivalents on hand and $41.5$198.7 million of short-term investments. Our cash flows for the fiscal years ended September 30, 2018, 20172021, 2020 and 20162019 are presented below:
| | | | | | | | | | |
| | Year Ended | | | | | | | | | | | | | | | |
| | September 30, | | Year Ended September 30, |
(in thousands) | | 2018 | | 2017 | | 2016 | (in thousands) | 2021 | | 2020 | | 2019 |
| | | | | As adjusted (Note 2) | |
Net cash provided (used) by: | | | | | | | | | | |
| Net cash provided by (used in): | | Net cash provided by (used in): | | | | | |
Operating activities | | $ | 544,531 | | $ | 361,631 | | $ | 754,531 | Operating activities | $ | 136,440 | | | $ | 538,881 | | | $ | 855,751 | |
Investing activities | | | (472,362) | | | (444,988) | | | (234,219) | Investing activities | (161,994) | | | (87,885) | | | (422,636) | |
Financing activities | | | (309,189) | | | (300,829) | | | (344,135) | Financing activities | 425,523 | | | (297,220) | | | (376,329) | |
Increase (decrease) in cash and cash equivalents | | $ | (237,020) | | $ | (384,186) | | $ | 176,177 | |
| Net increase in cash and cash equivalents and restricted cash | | Net increase in cash and cash equivalents and restricted cash | $ | 399,969 | | | $ | 153,776 | | | $ | 56,786 | |
For the purpose of understanding the impact on our cash flows from operating activities, operating net working capital
is calculated as current assets, excluding cash and
cash equivalents, short-term investments,
increased $87.6and assets held-for-sale, less current liabilities, excluding dividends payable and the current portion of long-term debt. Operating net working capital was $43.4 million,
to $412.6$194.2 million and $381.7 million as of September 30,
20182021, 2020 and 2019, respectively. The sequential decrease in net working capital was primarily driven by the receipt of the $86.5 million in cash consideration from
$325.0 millionADNOC Drilling in advance of delivering the eight purchased rigs. The total cash proceeds were recorded within Accrued Liabilities within our Consolidated Balance Sheets as of September 30,
2017 due primarily to an increase2021. This was partially offset by activity-driven increases in other components of our operating net working capital. Included in accounts receivable
and inventoriesas of
materials and supplies, offsetSeptember 30, 2021 was $24.5 million of income tax receivables. Cash flows provided by
an increase in accrued liabilities. Net cash provided from operating activities
was $544.5were $136.4 million, $538.9 million and $855.8 million in fiscal
year 2018 compared to $361.6 million in fiscal year 2017.years 2021, 2020 and 2019, respectively. The
$182.9 million increasedecrease in cash provided by operating activities is primarily
due to an increase in net income due to increaseddriven by lower operating activity
during the fiscal year. In fiscal year 2016, net cash provided from operating activities was $754.5 million. The $392.9 million decrease in cash provided by operating activities between fiscal years 2017 and
2016 was primarily due to a larger net loss reported in fiscal year 2017.lower pricing.
Capital Expenditures Our investing activities are primarily related to capital expenditures for our fleet. Our capital expenditures were $466.6$82.1 million, in 2018, $397.6$140.8 million and $458.4 million in fiscal year 2017years 2021, 2020 and $257.2 million2019, respectively. The year-over-year decrease in fiscal year 2016.capital expenditures is driven by lower maintenance capital expenditures as a result of lower activity. Our fiscal year 20192022 capital spending is currently estimated to be between $650$250 million and $680$270 million. This estimate includes normal capital maintenance requirements, capitalinformation technology spending relatedand skidding to reactivating idle rigs, tubularswalking conversions for a limited number of rigs.
Purchase of Investments Our net (purchases) sales of investments were $(209.9) million, $(40.0) million and other upgrades primarily related$1.1 million in fiscal years 2021, 2020 and 2019, respectively. The increase in purchases is attributable to improving our existing rig fleet.strategy to optimize our returns on investment, including our purchase of our cornerstone investment of $100.0 million in ADNOC Drilling. Acquisition of BusinessDuring fiscal years 2018 and 2017, weWe paid $47.9$16.2 million, and $70.4 million, respectively, net of cash acquired, during fiscal year 2019, for the acquisition of drilling technology companies.
Sale of AssetsOur proceeds from asset sales totaled $44.4$43.5 million, $78.4 million and $50.8 million in fiscal year 2018, $23.4 million in2021, 2020 and 2019, respectively. During the fiscal year 2017 and $21.8ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including six industrial sites, for total consideration, net of selling related expenses, of $40.7 million.
Sale of SubsidiaryIn December 2019, we closed on the sale of a wholly-owned subsidiary of HPIDC, TerraVici Drilling Solutions, Inc. ("TerraVici"). As a result of the sale, 100% of TerraVici's outstanding capital stock was transferred to the purchaser in exchange for approximately $15.1 million, resulting in fiscal year 2016. Income from asset sales in fiscal year 2018 totaled $22.7 million, $20.6 million in fiscal year 2017 and $9.9 million in fiscal year 2016. In each year we had salesa total gain on the sale of old or damaged rig equipment and drill pipe used in the ordinary courseTerraVici of business included in operating activity within the statementapproximately $15.0 million.
Equity SecuritiesAs of cash flow.Stock Portfolio HeldWe manage a portfolio of marketableSeptember 30, 2021, our equity securities consistingprimarily consist of common shares of Ensco plc (“Ensco”) andin Schlumberger, Ltd. that, at the close of fiscal year 2018,2021, had a fair value of $82.5$13.9 million. The value of the portfolioour securities is subject to fluctuation in the market and may vary considerably over time. The portfolioThis investment is recorded at fair value on our balance sheet. Consolidated Balance Sheets. Refer to Note 13—Fair Value Measurement of Financial Instruments to our Consolidated Financial Statements. In September 2019, we sold our remaining 1.6 million shares in Valaris, previously known as Ensco Rowan plc, for total proceeds of approximately $12.0 million.
2021 FORM 10-K|49
Advance payment for sale of property, plant and equipment During September 2021, the fourth quarterCompany agreed to sell eight FlexRig land rigs with an aggregate net book value of fiscal year 2016, we determined that the decline in fair value below our cost basis in Atwood Oceanics, Inc. (“Atwood”) was other than temporary. As a result, we recorded a non‑cash charge totaling $26.0$55.6 million to ADNOC Drilling for $86.5 million.In May 2017, Ensco announced that it entered into a definitive merger agreement under which Ensco would acquire Atwood in an all-stock transaction. The transaction closed on October 6, 2017. Under the terms Two of the mergereight rigs were already located in the U.A.E where ADNOC Drilling is domiciled with the remaining six rigs to be shipped from the United States. We received the $86.5 million in cash consideration in advance of delivering the rigs. As part of the sales agreement, we received 1.60 shares of Ensco for each share of our Atwood common stock. The securitiesthe rigs will be delivered and commissioned in our portfolio arestages over a twelve-month period subject to a wide varietyacceptance upon successful completion of market‑related risks that could substantially reduce or increase the fair value of the holdings. In general, the portfolio is recorded at fair valuefinal inspection on the balance sheet with changes in unrealized after‑tax value reflected in the equity section of the balance sheet.
Our stock portfolio heldcustomary terms and conditions. No rigs have been delivered to ADNOC Drilling as of September 30, 20182021 and, therefore, the total cash proceeds of $86.5 million is presented below:
recorded in Accrued Liabilities within our Consolidated Balance Sheets as of September 30, 2021. | | | | | | | | |
| | Number | | | | | | |
September 30, 2018 | | of Shares | | Cost Basis | | Market Value |
| | (in thousands, except share amounts) |
Ensco plc | | 6,400,000 | | $ | 34,760 | | $ | 54,016 |
Schlumberger, Ltd. | | 467,500 | | | 3,713 | | | 28,480 |
Total | | | | $ | 38,473 | | $ | 82,496 |
Financing Activities
Repurchase of Shares We have an evergreen authorization from the Board of Directors (the "Board") for the repurchase of up to four million common shares in any calendar year. The increaserepurchases may be made using our cash and cash equivalents or other available sources. We repurchased 1.5 million shares for $28.5 million during fiscal year 2020 and one million shares for $42.8 million during fiscal year 2019. There were no purchases of $8.4 million in net cash used by financing activitiescommon shares in fiscal year 2018 from fiscal year 2017 was primarily due to an excess tax benefit from stock-based compensation that occurred in 2017 and not in 2018. The decrease of $43.3 million in net cash used by financing activities between fiscal years 2017 and 2016 was primarily due to $40.0 million in cash used to payback long-term debt in fiscal year 2016.2021.
Dividends We paid dividends of $2.82, $2.80,$1.00, $2.38, and $2.78$2.84 per share during fiscal years 2018, 20172021, 2020 and 2016,2019, respectively. Total dividends paid were $308.4$109.1 million, $305.5$260.3 million and $300.2$313.4 million in fiscal years 2018, 20172021, 2020 and 2016,2019, respectively. Adjusting for stock splits accordingly, we have increased the effective annualA cash dividend of $0.25 per share every fiscal yearwas declared on September 1, 2021 for the past 46 years.shareholders of record on November 23, 2021, payable on December 1, 2021. The declaration and amount of future dividends is at the discretion of ourthe Board of Directors and subject to our financial condition, results of operations, cash flows, and other factors ourthe Board of Directors deems relevant. Debt Issuance Proceeds and Costs On September 29, 2021, we issued $548.7 million aggregate principal amount of the 2031 Notes in an offering to persons reasonably believed to be qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act (“Rule 144A”) and to certain non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act (“Regulation S”). Debt issuance fees paid as of September 30, 2021 were $3.9 million. On October 27, 2021, we redeemed all of the outstanding 2025 Notes. The Company financed the redemption of the 2025 Notes with the net proceeds from the offering of the 2031 Notes, together with cash on hand. Additional details are fully discussed in Note 7—Debt.
On JulyNovember 13, 2016,2018, we entered into a $300 millioncredit agreement by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which was amended on November 13, 2019, providing for an unsecured revolving credit facility (the “2016(as amended, the “2018 Credit Facility”), that was set to mature on November 13, 2024. On April 16, 2021, lenders with a maturity date$680.0 million of July 13, 2021. The 2016commitments under the 2018 Credit Facility hadexercised 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. The remaining $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.
The 2018 Credit Facility has $750.0 million in aggregate availability with a maximum of $75$75.0 million available tofor use as letters of credit. The majority2018 Credit Facility also permits aggregate commitments under the facility to be increased by $300.0 million, subject to the satisfaction of anycertain conditions and the procurement of additional commitments from new or existing lenders. The borrowings under the facility would2018 Credit Facility accrue interest at a spread over either the London Interbank Offered Rate (LIBOR)("LIBOR") or an adjusted base rate (as defined in the credit agreement). We also paidpay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees wereare determined according to a scale based on the Company’s debt to total capitalization ratio.rating for senior unsecured debt of the Company, as determined by Moody’s and Standard & Poor's. The spread over LIBOR rangedranges from 1.1250.875 percent to 1.751.500 percent per annum and commitment fees rangedrange from 0.150.075 percent to 0.300.200 percent per annum. Based on ourthe unsecured debt to total capitalizationrating of the Company on September 30, 2018,2021, the spread over LIBOR would have been 1.125 percent had borrowings been outstanding under the 2018 Credit Facility and commitment fees would be 1.125 percent and 0.15 percent, respectively.are 0.125 percent. There wasis a financial covenant in the facility2018 Credit Facility that requiredrequires us to maintain a total funded debt to total capitalization ratio of less than or equal to 50 percent. The 20162018 Credit Facility containedcontains additional terms, conditions, restrictions and covenants that we believe wereare usual and customary in
unsecured debt arrangements for companies of similar size and credit quality, including a limitation that priority debt (as defined in the credit agreement) couldmay not exceed 17.5 percent of the net worth of the Company. As of September 30, 2018,2021, there were no borrowings but there were threeor letters of credit outstanding, in the amount of $39.3 million. At September 30, 2018, we had $260.7leaving $750.0 million available to borrow under the 20162018 Credit Facility. Subsequent to
As of September 30,
2018, the Company decreased one of the three2021, we had 3 separate outstanding letters of credit
by $1.3with banks, in the amounts of $24.8 million,
which increased availability under the facility to $262.0 million.Subsequent to our fiscal year-end, on November 13, 2018,$3.0 million and $2.1 million, respectively.
As of September 30, 2021, we
entered intoalso had a
$750 million unsecured revolving credit facility (the “2018 Credit Facility”). In connection with entering into the 2018 Credit Facility, we terminated the 2016 Credit Facility. See Note 19-–Subsequent Events to our Consolidated Financial Statements for more information about the 2018 Credit Facility.The Company has a $12$20.0 million unsecured standalone line of credit facility, which is purposed for the purpose of obtaining the issuance of bidinternational letters of credit, bank guarantees, and performance bonds,bonds. Of the $20.0 million, $7.6 million of financial guarantees were outstanding as needed, for international land operations. The Company currently has no outstanding obligations against this facility.
of September 30, 2021.
2021 FORM 10-K|50
The applicable agreements for all unsecured debt contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30,
2018,2021, we were in compliance with all debt covenants, and we anticipate that we will continue to be in compliance
forduring the next
quarter of fiscal
year.Repurchaseyear 2022.
Senior Notes
2.90% Senior Notes due 2031 On September 29, 2021, we issued $550.0 million aggregate principal amount of the 2.90 percent 2031 Notes in an offering to persons reasonably believed to be qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act (“Rule 144A”) and Retirementto certain non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act (“Regulation S”). Interest on the 2031 Notes is payable semi-annually on March 29 and September 29 of Common SharesWe did not haveeach year, commencing on March 29, 2022. The 2031 Notes will mature on September 29, 2031 and bear interest at a rate of 2.90 percent annum.
Prior to June 29, 2031, the Company may redeem the 2031 Notes at its option, in whole or in part, at any active stock repurchase programtime or from time to time at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2031 Notes to be redeemed or (ii) the sum of the present values, as calculated by the Independent Investment Banker (as defined in the 2031 Notes Indenture (as defined herein)), of the remaining scheduled payments of principal and interest thereon (exclusive of the interest accrued to the redemption date) computed by discounting such payments to the redemption date on a semi-annual basis, assuming a 360-day year consisting of twelve 30-day months, at a rate equal to the sum of the Treasury Rate (as defined in the 2031 Notes Indenture) for such 2031 Notes plus 25 basis points, plus, in either case, accrued and unpaid interest, if any, to, but excluding, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).
On or after June 29, 2031, the Company may redeem the 2031 Notes at its option, in whole or in part, at any time or from time to time at a redemption price equal to 100% of the principal amount of the 2031 Notes to be redeemed, plus accrued and unpaid interest thereon to, but excluding, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).
The 2031 Notes were issued pursuant to an Indenture, dated as of December 20, 2018 (the “Base Indenture”), as supplemented by the Second Supplemental Indenture thereto, dated as of September 29, 2021 (together with the Base Indenture, the “2031 Notes Indenture”), in each case by and between the Company and Wells Fargo Bank, National Association, as trustee.
The 2031 Notes Indenture contains certain covenants that, among other things and subject to certain exceptions, limit the ability of the Company and its subsidiaries to incur certain liens; engage in sale and lease-back transactions; and consolidate, merge or transfer all or substantially all of the assets of the Company. The 2031 Notes Indenture also contains customary events of default with respect to the 2031 Notes.
4.65% Senior Notes due 2025 On December 20, 2018, we issued approximately $487.1 million in aggregate principal amount of the 2025 Notes. Interest on the 2025 Notes is payable semi-annually on March 15 and September 15 of each year, commencing on March 15, 2019. The debt issuance costs are being amortized straight-line over the stated life of the obligation, which approximated the effective interest method.
On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 2025 Notes at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. The Company financed the redemption of the 2025 Notes with the net proceeds from the offering of the 2031 Notes, together with cash on hand. The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021.
On October 27, 2021, we redeemed all of the outstanding 2025 Notes. The associated make-whole premium and accrued interest of $58.1 million and the write off of the unamortized discount and debt issuance costs of $3.7 million will be recognized during the first fiscal
years 2018, 2017, or 2016. We have an evergreen authorization to purchase up to four million shares per fiscal year.quarter of 2022 contemporaneously with the October 27, 2021 redemption.
2021 FORM 10-K|51
Our operating cash requirements, scheduled debt repayments, interest payments, any declared dividends, and estimated capital expenditures
including our rig upgrade construction program, for fiscal year
20192022 are expected to be funded through current cash and cash to be provided from operating activities. However, there can be no assurance that we will continue to generate cash flows at current levels.
The long‑term debt If needed, we may decide to total capitalization ratio was 10.1 percentobtain 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 long-term unsecured senior notes totaled $550.0 million at September 30, 2018 compared to 10.6 percent at2021 and matures on September 30, 2017.
Off-balance Sheet Arrangements
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K. For information regarding our drilling contract backlog, see Item 1— “Business — Contract Backlog”.
29, 2031. Material Commitments
Our contractual obligations asAs of September 30, 2018 are summarized in2021, we had a $563.4 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 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2023 |
Long-term debt | | $ | 500,000 | | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | 500,000 |
Interest (1) | | | 150,156 | | | 23,250 | | | 23,250 | | | 23,250 | | | 23,250 | | | 23,250 | | | 33,906 |
Operating leases (2) | | | 32,941 | | | 9,113 | | | 6,670 | | | 4,357 | | | 3,985 | | | 3,721 | | | 5,095 |
Purchase obligations (2) | | | 110,371 | | | 110,371 | | | — | | | — | | | — | | | — | | | — |
Total contractual obligations | | $ | 793,468 | | $ | 142,734 | | $ | 29,920 | | $ | 27,607 | | $ | 27,235 | | $ | 26,971 | | $ | 539,001 |
| (1)
| | Interest on fixed‑rate debt was estimated based on principal maturities. See Note 7--Debt to our Consolidated Financial Statements.
|
financial and income tax basis of property, plant and equipment. Our capital expenditures over the last several years have been subject to accelerated depreciation methods (including bonus depreciation) available under the Internal Revenue Code of 1986, as amended, enabling us to defer a portion of cash tax payments to future years. Future levels of capital expenditures and results of operations will determine the timing and amount of future cash tax payments. We expect to be able to meet any such obligations utilizing cash and investments on hand, as well as cash generated from ongoing operations. | (2)
| | See Note 15—Commitments and Contingencies to our Consolidated Financial Statements.
|
The above table does not include obligations for our pension plan or amounts recorded for uncertain tax positions.In fiscal years 2018 and 2017, we did not make any contributions to the pension plan. Contributions may be made in fiscal year 2019 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond fiscal year 2019 are difficult to estimate due to multiple variables involved.
At September 30, 2018,2021, we had $17.1$4.6 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
The long‑term debt to total capitalization ratio was 15.9 percent at September 30, 2021 compared to 12.8 percent at September 30, 2020. For additional information regarding debt agreements, refer to Note
8—Income Taxes7—Debt to our Consolidated Financial Statements.
Critical Accounting Policies
Our contractual obligations as of September 30, 2021 are summarized in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Payments due by year |
| (in thousands) | Total | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter |
Debt1 | 1,037,148 | | | 487,148 | | | — | | | — | | | — | | | — | | | 550,000 | |
Interest2 | 162,915 | | | 16,239 | | | 16,289 | | | 16,159 | | | 16,251 | | | 16,253 | | | 81,724 | |
Make-whole premium and accrued interest3 | 59,064 | | | 59,064 | | | — | | | — | | | — | | | — | | | — | |
Operating leases4 | 39,863 | | | 10,596 | | | 8,660 | | | 7,391 | | | 4,332 | | | 1,876 | | | 7,008 | |
Purchase obligations5 | 48,100 | | | 48,100 | | | — | | | — | | | — | | | — | | | — | |
| Total contractual obligations | $ | 1,347,090 | | | $ | 621,147 | | | $ | 24,949 | | | $ | 23,550 | | | $ | 20,583 | | | $ | 18,129 | | | $ | 638,732 | |
(1)On October 27, 2021, we redeemed the $487.1 million outstanding 2025 Notes. See Note 7—Debt to our Consolidated Financial Statements.
(2)Interest on fixed-rate 2031 Notes was estimated based on principal maturities. See Note 7—Debt to our Consolidated Financial Statements.
(3)On October 27, 2021, we redeemed all of the outstanding 2025 Notes, which resulted in the payment of a make-whole premium and Estimatesaccrued interest on the 2025 Notes. See Note 7—Debt to our Consolidated Financial Statements.
(4)See Note 5—Leases to our Consolidated Financial Statements.
(5)See Note 16—Commitments and Contingencies to our Consolidated Financial Statements.
| | | | | | | | | | | | | | |
| Critical Accounting Policies and Estimates |
Accounting policies that we consider significant are summarized in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties to our Consolidated Financial Statements included in Part II, Item
8 – 8—"Financial Statements and Supplementary
DataData" of this
report.Form 10-K. The preparation of our financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. These estimates and assumptions are evaluated on an
on‑goingongoing basis. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies and estimates used in our financial statements.2021 FORM 10-K|52
Property, Plant and Equipment
Property, plant and equipment, including renewals and betterments, are capitalized at cost, while maintenance and repairs are expensed as incurred. The interest expense applicable to the construction of qualifying assets is capitalized as a component of the cost of such assets. We account for the depreciation of property, plant and equipment using the
straight‑straight‑line method over the estimated useful lives of the assets considering the estimated salvage value of the property, plant and equipment. Both the estimated useful lives and salvage values require the use of management estimates. Assets held-for-sale are reported at the lower of the carrying amount or fair value less estimated costs to sell. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation or result in abandonments. For the fiscal years presented in this report,Form 10-K, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.Impairment of
Long‑Long‑lived Assets, Goodwill and Other Intangible AssetsManagement assesses the potential impairment of our long‑long‑lived assets and finite-lived intangibles whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, change in technology and/or overall changes in general market conditions. If a review of the long‑long‑lived assets and finite-lived intangibles indicates that the carrying value of certain of these assets or asset groups is more than the estimated undiscounted future cash flows, an impairment charge
is made, as required, to adjust the carrying value to the estimated fair value. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig’s marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics including utilization. The fair value of drilling rigs is determined based upon either an income approach using estimated discounted future cash flows, ora market approach considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors.factors, a cost approach utilizing reproduction costs new as adjusted for the asset age and condition, and/or a combination of multiple approaches. The use of different assumptions could increase or decrease the estimated fair value of assets and could therefore affect any impairment measurement.
We review goodwill
and indefinite-lived intangible assets for impairment annually in the fourth fiscal quarter or more frequently if events or changes in circumstances indicate
it is more likely than not that the carrying amount of
such goodwill and indefinite-lived intangible assets may exceed their fair value. For impairment testing, goodwill is evaluated at the reporting unit
level.holding such goodwill may exceed its fair value. We initially assess goodwill for impairment based on qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount.
If further testing is necessary or a quantitative test is elected, we quantitatively compare the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds the fair value, an impairment charge will be recognized in an amount equal to the excess; however, the loss recognized would not exceed the total amount of goodwill allocated to that reporting unit. Impairment for indefinite-lived intangible assets is measured as
Self‑Insurance Accruals
We insure working land rigs and related equipment at values that approximate the
difference betweencurrent replacement costs on the
fair valueinception date of the
assetpolicies. However, we self-insure large deductibles under these policies. We also carry insurance with varying deductibles and
its carrying value.At September 30, 2018, we performed impairment testing on our International FlexRig4 asset group, which has an aggregate net book value of $63.0 million. We concluded that the net book value of the drilling rig’s asset group is recoverable through estimated undiscounted future cash flowscoverage limits with a surplus of approximately 23 percent. The most significant assumptions used in our undiscounted cash flow model include: timing on awards of future drilling contracts, oil prices, operating dayrates, operating costs, rig- reactivation costs, drilling rig utilization, revenue efficiency, estimated remaining economic useful liferespect to stacked rigs, offshore platform rigs, and net proceeds received upon future sale/disposition. The assumptions are consistent with the Company’s internal budgets and forecasts for future years. These significant assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. Although we believe the assumptions used in our analysis are reasonable and appropriate and the asset group weighted average of expected future undiscounted net cash flows exceeds the net book value of the asset group as of the fiscal year 2018 year-end impairment evaluation, different assumptions and estimates could materially impact the analysis and our resulting conclusion.
At September 30, 2018, we engaged a third party independent accounting firm who performed a market valuation, utilizing the market approach, on two of our domestic and international conventional rigs’ asset groups, which have an aggregate net book values of $9.0 million and $15.2 million, respectively. We concluded that the fair values of these two asset groups exceed the net book values by approximately 64 percent and 141 percent, respectively and as such, no impairment was recorded. The significant assumptions“named wind storm” risk in the valuation exercise are classified as Level 2Gulf of Mexico. We self‑insure a number of other risks, including loss of earnings and Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures.
During fiscal years 2018 and 2016, we recognized $23.1 million and $6.3 million, respectively of asset impairment charges.
Self‑Insurance Accruals
business interruption.
We self‑self‑insure a significant portion of expected losses relating to workers’ compensation, general liability, employer’s liability and automobile liability. Generally, deductibles range from $1 million to $5$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 workers’ compensation and other casualty claims. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred. Estimates for liabilities and retained losses are based on adjusters’ estimates, our historical loss experience and statistical methods commonly used within the insurance industry that we believe are reliable.
We also engage
ana third-party actuary to perform a periodic review of our
domestic casualty losses. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.
Our wholly‑wholly‑owned captive insurance company financescompanies finance a significant portion of the physical damage risk on company‑company‑owned drilling rigs as well as international casualty deductibles. An actuary reviews our captive lossesthe loss reserves retained by the Company and the captives on an annual basis.
We insure land rigs
2021 FORM 10-K|53
Revenue Recognition
Drilling services and
related equipment at values that approximate the current replacement costs on the inception date of the policies. However, we self-insure large deductibles under these policies. We also carry insurance with varying deductibles and coverage limits with respect to offshore platform rigs and “named wind storm” risk in the Gulf of Mexico. We self‑insure a number of other risks, including loss of earnings and business interruption, and most cyber risks.Revenue Recognition
Contract drillingsolutions revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized overon a straight-line basis as 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‑out‑of‑pocket expenses are recorded as both revenues and direct costs.revenue. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.
Pension Costs
Income Taxes
Deferred income taxes are accounted for under the liability method, which takes into account the differences between the basis of the assets and Obligationsliabilities for financial reporting purposes and amounts recognized for income tax purposes. Our pension benefit costsnet deferred tax liability balance at year-end reflects the application of our income tax accounting policies and obligationsis based on management’s estimates, judgments and assumptions. Included in our net deferred tax liability balance are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan assets. Our discount ratedeferred tax assets that are assessed for realizability. If it is determined by matching projected cash distributions withmore likely than not that a portion of the appropriate corporate bond yieldsdeferred tax assets will not be realized in a yield curve analysis. The discount rate was increased to 4.27 percent from 3.79 percent as of September 30, 2018 to reflect changes infuture period, the market conditions for high‑quality fixed‑income investments. The expected return on plandeferred tax assets is determinedwill be reduced by a valuation allowance based on historical portfolio resultsmanagement’s estimates.
In addition, we operate in several countries throughout the world and
our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions we believe have a greater than 50 percent likelihood of being sustained. We cannot predict or provide assurance as to the ultimate outcome of any existing or future
expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated from future periods. We anticipate pension expense to decrease by approximately $1.4 million in fiscal year 2019 from fiscal year 2018.Stock‑Based Compensation
Historically, we have granted stock‑based awards to key employees and non‑employee directors as part of their compensation. We estimate the fair value of all stock option awards as of the date of grant by applying the Black‑Scholes option‑pricing model. The application of this valuation model involves assumptions, some of which are judgmental and highly sensitive. These assumptions include, among others, the expected stock price volatility, the expected life of the stock options and the risk‑free interest rate. Expected volatilities were estimated using the historical volatility of our stock based upon the expected term of the option. The expected term of the option was derived from historical data and represents the period of time that options are estimated to be outstanding. The risk‑free interest rate for periods within the estimated life of the option was based on the U.S. Treasury Strip rate in effect at the time of the grant. The fair value of each award is amortized on a straight‑line basis over the vesting period for awards granted to employees and non-employee directors.
The fair value of restricted stock awards is determined based on the closing price of our common stock on the date of grant. We amortize the fair value of restricted stock awards to compensation expense on a straight‑line basis over the vesting period.
New Accounting Standards
assessments.
See Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties to our Consolidated Financial Statements for recently adopted accounting standards and new accounting standards not yet adopted.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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| ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Our financial position is exposed to a variety of risks, including foreign currency exchange risk, commodity price risk, credit and capital market risk, interest rate risk and equity price risk. We have seen an increase in these risks and related uncertainties with increased volatility in oil and gas prices and the financial markets as a result of the COVID-19 pandemic.
Foreign Currency Exchange Rate Risk
Our drilling contracts in foreign countries generally provide for payment in U.S. dollars.
However,Historically, in Argentina, while the
contract iscontracts were denominated in the U.S. dollar, we
arewere paid in Argentine pesos.
We are currently receiving some customer payments in U.S. dollars, but we will likely receive future payments in Argentine pesos as we have in the past. The Argentine branch of one of our
second‑second‑tier subsidiaries then convertsremits U.S. dollars to its U.S. parent by converting the Argentine pesos tointo U.S. dollars through the Argentine Foreign Exchange Market and then remitsrepatriating the dollars to its U.S. parent.dollars. In the future, other contracts or applicable law may require payments to be made in foreign currencies. As such, there can be no assurance that we will not experience in Argentina or elsewhere a devaluation of foreign currency, foreign exchange restrictions or other difficulties repatriating U.S. dollars even if we are able to negotiate the contract provisions designed to mitigate such risks. In the future, we may incur currency devaluations, foreign exchange restrictions or other difficulties repatriating U.S. dollars in Argentina or elsewhere, which could have a material adverse impact on our business, financial condition and results of operations. At September 30, 2018,2021, a hypothetical decrease in value of 10 percent would result in an insignificanta decrease in value of our monetary assets and liabilities denominated in Argentine pesos by approximately $4,595.$2.5 million.
Argentina’s economy is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent
three‑three‑year period based on inflation data published by the respective governments. Nonetheless, all of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations.2021 FORM 10-K|54
The demand for
contract drilling services
and solutions is derived from exploration and production companies spending money to explore and develop drilling prospects in search of crude oil and natural gas. Their spending is driven by their cash flow and financial strength, which is affected by trends in crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including global supply and demand, the establishment of and compliance with production quotas by oil exporting countries, worldwide economic conditions and geopolitical factors. Crude oil and natural gas prices have historically been volatile and very difficult to predict with any degree of certainty. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining future spending levels. This volatility can lead many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for
contract drilling services
and solutions is not always purely a function of the movement of commodity prices.
Credit and Capital Market Risk
Customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets, as experienced in the past, can make it difficult for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in customer credit defaults or reduced demand for our services, which could have a material adverse effect on our business, financial condition and results of operations. Similarly, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by, among other things, oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health of the drilling and overall oil and gas industry, and the liquidity of the capital markets. Many of the factors that affect our ability to access capital markets are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations.
Further, we attempt to secure favorable prices through advanced ordering and purchasing for drilling rig components. While these materials have generally been available at acceptable prices, there is no assurance the prices will not vary significantly in the future. Any fluctuations in market conditions causing increased prices in materials and supplies could have a material adverse effect on future operating costs.
Our interest rate risk exposure results primarily from short‑short‑term rates, mainly LIBOR‑LIBOR‑based, on any borrowings from our revolving credit facility. There were no outstanding borrowings under this facility at September 30, 2018,2021, and our
outstanding debt consisted of $500 million$1.0 billion (face amount) in a senior unsecured note,notes, of which has$487.1 million is classified as current. In September 2021, we issued $550.0 million principal amount of senior unsecured notes, which have a fixed rate of 4.65 percent. At2.90 percent, and delivered a conditional notice, satisfied on September 30, 2018,29, 2021, of optional full redemption for all of the average interest rate risk on our fixed-rate debt of $500 million was estimated to beoutstanding 4.65 percent after 2023. Comparatively, we estimated our interest rate risk at September 30, 2017 to be 4.65 percent after 2022.senior unsecured notes, which have a carrying value of $487.1 million. The fair value of the fixed-rate debt4.65 percent senior unsecured notes was estimated to be $509.3$541.6 million and $529.0$534.5 million for fiscal years 20182021 and 2017, respectively.
2020, respectively, and the fair value of the 2.90 percent senior unsecured notes was estimated to be $554.3 million at September 30, 2021.
On September 30, 2018,2021, we had a portfolio ofequity securities with a total fair value of $82.5 million. The total fair value of the portfolio of securities was $70.2$13.9 million compared to $7.3 million at September 30, 2017.2020. A hypothetical 10 percent decrease in the market pricesprice for allour marketable equity securities in our portfolio as of September 30, 20182021 would decrease the fair value of our available‑for‑sale securities by $8.3$1.4 million. We make no specific plans to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market‑market‑related risks that could substantially reduce or increase the fair value of our holdings. The portfolio is recorded at fair value on the balance sheet with changes in unrealized after‑tax value reflected in the equity section of the balance sheet unless a decline in fair value below our cost basis is considered to be other than temporary in which case the change is recorded through earnings.
At November 8,
2018,2021, the total fair value of our
equity securities
decreasedincreased to approximately
$68.5$16.0 million.
Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements.
53
2021 FORM 10-K|55
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
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| ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
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| INDEX TO CONSOLIDATED FINANCIAL STATEMENTS | | Page
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| PAGE |
| | 55 |
| | 56 |
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| Consolidated Financial Statements: | | |
| 2020 | 58 |
| 2019 | 59 |
| 2019 | 60 |
| 2019 | 61 |
| 2019 | 62 |
| | 63 |
54
2021 FORM 10-K|56
Management’s Report on Internal Control over Financial Reporting
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| Management’s Report on Internal Control over Financial Reporting |
Management of Helmerich & Payne, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule
13a‑13a‑15(f) or 15d‑15d‑15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting was designed under the supervision of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America, and includes those policies and procedures that: | (i)
| | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
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(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
|
(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.
|
(iii)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018.2021. In making this assessment, management used the criteria established in theInternal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the criteria in Internal Control-Integrated Framework (2013), management has concluded that the Company maintained effective internal control over financial reporting as of September 30, 2018.2021.
Ernst & Young LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018,2021, as stated in their report which appears herein.
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| Helmerich & Payne, Inc. | | |
| | |
by | | |
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/s/ John W. Lindsay | | /s/ Mark W. Smith |
John W. Lindsay
Director, President and Chief Executive Officer | | Mark W. Smith |
Director, President and
| |
Senior Vice President and
|
Chief Executive Officer
| | Chief Financial Officer |
| | |
November 16, 2018 18, 2021 | | November 16, 2018 18, 2021 |
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2021 FORM 10-K|57
Report of Independent Registered Public Accounting Firm
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| Report of Independent Registered Public Accounting Firm |
The Board of Directors and Shareholders of
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. (the Company) as of September 30,
20182021 and
2017, and2020, the related consolidated statements of operations, comprehensive
income (loss),loss, shareholders' equity and cash flows for each of the three years in the period ended September 30,
2018,2021, and the related notes (collectively referred to as the “consolidated financial statements”).
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2018,2021, in conformity with U.S. generally accepted accounting principles.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of September 30,
2018,2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November
16, 2018,18, 2021 expressed an unqualified opinion thereon.
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits
includeincluded performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures
includeincluded examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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| Self-Insurance Accruals |
Description of the Matter | | The Company's self-insurance liability for workers’ compensation and other casualty claims was $81.0 million at September 30, 2021. 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. |
2021 FORM 10-K|58
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How We Addressed the Matter in Our Audit | | We evaluated the design and tested the operating effectiveness of the Company’s controls over the workers’ compensation and other casualty claims accrual process, 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 assumptions to ranges of assumptions independently developed by our actuarial specialists. |
| | Valuation of Assets Held-for-Sale |
Description of the Matter | | As more fully described in Note 4—Property, Plant and Equipment to the consolidated financial statements, during 2021 the Company committed to a plan to sell 71 non-super spec rigs. This action resulted in classification of the assets as held-for-sale. The Company measured these assets at fair value less cost to sell, resulting in a $56.4 million impairment charge.
Auditing the Company's valuation of the assets-held-for-sale was complex and required subjective judgment and involvement of a valuation specialist in evaluating management’s assumptions used in determining the fair value less costs to sell. Significant assumptions used in the Company’s estimate included management’s use of market quotes. |
How We Addressed the Matter in Our Audit | | We evaluated the design and tested the operating effectiveness of controls over the Company's process to estimate fair value less costs to sell. For example, we tested management's review controls over the significant assumptions underlying the fair value analysis.
Our testing of the Company’s held-for-sale analysis included, among other procedures, evaluating management’s selection of valuation methodologies, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. For example, we compared the market quotes used in the analysis to external documentation. We also performed sensitivity analyses of the assumptions to evaluate the change in the fair value resulting from changes in assumptions. We involved our valuation specialists to assist in our procedures. |
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| /s/Ernst & Young LLP | | |
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| We have served as the Company’s auditor since 1994. | | |
Tulsa, Oklahoma | | |
November 16, 2018 18, 2021 | | |
2021 FORM 10-K|59
Report of Independent Registered Public Accounting Firm
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| Report of Independent Registered Public Accounting Firm |
The Board of Directors and Shareholders of
Opinion on Internal Control over Financial Reporting
We have audited Helmerich & Payne, Inc.’s internal control over financial reporting as of September 30,
2018,2021, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Helmerich & Payne, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30,
2018,2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets
of the Company as of September 30,
20182021 and
2017, and2020, the related consolidated statements of operations, comprehensive
income (loss),loss, shareholders’ equity and cash flows for each of the three years in the period ended September 30,
2018,2021, and the related notes and our report dated November
16, 201818, 2021 expressed an unqualified opinion thereon.
The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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| /s/ Ernst & Young LLP | | |
| | |
Tulsa, Oklahoma | | |
November 16, 2018 18, 2021 | | |
57
2021 FORM 10-K|60
HELMERICH & PAYNE, INC.
Consolidated Balance Sheets
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| HELMERICH & PAYNE, INC. | | | |
| CONSOLIDATED BALANCE SHEETS | | | |
| September 30, |
| (in thousands except share data and per share amounts) | 2021 | | 2020 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 917,534 | | | $ | 487,884 | |
| Short-term investments | 198,700 | | | 89,335 | |
| Accounts receivable, net of allowance of $2,068 and $1,820, respectively | 228,894 | | | 192,623 | |
| Inventories of materials and supplies, net | 84,057 | | | 104,180 | |
| Prepaid expenses and other, net | 85,928 | | | 89,305 | |
| Assets held-for-sale | 71,453 | | | — | |
| Total current assets | 1,586,566 | | | 963,327 | |
| | | |
| Investments | 135,444 | | | 31,585 | |
| Property, plant and equipment, net | 3,127,287 | | | 3,646,341 | |
| Other Noncurrent Assets: | | | |
| Goodwill | 45,653 | | | 45,653 | |
| Intangible assets, net | 73,838 | | | 81,027 | |
| Operating lease right-of-use asset | 49,187 | | | 44,583 | |
| Other assets, net | 16,153 | | | 17,105 | |
| Total other noncurrent assets | 184,831 | | | 188,368 | |
| | | |
| Total assets | $ | 5,034,128 | | | $ | 4,829,621 | |
| | | |
| LIABILITIES & SHAREHOLDERS' EQUITY | | | |
| Current Liabilities: | | | |
| Accounts payable | $ | 71,996 | | | $ | 36,468 | |
| Dividends payable | 27,332 | | | 27,226 | |
| Current portion of long-term debt | 483,486 | | | — | |
| | | |
| Accrued liabilities | 283,492 | | | 155,442 | |
| Total current liabilities | 866,306 | | | 219,136 | |
| | | |
| Noncurrent Liabilities: | | | |
| Long-term debt, net | 541,997 | | | 480,727 | |
| Deferred income taxes | 563,437 | | | 650,675 | |
| Other | 147,757 | | | 147,180 | |
| Noncurrent liabilities - discontinued operations | 2,013 | | | 13,389 | |
| Total noncurrent liabilities | 1,255,204 | | | 1,291,971 | |
| Commitments and Contingencies (Note 16) | 0 | | 0 |
| Shareholders' Equity: | | | |
| Common stock, $0.10 par value, 160,000,000 shares authorized, 112,222,865 and 112,151,563 shares issued as of September 30, 2021 and 2020, respectively, and 107,898,859 and 107,488,242 shares outstanding as of September 30, 2021 and 2020, respectively | 11,222 | | | 11,215 | |
| Preferred stock, no par value, 1,000,000 shares authorized, no shares issued | — | | | — | |
| Additional paid-in capital | 529,903 | | | 521,628 | |
| Retained earnings | 2,573,375 | | | 3,010,012 | |
| Accumulated other comprehensive loss | (20,244) | | | (26,188) | |
| Treasury stock, at cost, 4,324,006 shares and 4,663,321 shares as of September 30, 2021 and 2020, respectively | (181,638) | | | (198,153) | |
| Total shareholders’ equity | 2,912,618 | | | 3,318,514 | |
| Total liabilities and shareholders' equity | $ | 5,034,128 | | | $ | 4,829,621 | |
| | | | | | |
| | September 30, |
(in thousands except share data and per share amounts) | | 2018 | | 2017 |
Assets | | | | | | |
Current Assets: | | | | | | |
Cash and cash equivalents | | $ | 284,355 | | $ | 521,375 |
Short-term investments | | | 41,461 | | | 44,491 |
Accounts receivable, net of allowance of $6,217 and $5,721, respectively | | | 565,202 | | | 477,074 |
Inventories of materials and supplies, net | | | 158,134 | | | 137,204 |
Prepaid expenses and other | | | 66,398 | | | 55,123 |
Total current assets | | | 1,115,550 | | | 1,235,267 |
Investments | | | 98,696 | | | 84,026 |
Property, plant and equipment, net | | | 4,857,382 | | | 5,001,051 |
Noncurrent Assets: | | | | | | |
Goodwill | | | 64,777 | | | 51,705 |
Intangible assets, net | | | 73,207 | | | 50,785 |
Other assets | | | 5,255 | | | 17,154 |
Total noncurrent assets | | | 143,239 | | | 119,644 |
| | | | | | |
Total assets | | $ | 6,214,867 | | $ | 6,439,988 |
| | | | | | |
Liabilities and Shareholders’ Equity | | | | | | |
Current Liabilities: | | | | | | |
Accounts payable | | $ | 132,664 | | $ | 135,628 |
Accrued liabilities | | | 244,504 | | | 208,757 |
Total current liabilities | | | 377,168 | | | 344,385 |
Noncurrent Liabilities: | | | | | | |
Long-term debt | | | 493,968 | | | 492,902 |
Deferred income taxes | | | 853,136 | | | 1,332,689 |
Other | | | 93,606 | | | 101,409 |
Noncurrent liabilities - discontinued operations | | | 14,254 | | | 4,012 |
Total noncurrent liabilities | | | 1,454,964 | | | 1,931,012 |
Commitments and Contingencies (Note 15) | | | | | | |
Shareholders' Equity: | | | | | | |
Common stock, $.10 par value, 160,000,000 shares authorized,112,008,961 and 111,956,875 shares issued as of September 30, 2018 and 2017, respectively, and 108,993,718 and 108,604,047 shares outstanding as of September 30, 2018 and 2017, respectively | | | 11,201 | | | 11,196 |
Preferred stock, no par value, 1,000,000 shares authorized, no shares issued | | | — | | | — |
Additional paid-in capital | | | 500,393 | | | 487,248 |
Retained earnings | | | 4,027,779 | | | 3,855,686 |
Accumulated other comprehensive income | | | 16,550 | | | 2,300 |
Treasury stock, at cost, 3,015,243 shares and 3,352,828 shares as of September 30, 2018 and 2017, respectively | | | (173,188) | | | (191,839) |
Total shareholders’ equity | | | 4,382,735 | | | 4,164,591 |
Total liabilities and stockholders' equity | | $ | 6,214,867 | | $ | 6,439,988 |
The accompanying notes are an integral part of these consolidated financial statements.
2021 FORM 10-K|61
HELMERICH & PAYNE, INC.
Consolidated Statements of Operations
| | | | | | | | | | | | | | | | | |
| HELMERICH & PAYNE, INC. | | | | | |
| CONSOLIDATED STATEMENTS OF OPERATIONS |
| Year Ended September 30, |
| (in thousands, except per share amounts) | 2021 | | 2020 | | 2019 |
| OPERATING REVENUES | | | | | |
| Drilling services | $ | 1,210,800 | | | $ | 1,761,714 | | | $ | 2,785,557 | |
| Other | 7,768 | | | 12,213 | | | 12,933 | |
| 1,218,568 | | | 1,773,927 | | | 2,798,490 | |
| OPERATING COSTS AND EXPENSES | | | | | |
| Drilling services operating expenses, excluding depreciation and amortization | 952,600 | | | 1,184,788 | | | 1,803,204 | |
| Other operating expenses | 5,138 | | | 5,777 | | | 5,382 | |
| Depreciation and amortization | 419,726 | | | 481,885 | | | 562,803 | |
| Research and development | 21,724 | | | 21,645 | | | 27,467 | |
| Selling, general and administrative | 172,195 | | | 167,513 | | | 194,416 | |
| Asset impairment charge | 70,850 | | | 563,234 | | | 224,327 | |
| Restructuring charges | 5,926 | | | 16,047 | | | — | |
| Gain on sale of assets | (1,042) | | | (46,775) | | | (39,691) | |
| 1,647,117 | | | 2,394,114 | | | 2,777,908 | |
| OPERATING INCOME (LOSS) FROM CONTINUING OPERATIONS | (428,549) | | | (620,187) | | | 20,582 | |
| Other income (expense) | | | | | |
| Interest and dividend income | 10,254 | | | 7,304 | | | 9,468 | |
| Interest expense | (23,955) | | | (24,474) | | | (25,188) | |
| Gain (loss) on investment securities | 6,727 | | | (8,720) | | | (54,488) | |
| Gain on sale of subsidiary | — | | | 14,963 | | | — | |
| Other | (5,657) | | | (5,384) | | | (1,596) | |
| (12,631) | | | (16,311) | | | (71,804) | |
| Loss from continuing operations before income taxes | (441,180) | | | (636,498) | | | (51,222) | |
| Income tax benefit | (103,721) | | | (140,106) | | | (18,712) | |
| Loss from continuing operations | (337,459) | | | (496,392) | | | (32,510) | |
| Income from discontinued operations before income taxes | 11,309 | | | 30,580 | | | 32,848 | |
| Income tax provision | — | | | 28,685 | | | 33,994 | |
| Income (loss) from discontinued operations | 11,309 | | | 1,895 | | | (1,146) | |
| NET LOSS | $ | (326,150) | | | $ | (494,497) | | | $ | (33,656) | |
| Basic earnings (loss) per common share: | | | | | |
| Loss from continuing operations | $ | (3.14) | | | $ | (4.62) | | | $ | (0.33) | |
| Income (loss) from discontinued operations | 0.10 | | | 0.02 | | | (0.01) | |
| Net loss | $ | (3.04) | | | $ | (4.60) | | | $ | (0.34) | |
| Diluted earnings (loss) per common share: | | | | | |
| Loss from continuing operations | $ | (3.14) | | | $ | (4.62) | | | $ | (0.33) | |
| Income (loss) from discontinued operations | 0.10 | | | 0.02 | | | (0.01) | |
| Net loss | $ | (3.04) | | | $ | (4.60) | | | $ | (0.34) | |
| Weighted average shares outstanding: | | | | | |
| Basic | 107,818 | | | 108,009 | | | 109,216 | |
| Diluted | 107,818 | | | 108,009 | | | 109,216 | |
| | | | | | | | | |
| | Year Ended September 30, |
(in thousands, except per share amounts) | | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | |
Contract drilling | | $ | 2,449,051 | | $ | 1,788,758 | | $ | 1,610,957 |
Other | | | 38,217 | | | 15,983 | | | 13,275 |
| | | 2,487,268 | | | 1,804,741 | | | 1,624,232 |
Operating costs and expenses | | | | | | | | | |
Contract drilling operating expenses, excluding depreciation and amortization | | | 1,626,387 | | | 1,242,605 | | | 892,748 |
Operating expenses applicable to other revenues | | | 26,223 | | | 6,712 | | | 6,057 |
Depreciation and amortization | | | 583,802 | | | 585,543 | | | 598,587 |
Research and development | | | 18,167 | | | 12,047 | | | 10,269 |
Selling, general and administrative | | | 200,619 | | | 151,002 | | | 146,183 |
Asset impairment charge | | | 23,128 | | | — | | | 6,250 |
Gain on sale of assets | | | (22,660) | | | (20,627) | | | (9,896) |
| | | 2,455,666 | | | 1,977,282 | | | 1,650,198 |
Operating income (loss) from continuing operations | | | 31,602 | | | (172,541) | | | (25,966) |
Other income (expense) | | | | | | | | | |
Interest and dividend income | | | 8,017 | | | 5,915 | | | 3,166 |
Interest expense | | | (24,265) | | | (19,747) | | | (22,913) |
Gain (loss) on investment securities | | | 1 | | | — | | | (25,989) |
Other | | | 486 | | | 1,775 | | | (965) |
| | | (15,761) | | | (12,057) | | | (46,701) |
Income (loss) from continuing operations before income taxes | | | 15,841 | | | (184,598) | | | (72,667) |
Income tax benefit | | | (477,169) | | | (56,735) | | | (19,677) |
Income (loss) from continuing operations | | | 493,010 | | | (127,863) | | | (52,990) |
Income from discontinued operations before income taxes | | | 23,389 | | | 3,285 | | | 2,360 |
Income tax provision | | | 33,727 | | | 3,634 | | | 6,198 |
Loss from discontinued operations | | | (10,338) | | | (349) | | | (3,838) |
Net Income (Loss) | | $ | 482,672 | | $ | (128,212) | | $ | (56,828) |
Basic earnings per common share: | | | | | | | | | |
Income (loss) from continuing operations | | $ | 4.49 | | $ | (1.20) | | $ | (0.50) |
Loss from discontinued operations | | $ | (0.10) | | $ | — | | $ | (0.04) |
Net income (loss) | | $ | 4.39 | | $ | (1.20) | | $ | (0.54) |
Diluted earnings per common share: | | | | | | | | | |
Income (loss) from continuing operations | | $ | 4.47 | | $ | (1.20) | | $ | (0.50) |
Loss from discontinued operations | | $ | (0.10) | | $ | — | | $ | (0.04) |
Net income (loss) | | $ | 4.37 | | $ | (1.20) | | $ | (0.54) |
Weighted average shares outstanding (in thousands): | | | | | | | | | |
Basic | | | 108,851 | | | 108,500 | | | 107,996 |
Diluted | | | 109,387 | | | 108,500 | | | 107,996 |
The accompanying notes are an integral part of these consolidated financial statements.
59
2021 FORM 10-K|62
HELMERICH & PAYNE, INC.
Consolidated Statements of Comprehensive Income (Loss)
| | | | | | | | | |
| | Year Ended September 30, |
(in thousands) | | 2018 | | 2017 | | 2016 |
Net income (loss) | | $ | 482,672 | | $ | (128,212) | | $ | (56,828) |
Other comprehensive income (loss), net of income taxes: | | | | | | | | | |
Unrealized appreciation (depreciation) on securities, net of income taxes of $3.3 million at September 30, 2018, ($0.5) million at September 30, 2017 and $1.7 million at September 30, 2016 | | | 9,001 | | | (829) | | | 2,772 |
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, 2018, $1.9 million at September 30, 2017 and ($1.4) million at September 30, 2016 | | | 5,249 | | | 3,333 | | | (2,525) |
Other comprehensive income | | | 14,250 | | | 2,504 | | | 1,173 |
Comprehensive income (loss) | | $ | 496,922 | | $ | (125,708) | | $ | (55,655) |
| | | | | | | | | | | | | | | | | |
| HELMERICH & PAYNE, INC. | | | | | |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS |
| Year ended September 30, |
| (in thousands) | 2021 | | 2020 | | 2019 |
| Net loss | $ | (326,150) | | | $ | (494,497) | | | $ | (33,656) | |
| Other comprehensive income (loss), net of income taxes: | | | | | |
| Net change related to employee benefit plans, net of income taxes of $1.8 million at September 30, 2021, $0.8 million at September 30, 2020 and $(3.5) million at September 30, 2019 | 5,944 | | | 2,447 | | | (11,875) | |
| Other comprehensive income (loss) | 5,944 | | | 2,447 | | | (11,875) | |
| Comprehensive loss | $ | (320,206) | | | $ | (492,050) | | | $ | (45,531) | |
The accompanying notes are an integral part of these consolidated financial statements.
60
2021 FORM 10-K|63
HELMERICH & PAYNE, INC.
Consolidated Statements of Shareholders’ Equity
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | Accumulated | | | | | | | | |
| | | | | | | Additional | | | | | Other | | | | | | | | |
| | Common Stock | | Paid-In | | Retained | | Comprehensive | | Treasury Stock | | | |
(in thousands, except per share amounts) | | Shares | | Amount | | Capital | | Earnings | | (Loss) Income | | Shares | | Amount | | Total |
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 ($2.78 per share) | | | | | | | | | | | (301,711) | | | | | | | | | | | (301,711) |
Exercise of employee stock options, net of shares withheld for employee taxes | | 220 | | | 22 | | | 6,937 | | | | | | | | 99 | | | (5,919) | | | 1,040 |
Tax benefit of stock-based awards | | | | | | | | 934 | | | | | | | | | | | | | | 934 |
Vesting of restricted stock awards, 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 Income: | | | | | | | | | | | | | | | | | | | | | | |
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 employee stock options, net of shares withheld for employee taxes | | 415 | | | 42 | | | 15,738 | | | | | | | | 88 | | | (5,246) | | | 10,534 |
Tax benefit of stock-based awards | | | | | | | | 4,414 | | | | | | | | | | | | | | 4,414 |
Vesting of restricted stock awards, 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 |
Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | | | | | | | | | 482,672 | | | | | | | | | | | 482,672 |
Other comprehensive income | | | | | | | | | | | | | | 14,250 | | | | | | | | 14,250 |
Dividends declared ($2.82 per share) | | | | | | | | | | | (310,024) | | | | | | | | | | | (310,024) |
Exercise of employee stock options, net of shares withheld for employee taxes | | 1 | | | | | | (7,557) | | | | | | | | (202) | | | 10,992 | | | 3,435 |
Vesting of restricted stock awards, net of shares withheld for employee taxes | | 51 | | | 5 | | | (11,857) | | | | | | | | (136) | | | 7,659 | | | (4,193) |
Stock-based compensation | | | | | | | | 31,687 | | | | | | | | | | | | | | 31,687 |
Adoption of ASU 2016-09 (Note 2) | | | | | | | | 872 | | | (555) | | | | | | | | | | | 317 |
Balance, September 30, 2018 | | 112,009 | | $ | 11,201 | | $ | 500,393 | | $ | 4,027,779 | | $ | 16,550 | | 3,015 | | $ | (173,188) | | $ | 4,382,735 |
The accompanying notes are an integral part of these consolidated financial statement.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, 2018 | 112,009 | | | $ | 11,201 | | | $ | 500,393 | | | $ | 4,027,779 | | | $ | 16,550 | | | 3,015 | | | $ | (173,188) | | | $ | 4,382,735 | |
| Comprehensive loss: | | | | | | | | | | | | | | | |
| Net loss | — | | | — | | | — | | | (33,656) | | | — | | | — | | | — | | | (33,656) | |
| Other comprehensive loss | — | | | — | | | — | | | — | | | (11,875) | | | — | | | — | | | (11,875) | |
| Dividends declared ($2.84 per share) | — | | | — | | | — | | | (313,088) | | | — | | | — | | | — | | | (313,088) | |
| Exercise of employee stock options, net of shares withheld for employee taxes | — | | | — | | | (7,153) | | | — | | | — | | | (151) | | | 8,474 | | | 1,321 | |
| Vesting of restricted stock awards, net of shares withheld for employee taxes | 71 | | | 7 | | | (17,227) | | | — | | | — | | | (222) | | | 12,531 | | | (4,689) | |
| Stock-based compensation | — | | | — | | | 34,292 | | | — | | | — | | | — | | | — | | | 34,292 | |
| Share repurchases | — | | | — | | | — | | | — | | | — | | | 1,000 | | | (42,779) | | | (42,779) | |
| Cumulative effect adjustment for adoption of ASU No. 2014-09 | — | | | — | | | — | | | (38) | | | — | | | — | | | — | | | (38) | |
| Cumulative effect adjustment for adoption of ASU No. 2016-01 | — | | | — | | | — | | | 29,071 | | | (29,071) | | | — | | | — | | | — | |
| Reclassification of stranded tax effect for adoption of ASU No. 2018-02 | — | | | — | | | — | | | 4,239 | | | (4,239) | | | — | | | — | | | — | |
| Balance at September 30, 2019 | 112,080 | | | $ | 11,208 | | | $ | 510,305 | | | $ | 3,714,307 | | | $ | (28,635) | | | 3,642 | | | $ | (194,962) | | | $ | 4,012,223 | |
| Comprehensive income (loss): | | | | | | | | | | | | | | | |
| Net loss | — | | | — | | | — | | | (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 | |
HELMERICH & PAYNE, INC.
Consolidated Statements of Cash Flows
| | | | | | | | | |
| | Year Ended September 30, |
(in thousands) | | 2018 | | 2017 | | 2016 |
| | | | | As adjusted (Note 2) |
Cash flows from operating activities: | | | | | | | | | |
Net income (loss) | | $ | 482,672 | | $ | (128,212) | | $ | (56,828) |
Adjustment for income from discontinued operations | | | 10,338 | | | 349 | | | 3,838 |
Income (loss) from continuing operations | | | 493,010 | | | (127,863) | | | (52,990) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | |
Depreciation and amortization | | | 583,802 | | | 585,543 | | | 598,587 |
Asset impairment charge | | | 23,128 | | | — | | | 6,250 |
Amortization of debt discount and debt issuance costs | | | 1,067 | | | 1,055 | | | 1,168 |
Provision for (recovery of) bad debt | | | 2,193 | | | 2,016 | | | (2,013) |
Stock-based compensation | | | 31,687 | | | 26,183 | | | 24,383 |
Pension settlement charge | | | 913 | | | 1,640 | | | 4,964 |
(Gain) loss on investment securities | | | (1) | | | — | | | 25,989 |
Gain from sale of assets | | | (22,660) | | | (20,627) | | | (9,896) |
Deferred income tax (benefit) expense | | | (486,758) | | | (24,111) | | | 60,088 |
Other | | | 6,710 | | | 543 | | | 151 |
Change in assets and liabilities increasing (decreasing) cash: | | | | | | | | | |
Accounts receivable | | | (85,202) | | | (97,114) | | | 72,792 |
Inventories of materials and supplies | | | (22,427) | | | (10,607) | | | 1,944 |
Prepaid expenses and other | | | (955) | | | 31,434 | | | (2,460) |
Accounts payable | | | (4,461) | | | 39,412 | | | (10,907) |
Accrued liabilities | | | 33,173 | | | (36,120) | | | 49,562 |
Deferred income tax liability | | | 2,268 | | | 3,472 | | | 3,703 |
Other noncurrent liabilities | | | (10,787) | | | (13,075) | | | (16,831) |
Net cash provided by operating activities from continuing operations | | | 544,700 | | | 361,781 | | | 754,484 |
Net cash provided by (used in) operating activities from discontinued operations | | | (169) | | | (150) | | | 47 |
Net cash provided by operating activities | | | 544,531 | | | 361,631 | | | 754,531 |
Cash flows from investing activities: | | | | | | | | | |
Capital expenditures | | | (466,584) | | | (397,567) | | | (257,169) |
Purchase of short-term investments | | | (71,049) | | | (69,866) | | | (57,276) |
Payment for acquisition of business, net of cash acquired | | | (47,886) | | | (70,416) | | | — |
Proceeds from sale of short-term investments | | | 68,776 | | | 69,449 | | | 58,381 |
Proceeds from asset sales | | | 44,381 | | | 23,412 | | | 21,845 |
Net cash used in investing activities | | | (472,362) | | | (444,988) | | | (234,219) |
Cash flows from financing activities: | | | | | | | | | |
Payments on long-term debt | | | — | | | — | | | (40,000) |
Debt issuance costs | | | — | | | — | | | (1,111) |
Dividends paid | | | (308,430) | | | (305,515) | | | (300,152) |
Proceeds from stock option exercises | | | 6,355 | | | 11,285 | | | 2,774 |
Payments for employee taxes on net settlement of equity awards | | | (7,114) | | | (6,599) | | | (5,646) |
Net cash used in financing activities | | | (309,189) | | | (300,829) | | | (344,135) |
Net increase (decrease) in cash and cash equivalents | | | (237,020) | | | (384,186) | | | 176,177 |
Cash and cash equivalents, beginning of period | | | 521,375 | | | 905,561 | | | 729,384 |
Cash and cash equivalents, end of period | | $ | 284,355 | | $ | 521,375 | | $ | 905,561 |
| | | | | | | | | |
Supplemental disclosure of cash flow information: | | | | | | | | | |
Cash paid during the period: | | | | | | | | | |
Interest paid | | $ | 20,502 | | $ | 22,936 | | $ | 28,011 |
Income tax refund, net | | $ | 38,400 | | $ | 23,463 | | $ | 24,109 |
Changes in accounts payable and accrued liabilities related to purchases of property, plant and equipment | | $ | (2,245) | | $ | (10,539) | | $ | 15,879 |
The accompanying notes are an integral part of these consolidated financial statements.
62
2021 FORM 10-K|64
HELMERICH & PAYNE, INC.
Notes to Consolidated Financial Statements | | | | | | | | | | | | | | | | | |
| HELMERICH & PAYNE, INC. | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| Year Ended September 30, |
| (in thousands) | 2021 | | 2020 | | 2019 |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | |
| Net loss | $ | (326,150) | | | $ | (494,497) | | | $ | (33,656) | |
| Adjustment for (income) loss from discontinued operations | (11,309) | | | (1,895) | | | 1,146 | |
| Loss from continuing operations | (337,459) | | | (496,392) | | | (32,510) | |
| Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 419,726 | | | 481,885 | | | 562,803 | |
| Asset impairment charges | 70,850 | | | 563,234 | | | 224,327 | |
| Amortization of debt discount and debt issuance costs | 1,423 | | | 1,817 | | | 1,732 | |
| Provision for credit loss | 203 | | | 2,203 | | | 2,321 | |
| Stock-based compensation | 27,858 | | | 36,329 | | | 34,292 | |
| Loss (gain) on investment securities | (6,727) | | | 8,720 | | | 54,488 | |
| Gain on sale of assets | (1,042) | | | (46,775) | | | (39,691) | |
| Gain on sale of subsidiary | — | | | (14,963) | | | — | |
| Deferred income tax benefit | (89,752) | | | (157,555) | | | (44,554) | |
| | | | | |
| Other | 13,794 | | | (2,423) | | | 4,431 | |
| Change in assets and liabilities: | | | | | |
| Accounts receivable | (28,416) | | | 300,807 | | | 70,323 | |
| Inventories of materials and supplies | 19,847 | | | 9,420 | | | (5,905) | |
| Prepaid expenses and other | (21,400) | | | (5,506) | | | (176) | |
| Other noncurrent assets | 2,772 | | | 2,820 | | | (10,430) | |
| Accounts payable | 31,027 | | | (9,414) | | | (9,147) | |
| Accrued liabilities | 33,957 | | | (138,414) | | | 40,887 | |
| Deferred income tax liability | 1,101 | | | 908 | | | 371 | |
| Other noncurrent liabilities | (1,274) | | | 2,227 | | | 2,251 | |
| Net cash provided by operating activities from continuing operations | 136,488 | | | 538,928 | | | 855,813 | |
| Net cash used in operating activities from discontinued operations | (48) | | | (47) | | | (62) | |
| Net cash provided by operating activities | 136,440 | | | 538,881 | | | 855,751 | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | |
| Capital expenditures | (82,148) | | | (140,795) | | | (458,402) | |
| Purchase of investments | (417,601) | | | (134,641) | | | (97,652) | |
| Payment for acquisition of business, net of cash acquired | — | | | — | | | (16,163) | |
| Proceeds from sale of investments | 207,716 | | | 94,646 | | | 98,764 | |
| Proceeds from sale of subsidiary | — | | | 15,056 | | | — | |
| Proceeds from asset sales | 43,515 | | | 78,399 | | | 50,817 | |
| Advance payment for sale of property, plant and equipment | 86,524 | | | — | | | — | |
| Other | — | | | (550) | | | — | |
| Net cash used in investing activities | (161,994) | | | (87,885) | | | (422,636) | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | |
| Dividends paid | (109,130) | | | (260,335) | | | (313,421) | |
| Proceeds from debt issuance | 548,719 | | | — | | | — | |
| Debt issuance costs | (3,935) | | | — | | | (3,912) | |
| Proceeds from stock option exercises | — | | | 4,100 | | | 3,053 | |
| Payments for employee taxes on net settlement of equity awards | (2,162) | | | (3,784) | | | (6,418) | |
| Payment of contingent consideration from acquisition of business | (7,250) | | | (8,250) | | | — | |
| Payments for early extinguishment of long-term debt | — | | | — | | | (12,852) | |
| Share repurchases | — | | | (28,505) | | | (42,779) | |
| Other | (719) | | | (446) | | | — | |
| Net cash provided by (used in) financing activities | 425,523 | | | (297,220) | | | (376,329) | |
| Net increase in cash and cash equivalents and restricted cash | 399,969 | | | 153,776 | | | 56,786 | |
| Cash and cash equivalents and restricted cash, beginning of period | 536,747 | | | 382,971 | | | 326,185 | |
| Cash and cash equivalents and restricted cash, end of period | $ | 936,716 | | | $ | 536,747 | | | $ | 382,971 | |
| Supplemental disclosure of cash flow information: | | | | | |
| Cash paid during the period: | | | | | |
| Interest paid | $ | 26,706 | | | $ | 22,928 | | | $ | 26,739 | |
| Income tax paid (received), net | (32,462) | | | 46,700 | | | 16,218 | |
| Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
| Payments for operating leases | 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 | (1,526) | | | 3,123 | | | 17,771 | |
| 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) | | | — | | | — | |
The accompanying notes are an integral part of these consolidated financial statements.
2021 FORM 10-K|65
| | | | | | | | | | | | | | |
| HELMERICH & PAYNE, INC. |
| NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |
NOTE 1 NATURE OF OPERATIONS
| | | | | | | | | | | | | | |
| NOTE 1 NATURE OF OPERATIONS |
Helmerich & Payne, Inc. (which,(“H&P,” which, together with its subsidiaries, is identified as the “Company,” “we,” “us,” or “our,” except where stated or the context requires otherwise) through its operating subsidiaries provides performance-driven drilling servicessolutions and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies.
Our global contract drilling business is composed of threeservices operations are organized into the following reportable operating business segments: U.S. Land,North America Solutions, Offshore Gulf of Mexico and International Land. During the fiscal year ended September 30, 2018,Solutions. Our real estate operations, our U.S. Landincubator program for new research and development projects and our wholly-owned captive insurance companies are included in "Other." Refer to Note 17—Business Segments and Geographic Information for further details on our reportable segments.
Our North America Solutions operations
wereare primarily located in Colorado, Louisiana,
Ohio, Oklahoma,Montana, Nevada, New Mexico, North Dakota,
Ohio, Oklahoma, Pennsylvania, Texas, Utah, West Virginia and Wyoming.
OurAdditionally, Offshore
Gulf of Mexico operations
wereare conducted
in Louisiana and in U.S. federal waters in the Gulf of
Mexico. OurMexico and our International
LandSolutions operations
hadhave rigs
primarily located in
five4 international
locations during fiscal year 2018:locations: Argentina, Bahrain, Colombia
Ecuador and United Arab
Emirates (“U.A.E.”). Additionally, we focus on research and development of technology designed to improve the efficiency and accuracy of drilling operations. Emirates.
We also own develop and operate a limited number of commercial real estate properties.properties located in Tulsa, Oklahoma. Our real estate investments which are located exclusively within Tulsa, Oklahoma, include a shopping center multi-tenant industrial warehouse properties, and undeveloped real estate.
Fiscal Year 2020 Dispositions
In December 2019, we closed on the sale of a wholly-owned subsidiary of Helmerich & Payne International Drilling Co. ("HPIDC"), TerraVici Drilling Solutions, Inc. ("TerraVici"). As a result of the sale, 100% of TerraVici's outstanding capital stock was transferred to the purchaser in exchange for approximately $15.1 million, resulting in a total gain on the sale of TerraVici of approximately $15.0 million. Prior to the sale, TerraVici was a component of the North America Solutions operating segment. This transaction did not represent a strategic shift in our operations and will not have a significant effect on our operations and financial results going forward.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, RISKS AND UNCERTAINTIES
| | | | | | | | | | | | | | |
| NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, RISKS AND UNCERTAINTIES |
The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
We classified our former Venezuelan operation as a discontinued operation in the third quarter of fiscal year 2010, as more fully described in Note
4—3—Discontinued Operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates only to our continuing operations.
Principles of Consolidation
The consolidated financial statements include the accounts of Helmerich & Payne, Inc. and its domestic and foreign subsidiaries. Consolidation of a subsidiary begins when the Company
obtainsgains control over the subsidiary and ceases when the Company loses control of the subsidiary. Specifically, income and expenses of a subsidiary acquired or disposed of during the fiscal year are included in the
consolidated statementConsolidated Statements of
profit or lossOperations and
other comprehensive incomeComprehensive Loss from the date the Company gains control until the date when the Company ceases to control the subsidiary. All
significant intercompany accounts and transactions have been eliminated in consolidation.
2021 FORM 10-K|66
COVID-19 and OPEC+ Production Impacts
The outbreak of a novel strain of coronavirus (“COVID-19”) and its development into a pandemic has resulted in significant global economic disruption, including North America and many of the other geographic areas where we operate, or where our customers are located, or suppliers or vendors operate. Actions taken to prevent the spread of COVID-19 by governmental authorities around the world, including imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of such facilities and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions, have significantly reduced global economic activity, thereby resulting in lower demand for crude oil. In addition to the impact on demand for crude oil, the travel restrictions in certain countries where we operate, including the closure of their borders to travel into the country, have resulted in an inability to effectively staff or rotate personnel at, and thereby operate, certain of our rigs and could lead to an inability to fulfill our contractual obligations under contracts with customers. Governmental authorities have also implemented multi-step policies with the goal of reopening various sectors of the economy. However, certain jurisdictions began reopening only to return to restrictions in the face of increases in new COVID-19 cases, while other jurisdictions are continuing to reopen or have completed the reopening process despite increases in COVID-19 cases. Despite the increased availability of vaccines in certain jurisdictions, the COVID-19 pandemic may continue unabated or worsen during the upcoming months, including as a result of the emergence of more infectious strains of the virus, vaccine hesitancy or increased business and social activities, which may cause governmental authorities to reconsider restrictions on business and social activities. In the event governmental authorities increase restrictions, the reopening of the economy may be curtailed. We have experienced, and expect to continue to experience, some disruptions to our business operations, as these restrictions have significantly impacted, and may continue to impact, many sectors of the economy. Depressed economic conditions exacerbated by COVID-19 restrictions in one foreign jurisdiction where we operate have led to an increase in community strikes which have resulted in periodic suspensions of our operations. In addition, the perceived risk of infection and health risk associated with COVID-19, and the illness of many individuals across the globe, has and will continue to alter behaviors of consumers and policies of companies around the world; such altered behaviors and policies have many of the same effects intended by governmental authorities to stop the spread of COVID-19, such as self-imposed or voluntary social distancing, quarantining, and remote work policies. We are complying with local governmental jurisdiction policies and procedures where our operations reside. In some cases, policies and procedures are more stringent in our foreign operations than in our North America operations.
In early March 2020, the increase in crude oil supply resulting from production escalations from the Organization of the Petroleum Exporting Countries and other oil producing nations (“OPEC+”) combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Consequently, we saw a significant decrease in customer 2020 capital budgets and a corresponding dramatic decline in the demand for land rigs. Although OPEC+ agreed in April 2020 to cut oil production, OPEC+ has been gradually reducing such cuts and in July 2021, agreed to further reduce such cuts on a monthly basis with a goal of phasing out all production cuts towards the end of 2022. There is no assurance that the most recent OPEC+ agreement will be observed by its parties and OPEC+ may change its agreement depending upon market conditions. Although crude oil prices have recovered since March 2020, oil and natural gas prices are expected to continue to be volatile as a result of near-term production instability, the ongoing COVID-19 pandemic, changes in oil and natural gas inventories, industry demand, global and national economic performance, and the actions of OPEC+.
These events have had, and could continue to have, an adverse impact on numerous aspects of our business, financial condition and results of operations. The ultimate extent of the impact of COVID-19 on our business, financial condition and results of operations will depend largely on future developments, including the duration and spread of COVID-19 within the United States and the parts of the world in which we operate and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the development, availability, timely distribution and acceptance of effective treatments and vaccines worldwide, all of which are highly uncertain and cannot be predicted with certainty at this time.
At September 30, 2021, the Company had cash and cash equivalents and short-term investments of $1.1 billion. The 2018 Credit Facility (as defined within Note 7—Debt) has $750.0 million in aggregate availability with a maximum of $75.0 million available for use as letters of credit. As of September 30, 2021, there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. 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.
On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 4.65% unsecured senior notes due 2025 (the "2025 Notes") at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. On September 29, 2021, we issued $550.0 million aggregate principal amount of the 2.90% unsecured senior notes due 2031 (the "2031 Notes"). The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021. The 2031 Notes mature on September 29, 2031. On October 27, 2021, we redeemed all of the outstanding 2025 Notes. As a result, these notes were included in the current portion of long-term debt on our Consolidated Balance Sheets as of September 30, 2021. The associated make-whole premium and accrued interest of $58.1 million and the write off of the unamortized discount and debt issuance costs of $3.7 million will be recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 redemption. Refer to Note 7—Debt for further details.
2021 FORM 10-K|67
Our functional currency, together with all our foreign subsidiaries, is the U.S. dollar. Monetary assets and liabilities denominated in currencies other than the U.S. dollar are translated at exchange rates in effect at the end of the period, and the resulting gains and losses are recorded on our
statementConsolidated Statements of
operations.Operations. Aggregate foreign currency losses of
$4.0$5.3 million,
$7.1$8.8 million and
$9.3$8.2 million in fiscal years
2018, 20172021, 2020 and
2016,2019, respectively, are included in
directdrilling services operating
costs.expenses.
The preparation of our financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash, Cash Equivalents, and Restricted Cash
Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Our cash, cash equivalents and short-term investments are subject to potential credit risk, and certain of our cash accounts carry balances greater than the federally insured limits.
We had restricted cash and cash equivalents of $41.8$19.2 million and $39.1$48.9 million at September 30, 20182021 and 2017,2020, respectively. Of the total at September 30, 20182021 and 2017, $11.32020, $1.5 million and $9.4$3.6 million, respectively, is related to the acquisition of drilling technology companies, described in Note 3—Business Combinations, $2.0 million as of both fiscal year ends is from the initial capitalization of the captive insurance company,companies, and $28.5$17.7 million and $27.7$43.1 million, respectively, represents an additional amount management has elected to restrict for the purpose of potential insurance claims in our wholly-owned captive insurance company.companies. The restricted amounts are primarily invested in short-term money market securities. See Note 2 for changes to the presentation of
Cash, cash equivalents, and restricted cash
effective October 1, 2018.The restricted cash and cash equivalents are reflected in the balance sheetConsolidated Balance Sheets as follows:
| | | | | | | | | | | | | | | | | | | | | |
| | September 30, | | September 30, |
| | 2018 | | 2017 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | 2019 |
| Cash | | Cash | $ | 917,534 | | | $ | 487,884 | | | $ | 347,943 | |
| Restricted cash | | Restricted cash | |
Prepaid expenses and other | | $ | 39,830 | | $ | 32,439 | Prepaid expenses and other | 18,350 | | | 45,577 | | | 31,291 | |
Other assets | | $ | 2,000 | | $ | 6,695 | Other assets | 832 | | | 3,286 | | | 3,737 | |
| Total cash, cash equivalents, and restricted cash | | Total cash, cash equivalents, and restricted cash | $ | 936,716 | | | $ | 536,747 | | | $ | 382,971 | |
Accounts Receivable
Accounts receivable represents valid claims against our customers for our services rendered, net of allowances for credit losses. We perform credit evaluations of customers and do not typically require collateral in support for trade receivables. We provide an allowance for credit losses, when necessary, to cover estimated credit losses. Outstanding customer receivables are reviewed regularly for possible nonpayment indicators, and allowances for credit losses are recorded based upon management’s estimate of expected credit losses. Refer to "Allowance for Credit Losses" below and Note 15—Supplemental Balance Sheet Information for additional information.
Inventories of Materials and Supplies
Inventories are primarily replacement parts and supplies held for consumption in our drilling operations. Inventories are valued at the lower of cost or net realizable value. Cost is determined on a weighted average basis and includes the cost of materials, shipping, duties
labor and
manufacturing overhead.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.
Our reserves during fiscal years 2018 and 2017 were 5.9 percent and 6.3 percent, respectively, of the balance to provide for non-recoverable inventory costs. The reserves for excess and obsolete inventory were $9.9$29.3 million and $9.2$36.5 million for fiscal years 20182021 and 2017,2020, respectively.
We maintain investments in equity
and debt securities of certain publicly traded
and private companies.
The cost ofWe recognize our equity securities
used in determining realized gains and losses is based on the average cost basis of the security purchased. We regularly review investment securities for impairment based on criteria that
include the extent to which the investment’s carrying value exceeds its relatedhave readily determinable fair values at fair value,
the duration of the market decline and the financial strength and specific prospects of the issuer of the security. Unrealized gains are recognized in other comprehensive income. Unrealized losses that are other than temporary are recognized in earnings. See Note 2 forwith changes in
accounting for investments effective October 1, 2018.such values reflected in net income. Our equity securities without readily determinable fair values are measured at cost, less any impairments.
2021 FORM 10-K|68
Property, Plant, and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Substantially all property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets after deducting their
residualsalvage values. The amount of depreciation expense we record is dependent upon certain assumptions, including an asset’s estimated useful life, rate of consumption, and corresponding salvage value. We periodically review these assumptions and may change one or more of these assumptions. Changes in our assumptions may require us to recognize, on a prospective basis, increased or decreased depreciation expense.
We
capitalize interest on major projects during construction. Interest is capitalized based on the average interest rate on related debt. CapitalizedWe had no capitalized interest forduring fiscal years 2018, 20172021, 2020 and 2016 was $0.4 million, $0.3 million and $2.8 million, respectively.2019.
We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Changes that could prompt such an assessment include a
significant decline in revenue or cash margin per day, extended periods of low rig asset group utilization, changes in market demand for a specific asset, obsolescence, completion of specific contracts, restructuring of our drilling fleet, and/or overall general market conditions. If the review of the long-lived assets indicates that the carrying value of these assets/asset groups is more than the estimated undiscounted future cash flows projected to be realized from the use of the asset and its eventual disposal an impairment charge is made, as required, to adjust the carrying value down to the estimated fair value of the asset. The estimated fair value is determined based upon either an income approach using estimated discounted future cash flows, or a market approach. Fair value is estimated, if applicable,approach considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors.
factors, a cost approach utilizing reproduction costs new as adjusted for the asset age and condition, and/or a combination of multiple approaches.
Cash flows are estimated by management considering factors such as prospective market demand, margins, recent changes in rig technology and its effect on each rig’s marketability, any investment required to make a rig operational, suitability of rig size and make up to existing platforms, and competitive dynamics including industry utilization. Long-lived assets that are held for sale are recorded at the lower of carrying value or the fair value less costs to sell.
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price over the fair value of net assets acquired and liabilities assumed in a business combination, at the date of acquisition. Goodwill and indefinite-life intangibles areis not amortized but areis 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’s fair value is recognized, limited to the total amount of goodwill allocated to that reporting unit. The reporting unit level is defined as an operating segment or one level below an operating segment. Finite-lived intangible assets are amortized using the straight-line method over the period in which these assets contribute to our cash flows, generally estimated to be 155 to 20 years, and are evaluated for impairment in accordance with our policies for valuation of long-lived assets. Drilling Revenues
Contract drilling
Drilling services revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment.
For certain contracts,Revenues associated with mobilization
payments received,and lump-sum 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 years
2018, 20172021, 2020 and
20162019 were
$274.7$148.0 million,
$179.9$212.0 million and
$125.9$322.8 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 from early terminated contracts are recognized when all contractual requirements have been met. Early termination revenue for fiscal years
2018, 20172021, 2020 and
20162019 was approximately
$17.1$7.7 million,
$29.4$73.4 million and
$219.0$11.3 million, respectively.
We enter into leases with tenants in our rental properties consisting primarily of retail and multi-tenant warehouse space. The lease terms of tenants occupying space in the retail centers and warehouse buildings generally range from three to ten years. Minimum rents are recognized on a straight-line basis over the term of the related leases. Overage and percentage rents are based on tenants’ sales volume. Recoveries from tenants for property taxes and operating expenses are recognized in other operating revenues in the Consolidated Statements of Operations. 2021 FORM 10-K|69
Our rent revenues are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, | | Year Ended September 30, |
| | 2018 | | 2017 | | 2016 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | 2019 |
Minimum rents | | $ | 9,950 | | $ | 9,735 | | $ | 9,196 | Minimum rents | $ | 5,589 | | | $ | 9,245 | | | $ | 10,168 | |
Overage and percentage rents | | $ | 1,040 | | $ | 936 | | $ | 1,211 | Overage and percentage rents | 726 | | | 656 | | | 932 | |
At September 30, 2018,2021, minimum future rental income to be received on noncancelable operating leases was as follows:
| | | | | | | | |
Fiscal Year | | Amount | Fiscal Year | Amount
(in thousands) |
| | (in thousands) | |
2019 | | $ | 7,709 | |
2020 | | | 6,314 | |
2021 | | | 4,473 | |
2022 | | | 2,488 | 2022 | $ | 5,429 | |
2023 | | | 1,725 | 2023 | 4,630 | |
| 2024 | | 2024 | 3,903 | |
| 2025 | | 2025 | 3,128 | |
| 2026 | | 2026 | 2,236 | |
Thereafter | | | 4,868 | Thereafter | 4,064 | |
Total | | $ | 27,577 | Total | $ | 23,390 | |
Leasehold improvement allowances are capitalized and amortized over the lease term.
At September 30, 20182021 and 2017,2020, the cost and accumulated depreciation for real estate properties were as follows:
| | | | | | | | | | | | | | | | |
| | September 30, | | September 30, |
| | 2018 | | 2017 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 |
Real estate properties | | $ | 69,133 | | $ | 66,005 | Real estate properties | $ | 43,302 | | | $ | 43,389 | |
Accumulated depreciation | | | (42,272) | | | (42,169) | Accumulated depreciation | (28,846) | | | (27,588) | |
| | $ | 26,861 | | $ | 23,836 | | $ | 14,456 | | | $ | 15,801 | |
Current income tax expense is the amount of income taxes expected to be payable for the current fiscal year. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities.
We
provide fortake tax positions in our tax returns from time to time that may not ultimately be allowed by the relevant taxing authority. When we take such positions, we evaluate the likelihood of sustaining those positions and determine the amount of tax benefit arising from such positions, if any, that should be recognized in our financial statements. We recognize uncertain tax positions
when suchwe believe have a greater than 50 percent likelihood of being sustained. Tax benefits not recognized by us are recorded as a liability for unrecognized tax benefits, which represents our potential future obligation to various taxing authorities if the tax positions
doare not
meet the recognition thresholds or measurement standards prescribed in Accounting Standards Codification (“ASC”) 740, Income Taxes, which is more fully discussed insustained. See Note 8—Income Taxes. Amounts for uncertain tax positions are adjusted in periods when new information becomes available or when positions are effectively settled. We recognize accrued interest related to unrecognized tax benefits in interest expense and penalties in other expense in the Consolidated Statements of Operations.Earnings per Common Share
Basic earnings per share is computed utilizing the two-class method and is calculated based on the weighted-average number of common shares outstanding during the periods presented. Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options, and nonvested restricted stock.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 ASCAccounting Standards Codification ("ASC") 260, Earnings Per Share. As such, we have included these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method.share.
Stock-based compensation expense is determined using a fair-value-based measurement method for all awards granted. In computingBeginning in fiscal year 2019, we replaced stock options with performance share units as a component of our executives’ long-term equity incentive compensation. We have also eliminated stock options as an element of our non-employee director compensation program. The Board of Directors (the "Board") has determined to award stock-based compensation to non-employee directors solely in the impact, theform of restricted stock.
2021 FORM 10-K|70
The grant date fair value of each optionperformance share units is estimated ondetermined through the dateuse of grant based on the Black-Scholes options-pricing model utilizingMonte Carlo simulation method. The Monte Carlo simulation method requires the use of highly subjective assumptions. Our key assumptions for ain the method include the price and the expected volatility of our stock and our self-determined peer group of companies’ (the "Peer Group") stock, risk free interest rate volatility,of return, dividend yieldyields and cross-correlations between the Company and our Peer Group.
expected remaining term of the awards. The assumptions used in calculating the fair value of stock-based payment awards represent management’s best estimates, but these estimates involve inherent uncertainties and the application of management judgment. Stock-based compensation is recognized on a straight-line basis over the requisite service periods of the stock awards, which is generally the vesting period. Compensation expense related to stock options is recorded as a component of drilling services operating expenses, research and development expenses and selling, general and administrative expenses in the Consolidated Statements of Operations.
See Note 11—Stock-based Compensation for additional discussion on stock-based compensation.
Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to additional paid-in capital using the average-cost method.
Treasury stock may be issued under the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan.
Comprehensive Income or Loss
Other comprehensive income or loss refers to revenues, expenses, gains, and losses that are included in comprehensive income or loss but excluded from net income or loss. We report the components of other comprehensive income or loss, net of tax, by their nature and disclose the tax effect allocated to each component in the Consolidated Statements of Comprehensive Income (Loss).
We lease office spacevarious offices, warehouses, equipment and vehicles. Rental contracts are typically made for fixed periods of one to 15 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not impose any covenants, but leased assets may not be used as security for borrowing purposes.
Up until the end of fiscal year 2019, leases of property, plant and equipment for use in operations. Leases are evaluated at inception or upon any subsequent material modification and, depending on the lease terms, arewere classified as either capital leases or operating leases as appropriateleases. Payments made under ASC 840, Leases. For operating leases that contain built-in pre-determined rent escalations, rent(net of any incentives received from the lessor) were charged to the income statement on a straight-line basis over the period of the lease (“levelized lease cost”).
Beginning October 1, 2019, leases are recognized as a right-of-use asset and a corresponding liability within accrued liabilities and other non-current liabilities at the date at which the leased asset is available for use by the Company. Operating lease expense is recognized on a straight-line basis over the life of the lease. Leasehold improvements are capitalized and amortizedThe right-of-use asset is depreciated over the shorter of the asset's useful life and the lease term. We do notterm on a straight-line basis for finance type leases.
Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:
•Fixed payments (including in-substance fixed payments), less any lease incentives receivable
•Variable lease payments that are based on an index or a rate
•Amounts expected to be payable by the lessee under residual value guarantees
•The exercise price of a purchase option if the lessee is reasonably certain to exercise that option, and
•Payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option.
The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, our incremental borrowing rate is used, which is the rate that we would have
significant capital leases.to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions. Right-of-use assets are measured at cost and are comprised of the following:
•The amount of the initial measurement of lease liability•Any lease payments made at or before the commencement date less any lease incentives received
•Any initial direct costs, and
•Asset retirement obligations related to that lease, as applicable.
2021 FORM 10-K|71
Payments associated with short-term leases and leases of low-value assets are recognized on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less. Low-value assets are comprised of IT-equipment and office furniture.
In determining the lease term, management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. Extension options (or periods after termination options) are only included in the lease term if the lease is reasonably certain to be extended (or not terminated). The assessment is reviewed if a significant event or a significant change in circumstances occurs and is within our control. Refer to Note 5—Leases for additional information regarding our leases.
Recently Issued Accounting Updates
Changes to U.S. GAAP are established by the Financial Accounting Standards Board (“FASB”) in the form of Accounting
StandardStandards Updates
(“ASUs”("ASUs") to the FASB ASC. We consider the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable,
or clarifications of ASUs listed
below.below, immaterial, or already adopted by the Company.
The following tables providetable provides a brief description of recent accounting pronouncements and our analysis of the effects on our financial statements:
| | | | | | | | | | | |
Standard | Description | Date of
Adoption | Effect on the Financial
Statements or Other Significant Matters |
Recently Adopted Accounting Pronouncements |
ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
| The standard requires that all excess tax benefits and deficiencies previously recorded as additional paid-in capital be prospectively recorded in income tax expense. The adoption of this ASU could cause volatility in the effective tax rate on a quarter by quarter basis due primarily to fluctuations in the Company's stock price and the timing of stock option exercises and vesting of restricted share grants. The standard requires excess tax benefits to be presented as an operating activity on the statement of cash flows rather than as a financing activity. Excess tax benefits and deficiencies are recorded within the provision for income taxes within the Consolidated Statements of Operationson a prospective basis as required by the standard. The standard also requires taxes paid for employee withholdings to be presented as a financing activity on the statement of cash flows.
| October 1, 2017
| We adopted this ASU during the first quarter of fiscal year 2018. We elected to present changes to the statement of cash flows on a retrospective basis as allowed by the standard in order to maintain comparability between fiscal years. As such, prior period cash flows from operations for the fiscal years ended September 30, 2017 and 2016 have been adjusted to reflect an increase of $4.4 million and $0.9 million, respectively, with a corresponding decrease to cash flows used in financing activities, compared to amounts previously reported. The standard also requires taxes paid for employee withholdings to be presented as a financing activity on the statement of cash flows but this requirement had no impact on our total financing activities as this has been the practice historically. We also elected to account for forfeitures of awards as they occur, instead of estimating a forfeiture amount. On October 1, 2017, we recorded a $0.3 million cumulative-effect adjustment to retained earnings for the differential between the amount of compensation cost previously recorded and the amount that would have been recorded without assuming forfeitures.
|
ASU No. 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern
| The new guidance requires management to assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Disclosures are required when conditions give rise to substantial doubt. Substantial doubt is deemed to exist when it is probable that the company will be unable to meet its obligations within one year from the financial statement issuance date.
| September 30, 2017
| We adopted ASU No. 2014-15, as required, on September 30, 2017 with no impact on our consolidated financial statements and disclosures.
|
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.
| October 1, 2017
| We adopted this ASU during the first quarter of fiscal year 2018. There was no impact on our consolidated financial statements.
|
ASU No. 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
| The new guidance eliminates the requirement to calculate the implied fair value of goodwill (i.e., Step 2 of today’s goodwill impairment test) to measure a goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (i.e., measure the charge based on today’s Step 1).
| June 30, 2017
| As permitted, we early adopted this guidance effective June 30, 2017, with no impact on our consolidated financial statements.
|
Standards that are not yet adopted as of September 30, 2018
|
ASU No. 2018-14, Compensation – Retirement Benefits – Defined Benefit Plans—General (Topic 715-20): Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans
| This ASU amends ASC 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans.
| October 1, 2021
| We are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures.
|
ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement
| This ASU eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of its disclosure framework project, where entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose the range and weighted average used to develop significant unobservable inputs for Level 3 fair value measurements.
| October 1, 2020
| We are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures.
|
ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220) Reclassification of Certain Tax Effects From Accumulated Other Comprehensive Income
| This ASU relates to the impacts of the tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Reform Act”). The guidance permits the reclassification of certain income tax effects of the Tax Reform Act from Other Comprehensive Income to Retained Earnings. The guidance also requires certain new disclosures. This update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal periods and early adoption is permitted. Entities may adopt the guidance using one of two transition methods; retrospective to each period (or periods) in which the income tax effects of the Tax Reform Act related to the items remaining in Other Comprehensive Income are recognized or at the beginning of the period of adoption.
| October 1, 2019
| We are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures.
|
ASU No. 2017-09, Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting
| Under the new guidance, modification accounting is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. Regardless of whether the change to the terms or conditions of the award requires modification accounting, the existing disclosure requirements and other aspects of U.S. GAAP associated with modification, such as earnings per share, continue to apply.
| October 1, 2018
| We do not expect the new guidance to have a material impact on our consolidated financial statements.
|
ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
| The ASU will change how employers that sponsor defined benefit pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Employers will present the other components of the net periodic benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income, if one is presented.
| October 1, 2018
| We do not expect the new guidance to have a material impact on our consolidated financial statements.
|
ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash
| The ASU requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows.
| October 1, 2018
| We will adopt the guidance retrospectively to all periods presented prior to the adoption date (October 1, 2018) by excluding the change in restricted cash balances from cash flows from operating activities. The impact of which will be an increase in the cash flows from operating activities in the fiscal years 2018 and 2017 by $2.7 million and $9.5 million, respectively.
|
ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
| Under current U.S. GAAP, the tax effects of intra-entity asset transfers (intercompany sales) are deferred until the transferred asset is sold to a third party or otherwise recovered through use. This is an exception to the principle in ASC 740, Income Taxes, that generally requires comprehensive recognition of current and deferred income taxes. The new guidance eliminates the exception for all intra-entity sales of assets other than inventory. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller's tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer's jurisdiction would also be recognized at the time of the transfer. The new guidance does not apply to intra-entity transfers of inventory. The income tax consequences from the sale of inventory from one member of a consolidated entity to another will continue to be deferred until the inventory is sold to a third party.
| October 1, 2018
| We do not expect the new guidance to have a material impact on our consolidated financial statements.
|
ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments
| The ASU is intended to reduce diversity in practice in presentation and classification of certain cash receipts and cash payments by providing guidance on eight specific cash flow issues. The ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period.
| October 1, 2018
| We plan to adopt this standard retrospectively to all periods presented. We are currently assessing the impact this standard will have on our consolidated statements of cash flows.
|
ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326) and related ASUs issued subsequent | This ASU introduces a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. The new model will apply to: (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and other financial assets measured at fair value through other comprehensive income/income (loss), and (4) beneficial interests in securitized financial assets. This update is effective for annual periods beginning after December 15, 2019. | October 1, 2020 | We adopted this ASU during the first quarter of fiscal year 2021, as required. Refer to "Allowance for Credit Losses" below for additional information. |
| ASU No. 2018-14, Compensation – Retirement Benefits – Defined Benefit Plans—General (Topic 715-20): Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans | This ASU amends ASC 715 to add, remove, and clarify disclosure requirements related to defined benefit, pension and other postretirement plans. This update is effective for annual periods ending after December 15, 2020. | September 30, 2021 | We adopted this ASU during the fourth quarter of fiscal year 2021. 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, 2021 |
| 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, 2019.2020. 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. The update is effective for annual periods beginning after December 15, 2020. | October 1, 2020 2021 | We plan to adopt this ASU, as required, in the first quarter of fiscal year 2022. Although we are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures. disclosures, we do not believe the adoption will have a material effect thereon. |
70
2021 FORM 10-K|72
ASU No. 2016-02, Leases (Topic 842)
| ASU 2016-02 will require organizations that lease assets — referred to as “lessees” — to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. Under ASU 2016-02, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Lessor accounting remains substantially similar to current U.S. GAAP. In addition, disclosures of leasing activities are to be expanded to include qualitative along with specific quantitative information. For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-02 mandates a modified retrospective transition method with an option to use certain practical expedients.
| October 1, 2019
| We are currently evaluating the potential impact of adopting this guidance on our consolidated financial statements and disclosures.
|
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.
| 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. The cumulative catch up impact for the October 1, 2018 implementation will be a reclassification of $44 million, cumulative gains related to our available-for-sale securities, currently recorded in the beginning balance of the accumulated other comprehensive income, to beginning balance of retained earnings at October 1, 2018.
|
ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606): Revenue from Contracts with Customers
| In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The update outlines a single comprehensive model for companies to use in accounting for revenue arising from contracts with customers and supersedes the most current revenue recognition guidance, including industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue when promised goods or services are transferred to customers in an amount that reflects the consideration to which the entity expects to be entitled for those goods or services. The update also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. Furthermore, as part of Topic 606, the FASB introduced ASC 340-40 Other Assets and Deferred Costs, which provides guidance on the capitalization of contract related costs that are not within the scope of other authoritative literature. The update will be effective for fiscal reporting periods beginning after December 15, 2017, including interim periods within the reporting period. Companies may use either a full retrospective or a modified retrospective approach to adopt the updates.
| October 1, 2018
| We intend to adopt the new guidance using the modified retrospective approach. In preparation for our adoption of the new standard, we have evaluated representative samples of contracts and other forms of agreements with our customers based upon the five-step model specified by the new guidance. We have completed a preliminary assessment of the of the potential impact the implementation of this new guidance will have on our financial statements. Although our preliminary assessment may change based upon completion of our evaluation, the following summarizes the more significant impacts expected from the adoption of the new standard:
·
Certain revenues currently recognized at a point in time, are expected to be recognized over the term of the contract.·
Certain associated costs to fulfill these contracts that are currently being expensed at a point in time, are expected to be capitalized as a contract fulfillment cost and amortized over the contract term, including expected contract extensions.·
Enhance our disclosures to provide additional information relating to disaggregated revenue, contract assets and liabilities and remaining performance obligations. |
On October 1, 2020, we adopted ASU 2016-13 on a modified retrospective basis through a cumulative-effect adjustment without restating comparative periods, as permitted under the adoption provisions. Upon adoption, we recognized a $1.6 million increase to our allowance for credit losses and a corresponding cumulative adjustment to reduce retained earnings, net of income taxes, of $1.3 million. This transition adjustment reflects the development of our models to estimate expected credit losses over the life of our financial assets, which primarily consist of our accounts receivable. Pursuant to ASU 2016-13, we have evaluated our customers’ financial strength and liquidity based on aging of accounts receivable, payment history, and other relevant information, including ratings agency, credit ratings and alerts, and publicly available reports. Concentration of Credit Risk
Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of temporary cash investments, short-term investments and trade receivables. The industry concentration has the potential to impact our overall exposure to market and credit risks, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base.
We had revenues from In fiscal years 2021, 2020 and 2019, no individual customers related to our U.S. Land segment, that constituted 10 percent or more of our total revenues as follows:
consolidated revenues. | | | | | | | | | |
(In thousands) | 2018 | | 2017 | | 2016 |
EOG Resources, Inc. | $ | 258,194 | | $ | 163,582 | | $ | 124,262 | |
In addition, we have certain customers that make up a significant portion of our Accounts Receivable at September 30, 2018, as indicated in the table below:
| | |
| Percentage of
|
| Accounts Receivable
|
EOG Resources, Inc.
| 8.8
| %
|
Occidental Oil and Gas Corporation
| 4.7
| %
|
We place temporary cash investments in the U.S.United States with established financial institutions and invest in a diversified portfolio of highly rated, short-term money market instruments. Our trade receivables, primarily with established companies in the oil and gas industry, may impact credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. International sales also present various risks including governmental activities that may limit or disrupt markets and restrict the movement of funds. Most of our international sales, however, are to large international or government-owned national oil companies. 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.
Our operations can be materially affected by oil and gas prices. Oil and natural gas prices have been historically volatile and difficult to predict with any degree of certainty. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining a customer’s future spending levels. This volatility, along with the difficulty in predicting future prices, can lead many exploration and production companies to base their capital spending on more conservative estimates of commodity prices. As a result, demand for
contract drilling services is not always purely a function of the movement of commodity prices.
In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets may cause difficulty for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in a reduction in customer spending and the demand for our services. This reduction in spending could have a material adverse effect on our operations.
We have accrued a liability for estimated workers’ compensation and other casualty claims incurred based upon
cashcase reserves plus an estimate of loss development and incurred but not reported claims. The estimate is based upon historical trends. Insurance recoveries related to such liability are recorded when considered probable.
We self-insure a significant portion of expected losses relating to workers’ compensation, general liability and automobile liability. Generally, deductibles range from $1 million to $5$10 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates are recorded for incurred outstanding liabilities for workers’ compensation, general, and automobile liability claims and claims that are incurred but not reported. Estimates are based on adjusters’ estimates, historic
historical experience and statistical methods commonly used within the insurance industry that we believe are reliable. We have also engaged ana third-party actuary to perform a review of our domestic casualty losses.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.
2021 FORM 10-K|73
On October 1, 2019, we elected to capitalize a new Captive insurance company to insure the deductibles for our domestic workers’ compensation, general liability and automobile liability claims programs, and to continue the practice of insuring deductibles from the Company's international casualty and rig property programs. Casualty claims occurring prior to October 1, 2019 will remain recorded within each of the operating segments and future adjustments to these claims will continue to be reflected within the operating segments. Reserves for legacy claims occurring prior to October 1, 2019, will remain as liabilities in our operating segments until they have been resolved. Changes in those reserves will be reflected in segment earnings as they occur. We will continue to utilize the Captives to finance the risk of loss to equipment and rig property assets. The Company and the Captives maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of significant events covered under these programs. Our operating subsidiaries are paying premiums to the Captives, typically on a monthly basis, for the estimated losses based on an 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. Direct operating costs consisted primarily of adjustments to accruals for estimated losses of $12.6 million and $16.4 million allocated to the Captives and rig and casualty insurance premiums of $21.9 million and $6.7 million during the fiscal years ended September 30, 2021 and 2020, respectively. These operating costs were recorded within drilling services operating expenses in our Consolidated Statement of Operations. Intercompany premium revenues recorded by the Captives during the fiscal years ended September 30, 2021 and 2020 amounted to $35.4 million and $36.9 million, respectively, which were eliminated upon consolidation. These intercompany insurance premiums are reflected as segment operating expenses within the North America Solutions, Offshore Gulf of Mexico, and International LandSolutions reportable operating segments and are reflected as intersegment sales within "Other." The Company self-insures employee health plan exposures in excess of employee deductibles. Starting in the second quarter of fiscal year 2020, the Captives insurer issued a stop-loss program that will reimburse the Company's health plan for claims that exceed $50,000. This program will also be reviewed at the end of each policy year by an outside actuary. Our medical stop loss operating expenses for the fiscal year ended September 30, 2021 and 2020 were $12.0 million and $8.0 million, respectively.
International Solutions Drilling
OperationsRisks
International LandSolutions drilling operations may significantly contribute to our revenues and net operating income.income (loss). 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 landInternational Solutions operations will be subject to numerous contingencies, some of which are beyond management’s control. These contingencies include general and regional economic conditions, fluctuations in currency exchange rates, modified exchange controls, changes in international regulatory requirements and international employment issues, risk of expropriation of real and personal property and the burden of complying with foreign laws. Additionally, in the event that extended labor strikes occur or a country experiences significant political, economic or social instability, we could experience shortages in labor and/or material and supplies necessary to operate some of our drilling rigs, thereby potentially causing an adverse material effect on our business, financial condition and results of operations.
We have also experienced certain risks related to our Argentine operations. In Argentina, while our dayrate is denominated in U.S. dollars, we are paid in Argentine pesos. The Argentine branch of one of our second-tier subsidiaries remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars. Argentina
also has a history of implementing currency controls which restrict the conversion and repatriation of
USU.S. dollars.
From September 2019 through 2021, Argentina implemented additional currency controls in an effort to preserve Argentina's U.S. dollar reserves. As a result of these currency controls, our ability to remit funds from our Argentine subsidiary to its U.S. parent has been limited. In the past, the Argentine government has also instituted price controls on crude oil, diesel and gasoline prices and instituted an exchange rate freeze in connection with those prices. These
price controls
were notand an exchange rate freeze could be instituted again in
placethe future. In addition, in
March 2020, the Argentine government introduced labor regulations that prohibit employee dismissals or suspensions without just cause, for lack of (or reduction in) work or due to force majeure, subject to certain exceptions that may result in the payment of compensation to suspended employees and/or increased severance costs to the company. These prohibitions have resulted in significant challenges for our Argentine operations and it remains uncertain for how long they will be in effect. Further, there are additional concerns regarding Argentina's debt burden, notwithstanding Argentina's restructuring deal with international bondholders in August 2020, as Argentina
during this past fiscal year.attempts to manage its substantial sovereign debt issues. These concerns could further negatively impact Argentina's economy and adversely affect our Argentine operations. Argentina’s economy is considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period based on inflation data published by the respective governments. Nonetheless, all of our foreign subsidiaries use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations.
Because of the impact of local laws, our future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. While we believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms acceptable to us.
NOTE 3 BUSINESS COMBINATIONS
Fiscal Year 2018 Acquisitions
On December 8, 2017,
2021 FORM 10-K|74
Although we
completed an acquisition (“MagVAR Acquisition”)attempt to minimize the potential impact of
an unaffiliated company, Magnetic Variation Services, LLC (“MagVAR”), which is now a wholly-owned subsidiary of the Company. The operations for MagVAR are included with our other non-reportable business segments. At the effective time of the MagVAR Acquisition, MagVAR shareholders received aggregate cash consideration of $47.9 million, net of customary closing adjustments, and certain management members received restricted stock awards covering 213,904 shares of Helmerich & Payne, Inc. common stock. The grant date fair value of the restricted stock of $13.1 million is being amortized to expense over the three year vesting period. At closing, $6.0 million of the cash consideration was placedsuch risks by operating in
escrow, to be released to the sellers twelve months after the acquisition closing date. The amount placed in escrow is classified as restricted cash and is included in prepaid expenses and other in the Consolidated Balance Sheet at September 30, 2018. Transaction costs related to the MagVAR Acquisition incurredmore than one geographical area, during the fiscal year ended September 30,
20182021, approximately 5.0 percent of our operating revenues were
approximately $1.2 million and are recordedgenerated from international locations in
the Consolidated Statements of Operations within general and administrative expense. We recorded revenue of $11.6 million and a net loss of $3.0 million relatedour drilling services business compared to
MagVAR8.3 percent during the fiscal year ended September 30,
2018.Through comprehensive 3D geomagnetic reference modeling, MagVAR provides measurement while drilling (“MWD”) survey corrections by identifying and quantifying MWD tool measurement errors in real-time, greatly improving
directional drilling performance and wellbore placement. MagVAR technology has been successfully deployed in both onshore and offshore fields in North America, South America, Europe, Africa, Australia and Asia.
The MagVAR Acquisition was accounted for as a business combination in accordance with ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. The following table summarizes the purchase price and the fair values of assets acquired and liabilities assumed at the acquisition date (in thousands):
| | | |
Purchase Price | | | |
Consideration given | | | |
Cash consideration | | $ | 48,485 |
| | | |
Allocation of Purchase Price | | | |
Fair value of assets acquired | | | |
Current assets | | $ | 2,286 |
Property, plant and equipment | | | 13 |
Intangible assets, net | | | 28,700 |
Goodwill | | | 17,791 |
| | | |
Total assets acquired | | $ | 48,790 |
| | | |
Fair value of liabilities assumed | | | |
Current liabilities | | $ | 305 |
| | | |
Fair value of total assets acquired and liabilities assumed | | $ | 48,485 |
Intangible assets acquired consist of developed technology, a trade name and customer relationships. The intangible assets are being amortized under a straight-line method over their estimated useful lives ranging from five to 20 years.
The methodologies used in valuing the intangible assets include the multi-period excess earnings method for developed technology, the with and without method for customer relationships and the relief-from-royalty method for the trade name. The excess of the purchase price over the total net identifiable assets has been recorded as goodwill. Factors comprising goodwill include the synergies expected from the expanded service capabilities as well as the value of the assembled workforce. The goodwill is reported within our other non-reportable business segments and was allocated to our MagVAR reporting unit. The goodwill is not subject to amortization, but is evaluated at least annually for impairment in the fourth quarter of each fiscal year, or more frequently if impairment indicators are present. The intangible assets and goodwill are amortized straight-line over 15 years for income tax purposes.
The following unaudited pro forma combined financial information is provided for2020. During the fiscal year ended September 30, 2018 and 2017, as though the MagVAR Acquisition had been completed as2021, approximately 48.9 percent of October 1, 2016. These pro forma combined results ofoperating revenues from international locations were from operations have been prepared by adjusting our historical resultsin South America compared to include the historical results of MagVAR and reflect pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including application of an appropriate income tax to MagVAR’s pre-tax loss. Additionally, pro forma earnings for the fiscal year ended September 30, 2018 were adjusted to exclude $0.5 million of after-tax transaction costs. The unaudited pro forma combined financial information is provided for illustrative purposes only and is not necessarily indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this pro forma financial information.
| | | | | | |
| | Pro Forma |
| | 2018 | | 2017 |
| | (unaudited, in thousands) |
Revenues | | $ | 2,490,955 | | $ | 1,814,215 |
Net income (loss) | | $ | 480,423 | | $ | (126,355) |
Fiscal Year 2017 Acquisitions
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 within our other non-reportable business segments. At the effective time of the MOTIVE Merger, MOTIVE shareholders received aggregate cash consideration of $74.3 million, net of customary closing adjustments, and may receive up to an additional $25.0 million in potential earnout payments based on future performance. At closing, $9.4 million of the cash consideration was placed in escrow, with one-half to be released to the seller on each of the twelve and eighteen month anniversaries of the merger completion date. Transaction costs related to the MOTIVE Merger incurred during fiscal year 2017 were $3.2 million and are recorded in the Consolidated Statement of Operations within the general and administrative expense line item. We recorded revenue of $12.9 million and $3.3 million and a net loss of $20.1 million and $2.2 million related to MOTIVE during the fiscal years ended September 30, 2018 and 2017, respectively.
MOTIVE has a proprietary Bit Guidance System™ that is an algorithm-driven system that considers the total economic consequences of directional drilling decisions and is designed to consistently lower drilling costs through more efficient drilling and increase hydrocarbon production through smoother wellbores and more accurate well placement. Given our strong and longstanding technology and innovation focus, we believe the technology will continue to advance and provide further benefits for the industry.
The MOTIVE Merger was accounted for as a business combination in accordance with ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. The following table summarizes the purchase price and the allocation of the fair values of assets acquired and liabilities assumed and separately identifiable intangible assets at the acquisition date (in thousands):
| | | |
Purchase Price
| | | |
Consideration given
| | | |
| | | |
Cash consideration
| | $
| 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 assets, net
| | | 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 acquired and liabilities assumed
| | $
| 88,784 |
Contingent consideration paid during fiscal year 2018 was $10.6 million. The fair value of the contingent consideration of $11.2 million and $14.9 million at September 30, 2018 and 2017, respectively, was calculated using a Monte Carlo simulation, which evaluates numerous potential earnings and pay out scenarios and is considered a Level 3 measurement under the fair value hierarchy. The change in the fair value of the contingent consideration of $6.9 million and $0.4 million61.6 percent during the fiscal year ended September 30, 2018 and 2017, respectively, was recorded in expenses applicable to other revenues in the Consolidated Statement of Operations. The developed technology is an intangible asset that will be amortized on a straight-line basis over an estimated 15-year life. The developed technology intangible asset was valued using an income approach, considering the estimated discounted future cash flows expected to be realized over the life2020. Substantially all of the asset, which is considered a Level 3 measurement under the fair value hierarchy. Goodwill represents the residualSouth American operating revenues were from Argentina and Colombia. The future occurrence of the purchase price paid and consists largely of the synergies and economies of scale expectedone or more international events arising from the drilling technology providing more efficient drillingtypes of risks described above could have a material adverse impact on our business, financial condition and directional drilling services, the first mover advantage obtained through the acquisition and expected future developments resulting from the assembled workforce. The goodwill is reported within our other non-reportable business segments and was allocated to our MOTIVE reporting unit. The goodwill is not subject to amortization but will be evaluated at least annually for impairment in the fourth quarterresults of each fiscal year or more frequently if impairment indicators are present. The developed technology and goodwill are not deductible for income tax purposes. An associated deferred tax liability has been recorded in regards to the developed technology.
operations.NOTE 4 DISCONTINUED OPERATIONS
Current and noncurrent
| | | | | | | | | | | | | | |
| NOTE 3 DISCONTINUED OPERATIONS |
Noncurrent liabilities
from discontinued operations consist of
municipal and income taxes payable and social obligations due withinan uncertain tax liability related to the country
inof Venezuela. Expenses incurred for in-country obligations are reported as discontinued
operations.operations within our Consolidated Statements of Operations.
The activity for the fiscal year ended September 30, 20182021 was primarily due to the remeasurement of an uncertain tax liabilitiesliability as a result of the devaluation of the Venezuela Bolivar. Early in 2018, the Venezuelan government announced that it changed the existing dual-rate foreign currency exchange system by eliminating its heavily subsidized foreign exchange rate, which was 10 Bolivars per U.S.United States dollar, and relaunched an exchange system known as DICOM. The Venezuela government also established a new currency called the “Sovereign Bolivar,” which was determined by the elimination of five zeros from the old currency. The DICOM floating rate was approximately 624,181,782, 436,677, and 21,028 Bolivars per U.S.United States dollar at September 30, 2018.2021, 2020 and 2019, respectively. The DICOM floating rate mightmay not reflect the barter market exchange rates.
NOTE 5 PROPERTY, PLANT AND EQUIPMENT
| | | | | | | | | | | | | | |
| NOTE 4 PROPERTY, PLANT AND EQUIPMENT |
Property, plant and equipment as of September 30, 20182021 and 20172020 consisted of the following (in thousands):following:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Estimated Useful Lives | | September 30, 2018 | | September 30, 2017 | |
Contract drilling equipment | | 4 - 15 years | | $ | 8,442,081 | | $ | 8,197,572 | |
| (in thousands) | | (in thousands) | Estimated Useful Lives | | September 30, 2021 | | September 30, 2020 |
| Drilling services equipment | | Drilling services equipment | 4 - 15 years | | $ | 6,229,011 | | | 7,313,234 | |
| Tubulars | | Tubulars | 4 years | | 573,900 | | | 615,281 | |
Real estate properties | | 10 - 45 years | | | 68,888 | | | 66,005 | Real estate properties | 10 - 45 years | | 43,302 | | | 43,389 | |
Other | | 2 - 23 years | | | 471,310 | | | 450,031 | Other | 2 - 23 years | | 459,741 | | | 464,704 | |
Construction in progress | | | | | 163,968 | | | 169,326 | |
Construction in progress1 | | Construction in progress1 | | 47,587 | | | 49,592 | |
| | | | | 9,146,247 | | | 8,882,934 | | 7,353,541 | | | 8,486,200 | |
Accumulated depreciation | | | | | (4,288,865) | | | (3,881,883) | Accumulated depreciation | | (4,226,254) | | | (4,839,859) | |
Property, plant and equipment, net | | | | $ | 4,857,382 | | $ | 5,001,051 | Property, plant and equipment, net | | $ | 3,127,287 | | | $ | 3,646,341 | |
| | Assets held-for-sale | | Assets held-for-sale | | $ | 71,453 | | | $ | — | |
(1)Included in construction in progress are costs for projects in progress to upgrade or refurbish certain rigs in our existing fleet. Additionally, we include other capital maintenance purchase-orders that are open/in process. As these various projects are completed, the costs are then classified to their appropriate useful life category.
Impairments
- Fiscal Year 2020
Consistent with our policy, we evaluate our drilling rigs and related equipment for impairment whenever events or changes in circumstances indicate the carrying value of these assets may exceed the estimated undiscounted future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessment on the future marketability of specific rigs’ asset group. Given
During the continued low utilization withinsecond quarter of fiscal year 2020, several significant economic events took place that severely impacted the current demand on drilling services, including the significant drop in crude oil prices caused by OPEC+'s price war coupled with the decrease in the demand due to the COVID-19 pandemic. To maintain a competitive edge in a challenging market, the Company’s management introduced a new strategy focused on operating various types of highly capable upgraded rigs and phasing out the older, less capable fleet. This resulted in grouping the super-spec rigs of our International FlexRig4legacy Domestic FlexRig® 3 asset group and two of our domesticFlexRig® 5 asset group creating a new "Domestic super-spec FlexRig®" asset group, while combining the legacy Domestic conventional asset group, FlexRig® 4 asset group and international conventional rigs’FlexRig® 3 non-super-spec rigs into one asset group (Domestic non-super-spec asset group). Given the current and projected low utilization for our Domestic non-super-spec asset group and all International asset groups, together with the continued delivery of new, more capable rigs, we considered these economic factors to be indicators that these asset groups may potentially be impaired.At September 30, 2018,
2021 FORM 10-K|75
As a result of these indicators, we performed impairment testing at March 31, 2020 on each of our Domestic non super-spec and International FlexRig4conventional, FlexRig® 3, and FlexRig® 4 asset group,groups, which hashad an aggregate net book value of $63.0$605.8 million. We concluded that the net book value of the drilling rigs’each asset group is not recoverable through estimated undiscounted cash flows withand recorded a surplus. non-cash impairment charge of $441.4 million in the Consolidated Statement of Operations for the fiscal year ended September 30, 2020. Of the $441.4 million total impairment charge recorded, $292.4 million and $149.0 million was recorded in the North America Solutions and International Solutions segments, respectively. No further impairments were recognized in fiscal year 2020. Impairment was measured as the amount by which the net book value of each asset group exceeds its fair value.
The most significant assumptions used in our undiscounted cash flow model include:include timing on awards of future drilling contracts, oil prices, operating dayrates, operating costs, rig reactivation costs, drilling rig utilization, revenue efficiency, estimated remaining economic useful life, and net proceeds received upon future sale/disposition. The assumptions are consistent with the Company’s internal budgets and forecasts for future years. These significant assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts.Although we believe
In determining the
assumptions used in our analysis are reasonable and appropriate and thefair value of each asset group,
weighted averagewe utilized a combination of
expected future undiscounted net cash flows exceeds the net book value of the asset group as of the fiscal year 2018 year-end impairment evaluation, different assumptionsincome and
estimates could materially impact the analysis and our resulting conclusion.At September 30, 2018, we engaged a third party independent accounting firm who performed a market valuation, utilizing the market approach, on two of our domestic and international conventional rigs’ asset groups, which have an aggregate net book values of $9.0 million and $15.2 million, respectively. We concluded that the fair values of these two asset groups exceed the net book values by approximately 64 percent and 141 percent, respectively, and as such, no impairment was recorded.approaches. The significant assumptions in the valuation exerciseare based on those of a market participant and are classified as Level 2 and Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures.
During
As of March 31, 2020, the fourth quarterCompany also recorded an additional non-cash impairment charge related to in-progress drilling equipment and rotational inventory of fiscal year 2018, after ceasing operations in Ecuador, we entered into a sales negotiation with respect to the six conventional rigs, within a separate international conventional rigs’ asset group, with net$44.9 million and $38.6 million, respectively, which had aggregate book values of $20.8$68.4 million presentand $38.6 million, respectively, in the country, pursuant to which the rigs, together with associated equipment and machinery would be sold to a third party to be recycled. Certain components of these rigs, with an $8.5 million net book
value, that are not subject to the sale agreement, will be transferred to the United States to be utilized on other FlexRigs with high activity and demand. The sales transaction was completed in November 2018. We recorded a non-cash impairment charge within our International Land segment of $9.2 million ($7.0 million, net of tax, or $0.06 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018. As a result,2020. Of the remaining rig within the same asset group, not to be disposed of, was written down resulting in an additional$83.5 million total impairment charge of $1.4recorded for in-progress drilling equipment and rotational inventory, $75.8 million ($1.0and $7.7 million net of tax, or $0.01 per diluted share). The assets werewas recorded at fair value based onin the sales agreementNorth America Solutions and as such are classified as Level 2 withinInternational Solutions segments, respectively.
Impairment - Fiscal Year 2019
During the
fair value hierarchy.Furthermore, during the fourththird quarter of fiscal year 2018,2019, the Company's management performed a detailed assessment, considering a number of approaches, to maximize the utilization and enhance the margins of the domestic and international FlexRig® 4 asset groups. In June 2019, this assessment concluded that marketing a smaller fleet of these two asset groups would provide the best economic outcome. As such, the decision was made to downsize the number of domestic and international FlexRig® 4 drilling rigs, to be marketed to our customers, from 71 rigs to 20 domestic rigs and from 10 rigs to 8 international rigs and utilize the major interchangeable components of the decommissioned drilling rigs within these asset groups as capital spares for all of our U.S. Land segment, management committedremaining rig fleet. This reduced the aggregate net book values of the FlexRig®4 asset groups as of June 30, 2019 from $317.8 million to $107.5 million for domestic rigs and from $55.7 million to $47.8 million for international rigs. Following the downsizing process, we performed a plandetailed study to auction several previously decommissioned rigs during fiscal year 2019. Asoptimize the quantities of capital spares and drilling support equipment required to support the future operations of our rig fleet going forward. These decisions and analysis resulted in a result, we wrote themwrite down of excess capital spares and drilling support equipment, which had an aggregate net book value of $235.3 million, to their estimated fair values. Weproceeds to ultimately be received on sale or disposal based on our historical experience with sales and disposals of similar assets, resulting in an impairment of $224.3 million, which was recorded a non-cash impairment charge of $5.7 million ($4.2 million, net of tax, or $0.04 per diluted share), which is included in Asset Impairment Charge on theour Consolidated StatementsStatement of Operations for the fiscal year ended September 30, 2018.2019. Of the $224.3 million total impairment charge recorded, $216.9 million and $7.4 million was recorded in our North America Solutions and International Solutions segments, respectively. The assets were recorded at fair value based onsignificant assumptions in the auction price and as suchvaluation are classified as Level 2 inputs by ASC Topic 820, Fair Value Measurement and Disclosures.
Due to the downsizing of our domestic and international FlexRig® 4 asset groups, at June 30, 2019, we performed impairment testing on these two asset groups. We concluded that the net book values of the fair value hierarchy.During fiscal year 2016, we recorded an asset impairment chargegroups were recoverable through estimated undiscounted cash flows with a surplus. The most significant assumptions used in our undiscounted cash flow model include timing on awards of future drilling contracts, operating dayrates, operating costs, rig reactivation costs, drilling rig utilization, estimated remaining useful life, and net proceeds received upon future sale/disposition. The assumptions are consistent with the U.S. Land segment of $6.3 million to reduce the carrying value of rig and rig related equipment classified as heldCompany's internal forecasts for sale to their estimated fair values, based on expected sales prices.
future years.
Depreciation in the Consolidated Statements of Operations of $583.8$412.5 million, $585.5$474.7 million and $598.6$556.9 million includes abandonments of $27.7$2.0 million, $42.6$4.0 million and $39.3$11.4 million for the fiscal years 2018, 20172021, 2020 and 2016,2019, respectively.
2021 FORM 10-K|76
Assets Held-for-Sale
The following table summarizes the balance (in thousands) of our assets held-for-sale at the dates indicated below:
| | | | | |
| 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 | |
In March 2021, the Company's leadership continued the execution of the current strategy, which was initially introduced in 2019, focusing on operating various types of highly capable upgraded rigs and phasing out the older, less capable fleet. As a result, the Company has undertaken 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. The book values of those assets were written down to $13.5 million, which represents their fair value less estimated cost to sell, and were reclassified as held-for-sale in the second and third quarters of fiscal year 2021. As a result, we recognized a non-cash impairment charge of $56.4 million during the fiscal year ended September 30, 2021 in the Consolidated Statement of Operations. During 2018,the fiscal year ended September 30, 2021, we have shortenedcompleted the estimated useful livessale of certain componentsa portion of rigs planned for conversion,the assets with a total net book value of $3.7$6.5 million resultingthat were originally classified as held-for-sale during the second and third quarters of fiscal year 2021.
During September 2021, the Company agreed to sell 8 FlexRig land rigs with an aggregate net book value of $55.6 million to ADNOC Drilling Company P.J.S.C. ("ADNOC Drilling") for $86.5 million. NaN of the 8 rigs were already located in an increasethe U.A.E where ADNOC Drilling is domiciled with the remaining 6 rigs to be shipped from the United States. We received the $86.5 million in depreciation expensecash consideration in advance of delivering the rigs. As part of the sales agreement, the rigs will be delivered and commissioned in stages over a twelve-month period subject to acceptance upon successful completion of final inspection on customary terms and conditions. No rigs have been delivered to ADNOC Drilling as of September 30, 2021 and, therefore, the total cash proceeds of $86.5 million is recorded in Accrued Liabilities within our Consolidated Balance Sheets as of September 30, 2021. As a result, these rigs are classified as held-for-sale in the Consolidated Balance Sheets until each rig is delivered, at which time any related gain/loss on the sale will be recognized in the Consolidated Statement of Operations. The rigs' fair value less estimated cost to sell of $29.0 million, including approximately $24.0 million of cash costs to be incurred, approximated their net book values at September 30, 2021.
During the fiscal year ended September 30, 2021, we formalized a plan to sell assets related to 2 of our lower margin service offerings, trucking and casing running services, which contributed approximately 2.8 percent to our consolidated revenue during 2018fiscal year 2021, all within our North America Solutions segment. The combined net book values of approximately $9.7 million. This will also increase the depreciation expense for the next three months by approximately $0.9these assets of $23.2 million were written down to their combined fair value less estimated cost to sell of $8.8 million, and will decreasewere reclassified as held-for-sale in the depreciation expenseConsolidated Balance Sheets as of September 30. 2021. As a result, we recognized a non-cash impairment charge of $14.4 million in the Consolidated Statement of Operations during the year ended September 30, 2021.
Subsequent to September 30, 2021, we closed on the sale of these assets in 2 separate transactions. The sale of our trucking services was completed on November 3, 2021 while the sale of our casing running services was completed on November 15, 2021 for fiscal years 2019, 2020, 2021, 2022,combined cash consideration less costs to sell of $5.8 million, in addition to the possibility of future earnout revenue.
The significant assumptions utilized in the held-for-sale valuations were based on our intended method of disposal, historical sales of similar assets, and
2023market quotes and are classified as Level 2 and Level 3 inputs by
$2.3 million, $2.3 million, $2.2 million, $1.3 million,ASC Topic 820, Fair Value Measurement and
$0.4 million, respectively,Disclosures. Although we believe the assumptions used in our analysis are reasonable and
thereafter by $1.0 million.appropriate, different assumptions and estimates could materially impact the analysis and our resulting conclusion.
We had aan aggregate gain on salessale of assets of $22.7$1.0 million, $46.8 million and $20.6$39.7 million in fiscal years 20182021, 2020 and 2017, respectively. These gains were primarily2019, respectively, which are included within Gain on Sale of Assets on the Consolidated Statement of Operations.
During the fiscal year ended September 30, 2021, we closed on the sale of an offshore platform rig within our Offshore Gulf of Mexico operating segment for total consideration of $12.0 million with an aggregate net book value of $2.8 million, resulting in a gain of $9.2 million. Additionally during the fiscal year ended September 30, 2021, we sold excess drilling equipment and spares, which resulted in a loss of $31.2 million and we also sold assets previously classified as held-for-sale, which resulted in a $3.1 million gain. Furthermore, we recognized a $14.4 million gain on asset sales related to customer reimbursement for the replacement value of drill pipe damaged or lost in drilling operations.operations during the fiscal year ended September 30, 2021.
2021 FORM 10-K|77
During the fiscal year ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including 6 industrial sites, for total consideration, net of selling related expenses, of $40.7 million and an aggregate net book value of $13.5 million, resulting in a gain of $27.2 million. Additionally, we recorded a gain of $27.0 million related to the customer reimbursement for replacement value of lost or damaged drill pipe.
During the fiscal year ended September 30, 2019, our $39.7 million gain on sale of assets was primarily related to customer reimbursement for the replacement value of lost or damaged drill pipe.
Lease Position
| | | | | | | | | | | |
| (in thousands) | September 30, 2021 | | September 30, 2020 |
Operating lease commitments, including probable extensions1 | $ | 56,667 | | | $ | 48,695 | |
| | | |
| Discounted using the lessee's incremental borrowing rate at the date of initial application | $ | 52,372 | | | $ | 46,706 | |
| (Less): short-term leases recognized on a straight-line basis as expense | $ | (1,761) | | | (1,456) | |
| (Less): Low value lease contracts | $ | (123) | | | — | |
| Lease liability recognized | $ | 50,488 | | | $ | 45,250 | |
| | | |
| Of which: | | | |
| Current lease liabilities | $ | 12,624 | | | $ | 11,364 | |
| Non-current lease liabilities | $ | 37,864 | | | 33,886 | |
(1)Our future minimal rental payments exclude optional extensions that have not been exercised but are probable to be exercised in the future, those probable extensions are included in the operating lease liability balance.
The recognized right-of-use assets relate to the following types of assets:
| | | | | | | | | | | |
| (in thousands) | September 30, 2021 | | September 30, 2020 |
| Properties | $ | 48,176 | | | $ | 42,448 | |
| Equipment | 935 | | | 1,394 | |
| Other | 76 | | | 741 | |
| Total right-of-use assets | $ | 49,187 | | | $ | 44,583 | |
Lease Costs
The following table presents certain information related to the lease costs for our operating leases:
| | | | | | | | | | | |
| Year ended September 30, |
| (in thousands) | 2021 | | 2020 |
| Operating lease cost | $ | 13,686 | | | $ | 16,953 | |
| Short-term lease cost | $ | 3,580 | | | 1,693 | |
| Total lease cost | $ | 17,266 | | | $ | 18,646 | |
Lease Terms and Discount Rates
The table below presents certain information related to the weighted average remaining lease terms and weighted average discount rates for our operating leases as of September 30, 2021.
| | | | | | | | | | | |
| September 30, 2021 | | September 30, 2020 |
| Weighted average remaining lease term | 6.7 | | 4.9 |
| Weighted average discount rate | 2.5 | % | | 2.7 | % |
2021 FORM 10-K|78
Lease Obligations
Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of one year at September 30, 2021 (in thousands) are as follows:
| | | | | |
| Fiscal Year | Amount |
| 2022 | $ | 10,596 | |
| 2023 | 8,660 | |
| 2024 | 7,391 | |
| 2025 | 4,332 | |
| 2026 | 1,876 | |
| Thereafter | 7,008 | |
Total1 | $ | 39,863 | |
(1)Our future minimal rental payments exclude optional extensions that have not been exercised but are probable to be exercised in the future, those probable extensions are included in the operating lease liability balance.
Total rent expense was $17.3 million, $18.6 million and $15.5 million for the fiscal years ended September 30, 2021, 2020 and 2019, respectively. The future minimum lease payments for our Tulsa corporate office and our Tulsa industrial facility represent a material portion of the amounts shown in the table above. The lease agreement for our Tulsa corporate office commenced on May 30, 2003 and has subsequently been amended, most recently on April 1, 2021. The agreement will expire on January 31, 2025; however, we have 2 five-year renewal options, which were not recognized as part of our right-of-use assets and lease liabilities. The lease agreement for our Tulsa industrial facility, where we perform maintenance and assembly of FlexRig® components commenced on December 21, 2018 and will expire on June 30, 2025; however, we have 2 two-year renewal options which were recognized as part of our right-of-use assets and lease liabilities.
During the fiscal year ended September 30, 2021, we downsized and relocated our Houston assembly facility to a new location. Refer to Note 18—Restructuring Charges for additional details. As a result, and during fiscal year 2021, we entered into a lease agreement for a new assembly facility located in Galena Park, Texas. This lease agreement commenced on January 1, 2021 and will expire on December 31, 2030; however, we have 1 unpriced renewal option for a minimum of five years and a maximum of 10 years, which was not recognized as part of our right-of-use assets and lease liabilities. This contract was accounted for as an operating lease resulting in an operating lease right-of-use asset of $16.0 million and minimum lease liability of $16.2 million as of September 30, 2021.
NOTE 6 GOODWILL AND INTANGIBLE ASSETS
| | | | | | | | | | | | | | |
| NOTE 6 GOODWILL AND INTANGIBLE ASSETS |
Goodwill represents the excess of the purchase price over the fair values of the assets acquired and liabilities assumed in a business combination, at the date of acquisition. Goodwill is not amortized but is tested for potential impairment at the reporting unit level, at a minimum on an annual basis, or when indications of potential impairment exist. All of our goodwill is within our other non-reportable operating segments. North America Solutions reportable segment.
The following is a summary of changes in goodwill (in thousands):
| | | |
Balance at September 30, 2016 | | $ | 4,718 |
Additions | | | 46,987 |
Balance at September 30, 2017 | | | 51,705 |
Additions (Note 3) | | | 17,791 |
Impairment | | | (4,719) |
Balance at September 30, 2018 | | $ | 64,777 |
| | | | | |
| Balance at September 30, 2019 | $ | 82,786 | |
| Additions | 1,200 | |
| Impairment | (38,333) | |
| Balance at September 30, 2020 | 45,653 | |
| Additions | — | |
| |
| Balance at September 30, 2021 | $ | 45,653 | |
During fiscal year 2020, as a result of new information identified related to the acquisition of DrillScan®, the acquisition date fair value of the contingent consideration and goodwill increased by approximately $1.2 million.
2021 FORM 10-K|79
Intangible Assets
Intangible
Finite-lived intangible assets arising from business acquisitionsare amortized using the straight-line method over the period in which these assets contribute to our cash flows and are evaluated for impairment in accordance with our policies for valuation of long-lived assets. All of our intangible assets are within our North America Solutions reportable segment. Intangible assets consisted of the following:
| | | | | | | | | | | | | | | | | | | |
| | September 30, 2018 | | September 30, 2017 | |
| | Gross | | | | | | Gross | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Carrying | | Accumulated | | | | Carrying | | Accumulated | | | | September 30, 2021 | | September 30, 2020 |
(in thousands) | | Amount | | Amortization | | Net | | Amount | | Amortization | | Net | (in thousands) | Weighted Average Estimated Useful Lives | | Gross Carrying Amount | | Accumulated Amortization | | Net | | Gross Carrying Amount | | Accumulated Amortization | | Net |
Finite-lived intangible asset: | | | | | | | | | | | | | | | | | | | Finite-lived intangible asset: | | | | | | | | | | | | | |
Developed technology | | $ | 70,000 | | $ | 5,589 | | $ | 64,411 | | $ | 51,000 | | $ | 1,134 | | $ | 49,866 | Developed technology | 15 years | | $ | 89,096 | | | $ | 22,182 | | | $ | 66,914 | | | $ | 89,096 | | | $ | 16,222 | | | $ | 72,874 | |
| Intellectual property | | Intellectual property | 13 years | | 1,500 | | | 216 | | | 1,284 | | | 1,500 | | | 103 | | | 1,397 | |
Trade name | | | 5,700 | | | 237 | | | 5,463 | | | — | | | — | | | — | Trade name | 20 years | | 5,865 | | | 1,158 | | | 4,707 | | | 5,865 | | | 842 | | | 5,023 | |
Customer relationships | | | 4,000 | | | 667 | | | 3,333 | | | — | | | — | | | — | Customer relationships | 5 years | | 4,000 | | | 3,067 | | | 933 | | | 4,000 | | | 2,267 | | | 1,733 | |
| | $ | 79,700 | | $ | 6,493 | | $ | 73,207 | | $ | 51,000 | | $ | 1,134 | | $ | 49,866 | | $ | 100,461 | | | $ | 26,623 | | | $ | 73,838 | | | $ | 100,461 | | | $ | 19,434 | | | $ | 81,027 | |
| | | | | | | | | | | | | | | | | | | |
Indefinite-lived intangible asset: | | | | | | | | | | | | | | | | | | | |
Trademark | | $ | — | | $ | — | | $ | — | | $ | 919 | | $ | — | | $ | 919 | |
| | | | | | | | | | | | | | | | | | | |
Amortization expense in the Consolidated Statements of Operations was $5.4$7.2 million, $7.2 million and $1.1$5.8 million for fiscal years 20182021, 2020 and 2017,2019, respectively, and is estimated to be $5.8 million for each of the next four succeeding fiscal years and approximately $5.1$7.2 million for fiscal year 2022, approximately $6.5 million for fiscal year 2023.Impairments
During and approximately $6.4 million
for fiscal years 2024, 2025 and 2026. Impairment - Fiscal Year 2020
Consistent with our policy, we test goodwill annually for impairment in the fourth quarter of our fiscal year, 2018,or more frequently if there are indicators that goodwill might be impaired.
Due to the market conditions described in Note 4—Property, Plant and
as partEquipment, during the second quarter of
our annualfiscal year 2020, we concluded that goodwill
impairment test, we performed a detailed assessment ofand intangible assets might be impaired and tested the
TerraViciH&P Technologies reporting unit, where
$4.7 million ofthe goodwill
was allocated. We determined thatbalance is allocated and the
estimated fair value of this reporting unit was less than its carrying amount and we recorded goodwill impairment losses of $4.7 million ($3.5 million, net of tax, or $0.03 per diluted share). In addition, we recorded an intangible assets are recorded, for recoverability. This resulted in a goodwill only non-cash impairment losscharge of $0.9$38.3 million ($0.7 million net of tax, or $0.01 per diluted share). These impairment losses are includedrecorded in Asset Impairment Charge on the Consolidated StatementsStatement of Operations forduring the fiscal year ended September 30, 2018.Our goodwill2020.
The recoverable amount of the H&P Technologies reporting unit was determined based on a fair value calculation which uses cash flow projections based on the Company's financial projections presented to the Board covering a 5-year period, and a discount rate of 14 percent. Cash flows beyond that 5-year period were extrapolated using the fifth-year data with no implied growth factor. The reporting unit level is defined as an operating segment or one level below an operating segment.
The recoverable amount of the intangible assets tested for impairment within the H&P Technologies reporting unit is determined based on undiscounted cash flow projections using the Company's financial projections presented to the Board covering a five-year period and extrapolated for the remaining weighted average useful lives of the intangible assets.
The most significant assumptions used in our cash flow model include timing of awarded future contracts, commercial pricing terms, utilization, discount rate, and the terminal value. These assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. Although we believe the assumptions used in our analysis performed onand the probability-weighted average of expected future cash flows are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and our remaining technology reporting units in the fourth quarterresulting conclusion.
2021 FORM 10-K|80
We had the following unsecured long-term debt outstanding at rates andwith maturities shown in the following table:
| | | | | | | | | | | | | | | | | | |
| | September 30, 2018 | | September 30, 2017 |
| | | | Unamortized | | | | | | Unamortized | | |
| | Face | | Debt Issuance | | Book | | Face | | Debt Issuance | | Book |
| | Amount | | Cost | | Value | | Amount | | Cost | | Value |
| | (in thousands) |
Unsecured senior notes issued March 19, 2015: | | | | | | | | | | | | | | | | | | |
Due March 19, 2025 | | $ | 500,000 | | $ | (6,032) | | $ | 493,968 | | $ | 500,000 | | $ | (7,098) | | $ | 492,902 |
| | | 500,000 | | | (6,032) | | | 493,968 | | | 500,000 | | | (7,098) | | | 492,902 |
Less long-term debt due within one year | | | — | | | — | | | — | | | — | | | — | | | — |
Long-term debt | | $ | 500,000 | | $ | (6,032) | | $ | 493,968 | | $ | 500,000 | | $ | (7,098) | | $ | 492,902 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2021 | | September 30, 2020 |
| (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 15, 20251 | $ | 487,148 | | | $ | (3,662) | | | $ | 483,486 | | | $ | 487,148 | | | $ | (6,421) | | | $ | 480,727 | |
| Due September 29, 2031 | 550,000 | | | (8,003) | | | 541,997 | | | — | | | — | | | — | |
| Total notes payable | 1,037,148 | | | (11,665) | | | 1,025,483 | | | 487,148 | | | (6,421) | | | 480,727 | |
| | | | | | | | | | | |
| Less: long-term debt due within one year | $ | (487,148) | | | 3,662 | | | (483,486) | | | — | | | — | | | — | |
| Long-term debt | $ | 550,000 | | | $ | (8,003) | | | $ | 541,997 | | | $ | 487,148 | | | $ | (6,421) | | | $ | 480,727 | |
(1) Debt was extinguished prior to maturity date. Refer to 'Senior Notes' section below.
Senior Notes
2.90% Senior Notes due 2031 On March 19, 2015,September 29, 2021, we issued $500$550.0 million aggregate principal amount of 4.65the 2.90 percent 10-year unsecured senior notes.2031 Notes in an offering to persons reasonably believed to be qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act (“Rule 144A”) and to certain non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act (“Regulation S”). Interest on the 2031 Notes is payable semi-annually on March 29 and September 29 of each year, commencing on March 29, 2022. The 2031 Notes will mature on September 29, 2031 and bear interest at a rate of 2.90 percent per annum.
The indenture governing the 2031 Notes contains certain covenants that, among other things and subject to certain exceptions, limit the ability of the Company and its subsidiaries to incur certain liens; engage in sale and lease-back transactions; and consolidate, merge or transfer all or substantially all of the assets of the Company. The indenture governing the 2031 Notes also contains customary events of default with respect to the 2031 Notes.
4.65% Senior Notes due 2025 On December 20, 2018, we issued approximately $487.1 million in aggregate principal amount of the 2025 Notes. Interest on the 2025 Notes was payable semi-annually on March 15 and September 15. The debt discount is being amortized to interest expense using the effective interest method.15 of each year, commencing on March 15, 2019. The debt issuance costs arecost was being amortized straight-line over the stated life of the obligation, which approximatesapproximated the effective interest method.
On JulySeptember 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 2025 Notes at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. The Company financed the redemption of the 2025 Notes with the net proceeds from the offering of the 2031 Notes, together with cash on hand. The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021.
On October 27, 2021, we redeemed all of the outstanding 2025 Notes. As a result, these notes were included in the current portion of long-term debt on our Consolidated Balance Sheets as of September 30, 2021. The associated make-whole premium and accrued interest of $58.1 million and the write off of the unamortized discount and debt issuance costs of $3.7 million will be recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 redemption.
Credit Facilities
On November 13, 2016,2018, we entered into a $300 millioncredit agreement by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which was amended on November 13, 2019, providing for an unsecured revolving credit facility (the “2016(as amended, the “2018 Credit Facility”), that was set to mature on November 13, 2024. On April 16, 2021, lenders with a maturity date$680.0 million of July 13, 2021. The 2016commitments under the 2018 Credit Facility hadexercised 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. The remaining $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.
2021 FORM 10-K|81
The 2018 Credit Facility has $750.0 million in aggregate availability with a maximum of $75$75.0 million available tofor use as letters of credit. The majority2018 Credit Facility also permits aggregate commitments under the facility to be increased by $300.0 million, subject to the satisfaction of anycertain conditions and the procurement of additional commitments from new or existing lenders. The borrowings under the facility would2018 Credit Facility accrue interest at a spread over either the London Interbank Offered Rate (“LIBOR”("LIBOR") or an adjusted base rate (as defined in the credit agreement). We also paidpay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees wereare determined according tobased on the Company’s credit rating.debt rating for senior unsecured debt of the Company, as determined by Moody’s and Standard & Poor’s. The spread over LIBOR rangedranges from 1.1250.875 percent to 1.751.500 percent per annum and commitment fees rangedrange from 0.150.075 percent to 0.300.200 percent per
annum. Based on ourthe unsecured debt to total capitalizationrating of the Company on September 30, 2018,2021, the spread over LIBOR would have been 1.125 percent had borrowings been outstanding under the 2018 Credit Facility and commitment fees would be 1.125 percent and 0.15 percent, respectively.are 0.125 percent. There wasis a financial covenant in the facility2018 Credit Facility that requiredrequires us to maintain a total funded debt to total capitalization ratio of less than or equal to 50 percent. The 20162018 Credit Facility containedcontains additional terms, conditions, restrictions and covenants that we believe wereare usual and customary in unsecured debt arrangements for companies of similar size and credit quality, including a limitation that priority debt (as defined in the credit agreement) couldmay not exceed 17.5 percent of the net worth of the Company. As of September 30, 2018, the Company had2021, there were no borrowings against the line, but there were threeor letters of credit outstanding, in the amount of $39.3 million. Two of these letters of credit in the amount of $29.3 million support self-insured losses under the Company’s high deductible casualty insurance programs and the remaining $10.0 million letter of credit supports an operating line of credit with a bank in Argentina. As a result, at September 30, 2018, we had $260.7leaving $750.0 million available to borrow under the 20162018 Credit Facility. Subsequent to
As of September 30,
2018, the Company decreased one of the three2021, we had 3 separate outstanding letters of credit
by $1.3with banks, in the amounts of $24.8 million,
which increased availability under the facility to $262.0$3.0 million, and $2.1 million.
Subsequent to our fiscal year-end, on November 13, 2018, we entered into a $750 million unsecured revolving credit facility (the “2018 Credit Facility”). In connection with entering into the 2018 Credit Facility, we terminated the 2016 Credit Facility. See Note 19-–Subsequent Events to our Consolidated Financial Statements for more information about the 2018 Credit Facility.
At
As of September 30,
2018,2021, we
also had a
$12$20.0 million unsecured standalone line of credit
which is purposedfacility, for
the purpose of obtaining the issuance of
bidinternational letters of credit, bank guarantees, and performance
bonds,bonds. Of the $20.0 million, $7.6 million of financial guarantees were outstanding as
needed, for international land operations. As of September 30,
2018, we do not have any outstanding obligations against this facility. 2021.
The applicable agreements for all unsecured debt contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30,
2018,2021, we were in compliance with all debt covenants.
At September 30, 2018,2021, aggregate maturities of long-term debt are as follows (in thousands):
| | | |
Year ending September 30, | | | |
2019 | | $ | — |
2020 | | | — |
2021 | | | — |
2022 | | | — |
2023 | | | — |
Thereafter | | | 500,000 |
| | $ | 500,000 |
| | | | | |
| Year ending September 30, | |
| 2022 | $ | — | |
| 2023 | — | |
| 2024 | — | |
| 2025 | — | |
| 2026 | — | |
| Thereafter - Due 2031 | 550,000 | |
| $ | 550,000 | |
NOTE 8 INCOME TAXES
Impact of
Income Tax
ReformOn December 22, 2017, the President of the United States signed into law the Tax Reform Act. Among a number of substantial changes to the current U.S. federal income tax rules, the Tax Reform Act decreases the marginal U.S. corporate income tax rate from 35 percent to 21 percent, provides for bonus depreciation that will allow for full expensing of qualified property in the year placed in service, limits the deductibility of certain expenditures, and significantly changes the U.S. taxation of certain foreign operations. By operation of law, we will apply a blended U.S. statutory federal income tax rate of 24.5 percent for fiscal year 2018. As a result of the Tax Reform Act, we were required to revalue deferred tax assets and liabilities from 35 percent to 21 percent. This revaluation has resulted in recognition of a tax benefit of approximately $502.1 million, which is included as a component of income tax expense in continuing operations on the Consolidated Statements of Operations.
On December 22, 2017, Staff Accounting Bulletin No. 118 ("SAB 118") was issued to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Reform Act. In accordance with SAB 118, we recorded our best estimate of the impact of the Tax Reform Act in our fiscal year end income tax provision in accordance with our understanding of the Tax Reform Act and guidance available as of the date of this filing. Although we believe we have substantially completed our accounting for certain income tax effects of the Tax Reform Act, to the extent that the Internal Revenue Service or U.S. Treasury issues additional guidance during the SAB 118 measurement period, the Company will promptly evaluate whether any additional adjustments are required.
Income Tax(Benefit) Provision and Rate
The components of the provision (benefit)benefit for income taxes are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, | | Year Ended September 30, |
| | 2018 | | 2017 | | 2016 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | 2019 |
Current: | | | | | | | | | | Current: | | | | | |
Federal | | $ | 757 | | $ | (36,260) | | $ | (86,010) | Federal | $ | (15,466) | | | $ | 15,431 | | | $ | 21,745 | |
Foreign | | | 6,492 | | | 4,108 | | | 9,987 | Foreign | 772 | | | 1,495 | | | 732 | |
State | | | 2,340 | | | (472) | | | (3,742) | State | 725 | | | 523 | | | 3,365 | |
| | | 9,589 | | | (32,624) | | | (79,765) | | (13,969) | | | 17,449 | | | 25,842 | |
Deferred: | | | | | | | | | | Deferred: | | | | | |
Federal | | | (508,256) | | | (14,953) | | | 58,136 | Federal | (81,760) | | | (127,096) | | | (35,809) | |
Foreign | | | 7,415 | | | (7,827) | | | 408 | Foreign | 4,106 | | | (12,390) | | | 2,804 | |
State | | | 14,083 | | | (1,331) | | | 1,544 | State | (12,098) | | | (18,069) | | | (11,549) | |
| | | (486,758) | | | (24,111) | | | 60,088 | | (89,752) | | | (157,555) | | | (44,554) | |
Total benefit | | $ | (477,169) | | $ | (56,735) | | $ | (19,677) | Total benefit | $ | (103,721) | | | $ | (140,106) | | | $ | (18,712) | |
2021 FORM 10-K|82
The amounts of domestic and foreign income (loss)loss before income taxes are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, | | Year Ended September 30, |
| | 2018 | | 2017 | | 2016 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | 2019 |
Domestic | | $ | 27,436 | | $ | (173,157) | | $ | (49,636) | Domestic | $ | (412,556) | | | $ | (458,364) | | | $ | (45,118) | |
Foreign | | | (11,595) | | | (11,441) | | | (23,031) | Foreign | (28,624) | | | (178,134) | | | (6,104) | |
| | $ | 15,841 | | $ | (184,598) | | $ | (72,667) | | $ | (441,180) | | | $ | (636,498) | | | $ | (51,222) | |
Effective income tax rates as compared to the U.S. Federal income tax rate are as follows:
| | | | | | | |
| | Year Ended September 30, | |
| | 2018 | | 2017 | | 2016 | |
U.S. Federal income tax rate | | 24.5 | % | 35.0 | % | 35.0 | % |
Effect of foreign taxes | | 87.8 | | 1.8 | | (13.8) | |
State income taxes, net of federal tax benefit | | 68.8 | | 0.6 | | 3.2 | |
U.S. domestic production activities | | — | | (2.1) | | (10.4) | |
Remeasurement of deferred tax related to Tax Reform Act | | (3,169.4) | | — | | — | |
Other impact of foreign operations | | (43.4) | | (2.9) | | 14.7 | |
Non-deductible meals and entertainment (1) | | 8.2 | | — | | — | |
Equity compensation (1) | | (5.3) | | — | | — | |
Officer's compensation (1) | | 1.7 | | — | | — | |
Contingent consideration adjustment (1) | | 10.7 | | — | | — | |
Other (1) | | 4.1 | | (1.7) | | (1.6) | |
Effective income tax rate | | (3,012.3) | % | 30.7 | % | 27.1 | % |
| | | | | | | | | | | | | | | | | |
| Year Ended September 30, |
| 2021 | | 2020 | | 2019 |
| U.S. Federal income tax rate | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Effect of foreign taxes | 0.1 | | | (0.2) | | | (0.6) | |
| State income taxes, net of federal tax benefit | 2.6 | | | 2.8 | | | 17.2 | |
| Other impact of foreign operations | — | | | (0.5) | | | 0.9 | |
| Non-deductible meals and entertainment | (0.1) | | | (0.2) | | | (2.5) | |
| Equity compensation | (0.8) | | | (0.3) | | | 2.7 | |
| Excess officer's compensation | — | | | (0.2) | | | (1.9) | |
| Contingent consideration adjustment | — | | | — | | | 4.5 | |
| Other | 0.7 | | | (0.4) | | | (4.8) | |
| Effective income tax rate | 23.5 | % | | 22.0 | % | | 36.5 | % |
| (1)
| | For fiscal years 2017 and 2016, “other” reflects adjustments for non-deductible meals and entertainment, equity compensation, officer’s compensation and contingent consideration.
|
Effective tax rates differ from the U.S. federal statutory rate of
24.521.0 percent
(blended for fiscal year 2018) due to state and foreign income taxes
change of the federal income tax rate from the Tax Reform Act, and the tax effect of non-deductible
expenses (primarily related to certain meals and entertainment, officer’s compensation limited pursuant to Section 162(m) of the Code, and adjustments to the contingent consideration related to the MOTIVE Merger).expenditures.
Deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated, and necessary valuation allowances are provided. The carrying value of the net deferred tax assets is based on management’s judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future.
The components of our net deferred tax liabilities are as follows:
| | | | | | | | | | | | | | | | |
| | September 30, | | September 30, |
| | 2018 | | 2017 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 |
Deferred tax liabilities: | | | | | | | Deferred tax liabilities: | | | |
Property, plant and equipment | | $ | 904,734 | | $ | 1,386,512 | Property, plant and equipment | $ | 598,798 | | | $ | 685,389 | |
Available-for-sale securities | | | 10,464 | | | 24,940 | |
| Marketable securities | | Marketable securities | 1,669 | | | 1,957 | |
Other | | | 12,787 | | | 21,609 | Other | 26,244 | | | 26,138 | |
Total deferred tax liabilities | | | 927,985 | | | 1,433,061 | Total deferred tax liabilities | 626,711 | | | 713,484 | |
Deferred tax assets: | | | | | | | Deferred tax assets: | | | |
Pension reserves | | | 3,477 | | | 7,614 | Pension reserves | 5,791 | | | 7,369 | |
Self-insurance reserves | | | 13,100 | | | 19,461 | Self-insurance reserves | 7,862 | | | 10,360 | |
Net operating loss, foreign tax credit, and other federal tax credit carryforwards | | | 55,889 | | | 62,478 | Net operating loss, foreign tax credit, and other federal tax credit carryforwards | 25,474 | | | 33,747 | |
Financial accruals | | | 45,708 | | | 62,971 | Financial accruals | 31,910 | | | 32,481 | |
Other | | | 4,888 | | | 6,003 | Other | 17,963 | | | 15,632 | |
Total deferred tax assets | | | 123,062 | | | 158,527 | Total deferred tax assets | 89,000 | | | 99,589 | |
Valuation allowance | | | (48,213) | | | (58,155) | Valuation allowance | (25,726) | | | (36,780) | |
Net deferred tax assets | | | 74,849 | | | 100,372 | Net deferred tax assets | 63,274 | | | 62,809 | |
Net deferred tax liabilities | | $ | 853,136 | | $ | 1,332,689 | Net deferred tax liabilities | $ | 563,437 | | | $ | 650,675 | |
The change in our net deferred tax assets and liabilities is impacted by foreign currency remeasurement.
2021 FORM 10-K|83
As of September 30,
2018,2021, we had federal, state and foreign tax net operating loss carryforwards of
$50.8approximately $7.3 million,
$31.2$56.2 million and
$83.7$32.0 million, respectively, federal and foreign research and development tax credits of approximately $1.0 million and $0.3 million, respectively, and foreign tax credit carryforwards of approximately
$24.9$10.6 million (of which
$20.1$9.3 million is reflected as a deferred tax asset in our Consolidated
Financial StatementsBalance Sheets prior to consideration of our valuation allowance)
, which will expire in fiscal years
20192022 through
2038.2041 and some of which can be carried forward indefinitely. Certain of these carryforwards are subject to various rules which impose limitations on their utilization. The valuation allowance is primarily attributable to foreign
and certain state net operating loss carryforwards of
$22.8$9.5 million,
and $0.5 million, respectively, and foreign tax credit carryforwards of
$20.1$9.3 million, equity compensation of
$2.3$5.4 million, and foreign minimum tax credit carryforwards of
$2.5$1.4 million which more likely than not will not be utilized.
Unrecognized Tax Benefits
We recognize accrued interest related to unrecognized tax benefits in interest expense, and penalties in other expense in the Consolidated Statements of Operations. As of September 30,
20182021 and
2017,2020, we had accrued interest and penalties of
$2.2$2.9 million and $2.8 million, respectively.
A reconciliation of the change in our gross unrecognized tax benefits for the fiscal years ended September 30, 20182021 and 20172020 is as follows:
| | | | | | | | | | | | | | | | |
| | September 30, | |
| | 2018 | | 2017 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 |
Unrecognized tax benefits at October 1, | | $ | 4,773 | | $ | 9,551 | Unrecognized tax benefits at October 1, | $ | 13,440 | | | $ | 15,759 | |
Gross increases - tax positions in prior periods | | | 3 | | | — | |
Gross decreases - tax positions in prior periods | | | — | | | (1) | |
Gross decreases - current period effect of tax positions | | | (280) | | | (170) | Gross decreases - current period effect of tax positions | (11,648) | | | (2,338) | |
Gross increases - current period effect of tax positions | | | 10,537 | | | 300 | Gross increases - current period effect of tax positions | — | | | 20 | |
Expiration of statute of limitations for assessments | | | (128) | | | (4,907) | Expiration of statute of limitations for assessments | (114) | | | (1) | |
Unrecognized tax benefits at September 30, | | $ | 14,905 | | $ | 4,773 | Unrecognized tax benefits at September 30, | $ | 1,678 | | | $ | 13,440 | |
As of September 30,
20182021 and
2017,2020, our liability for unrecognized tax benefits includes
$14.3$1.4 million and
$3.7$13.0 million, respectively, of unrecognized tax benefits related to discontinued operations that, if recognized, would not affect the effective tax rate. The remaining unrecognized tax benefits would affect the effective tax rate if recognized. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in our Consolidated Balance Sheets.
For the next 12 months, we cannot predict with certainty whether we will achieve ultimate resolution of any uncertain tax position associated with our U.S. and international
land operations that could result in increases or decreases of our unrecognized tax benefits. However, we do not expect
theany such increases or decreases to have a material effect on our results of operations or financial position.
We file a consolidated U.S. federal income tax return, as well as income tax returns in various states and foreign jurisdictions. The tax years that remain open to examination by U.S. federal and state jurisdictions include fiscal years 20142017 through 2017,2020, with exception of certain state jurisdictions currently under audit. The tax years remaining open to examination by foreign jurisdictions include 2003 through 2017.2020.
NOTE 9 SHAREHOLDERS’ EQUITY
| | | | | | | | | | | | | | |
| NOTE 9 SHAREHOLDERS’ EQUITY |
The Company has
an evergreen authorization from the Board
of Directors for the repurchase of up to
four4 million common shares in any calendar year. The repurchases may be made using our cash and cash equivalents or other available sources.
During the fiscal year ended September 30, 2021, we purchased no common shares. We
had no purchasespurchased 1.5 million and 1.0 million common shares at an aggregate cost of
common$28.5 million and $42.8 million, which are held as treasury shares, during the fiscal years ended September 30,
2018, 20172020 and
2016.2019, respectively.
As of September 30, 2021, we declared $109.2 million in cash dividends. A cash dividend of $0.25 per share was declared on September 1, 2021 for shareholders of record on November 23, 2021, payable on December 1, 2021. As a result, we recorded a Dividend Payable of $27.3 million on our Consolidated Balance Sheets as of September 30, 2021.
2021 FORM 10-K|84
Accumulated Other Comprehensive
Income (Loss)Loss
Components of accumulated other comprehensive income (loss)loss were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, | | September 30, |
| | 2018 | | 2017 | | 2016 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | 2019 |
Pre-tax amounts: | | | | | | | | | | Pre-tax amounts: | | | | | |
Unrealized appreciation on securities | | $ | 44,023 | | $ | 31,700 | | $ | 33,051 | |
Unrealized actuarial loss | | | (21,693) | | | (28,873) | | | (34,112) | Unrealized actuarial loss | (26,268) | | | (33,923) | | | (37,084) | |
| | $ | 22,330 | | $ | 2,827 | | $ | (1,061) | | $ | (26,268) | | | $ | (33,923) | | | $ | (37,084) | |
After-tax amounts: | | | | | | | | | | After-tax amounts: | | | | | |
Unrealized appreciation on securities | | $ | 29,071 | | $ | 20,070 | | $ | 20,899 | |
Unrealized actuarial loss | | | (12,521) | | | (17,770) | | | (21,103) | Unrealized actuarial loss | (20,244) | | | (26,188) | | | (28,635) | |
| | $ | 16,550 | | $ | 2,300 | | $ | (204) | | $ | (20,244) | | | $ | (26,188) | | | $ | (28,635) | |
The following is a summary of the changes in accumulated other comprehensive
income (loss),loss, net of tax, by component for the fiscal year ended September 30,
2018: | | | | | | | | | |
| | Unrealized | | | | | | |
| | Appreciation on | | Defined | | | |
| | Available-for-sale | | Benefit | | | |
| | Securities | | Pension Plan | | Total |
| | (in thousands) |
Balance at September 30, 2017 | | $ | 20,070 | | $ | (17,770) | | $ | 2,300 |
Other comprehensive income before reclassifications | | | 9,001 | | | — | | | 9,001 |
Amounts reclassified from accumulated other comprehensive income | | | — | | | 5,249 | | | 5,249 |
Net current-period other comprehensive income | | | 9,001 | | | 5,249 | | | 14,250 |
Balance at September 30, 2018 | | $ | 29,071 | | $ | (12,521) | | $ | 16,550 |
| | | | | |
| (in thousands) | Defined Benefit Pension Plan |
| Balance at September 30, 2020 | $ | (26,188) | |
| Activity during the period | |
| Amounts reclassified from accumulated other comprehensive loss | 5,944 | |
| Net current-period other comprehensive loss | 5,944 | |
| Balance at September 30, 2021 | $ | (20,244) | |
| | | | | | | | | | | | | | |
| NOTE 10 REVENUE FROM CONTRACTS WITH CUSTOMERS |
The majority of Contents
The following provides detail about accumulated other comprehensive income (loss) componentsour drilling services are performed on a “daywork” contract basis, under which were reclassifiedwe charge a rate per day, with the price determined by the location, depth and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. These drilling services, including our technology solutions, represent a series of distinct daily services that are substantially the same, with the same pattern of transfer to the Consolidated Statementscustomer. Because our customers benefit equally throughout the service period and our efforts in providing drilling services are incurred relatively evenly over the period of Operations duringperformance, revenue is recognized over time using a time-based input measure as we provide services to the customer.
Contracts generally contain renewal or extension provisions exercisable at the option of the customer at prices mutually agreeable to us and the customer. For contracts that are terminated by customers prior to the expirations of their fixed terms, contractual provisions customarily require early termination amounts to be paid to us. Revenues from early terminated contracts are recognized when all contractual requirements have been met. During the fiscal years ended September 30, 2018, 20172021, 2020 and 2016:2019, early termination revenue associated with term contracts was approximately $7.7 million, $73.4 million and $11.3 million, respectively. During the fiscal year ended September 30, 2021, we recognized no notification fee revenue related to well-to-well contracts. During the fiscal years ended September 30, 2020 and 2019, notification fee revenue related to well-to-well contracts was approximately $2.9 million and $1.2 million, respectively.
| | | | | | | | | | | |
| | Amount | | |
| | Reclassified from | | |
| | Accumulated Other | | |
| | Comprehensive | | Affected Line |
Details About Accumulated Other | | Income (Loss) | | Item in the Consolidated |
Comprehensive Income (Loss) Components | | 2018 | | 2017 | | 2016 | | 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 | | $ | 7,180 | | $ | 5,238 | | $ | (3,968) | | Selling, general and administrative |
| | | (1,931) | | | (1,905) | | | 1,443 | | Income tax provision |
| | | 5,249 | | | 3,333 | | | (2,525) | | Net of tax |
Total reclassifications for the period | | $ | 5,249 | | $ | 3,333 | | $ | (1,599) | | |
With most drilling contracts, we also receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenues associated with the mobilization and demobilization of our drilling rigs to and from the client’s drill site do not relate to a distinct good or service. These revenues are deferred and recognized ratably over the related contract term that drilling services are provided. For any contracts that include a provision for pooled term days at contract inception, followed by the assignment of days to specific rigs throughout the contract term, we have elected, as a practical expedient, to recognize revenue in the amount to which the entity has a right to invoice, as permitted by ASC 606.
2021 FORM 10-K|85
Demobilization fees expected to be received upon contract completion are estimated at contract inception and recognized on a straight-line basis over the contract term. The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced or no payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Any change in the expected amount of demobilization revenue is accounted for with the net cumulative impact of the change in estimate recognized in the period during which the revenue estimate is revised.
Contract Costs
Mobilization costs include certain direct costs incurred for mobilization of contracted rigs. These costs relate directly to a contract, enhance resources that will be used in satisfying the future performance obligations and are expected to be recovered. These costs are capitalized when incurred and recorded as current or noncurrent contract fulfillment cost assets (depending on the length of the initial contract term), and are amortized on a systematic basis consistent with the pattern of the transfer of the goods or services to which the asset relates which typically includes the initial term of the related drilling contract or a period longer than the initial contract term if management anticipates a customer will renew or extend a contract, which we expect to benefit from the cost of mobilizing the rig. Abnormal mobilization costs are fulfillment costs that are incurred from excessive resources, wasted or spoiled materials, and unproductive labor costs that are not otherwise anticipated in the contract price and are expensed as incurred. As of September 30, 2021 and 2020, we had capitalized fulfillment costs of $4.3 million and $6.2 million, respectively.
If capital modificationcosts are incurred for rig modifications or if upgrades are required for a contract, these costs are considered to be capital improvements. These costs are capitalized as property, plant and equipment and depreciated over the estimated useful life of the improvement.
Remaining Performance Obligations
The total aggregate transaction price allocated to the unsatisfied performance obligations, commonly referred to as backlog, as of September 30, 2021 was approximately $572.0 million, of which $440.8 million is expected to be recognized during fiscal year 2022, and approximately $131.2 million in fiscal year 2023 and thereafter. These amounts do not include anticipated contract renewals. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. Our contracts are subject to cancellation or modification at the election of the customer; however, due to the level of capital deployed by our customers on underlying projects, we have not been materially adversely affected by contract cancellations or modifications in the past. However, the impact of the COVID-19 pandemic is inherently uncertain, and, as a result, the Company is unable to reasonably estimate the duration and ultimate impacts of the pandemic, including the effect it may have on our contractual obligations with our customers.
Contract Assets and Liabilities
Amounts owed from our customers under our revenue contracts are typically billed on a monthly basis as the service is being provided and are due within 30 days of billing. Such amounts are classified as accounts receivable on our Consolidated Balance Sheets. Under certain of our contracts, we recognize revenues in excess of billings, referred to as contract assets, within prepaid expenses and other current assets within our Consolidated Balance Sheets.
Under certain of our contracts, we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized, referred to as deferred revenue or contract liabilities, within accrued liabilities and other noncurrent liabilities in our Consolidated Balance Sheets. Contract balances are presented at the net amount at a contract level.
The following table summarizes the balances of our contract assets and liabilities at the dates indicated:
| | | | | | | | | | | |
| (in thousands) | September 30, 2021 | | September 30, 2020 |
| Contract assets | $ | 4,513 | | | $ | 2,367 | |
| | | | | |
| (in thousands) | September 30, 2021 |
| Contract liabilities balance at October 1, 2019 | $ | 23,354 | |
| Payment received/accrued and deferred | 19,312 | |
| Revenue recognized during the period | (34,030) | |
| Contract liabilities balance at September 30, 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 | |
2021 FORM 10-K|86
NOTE 10 STOCK-BASED COMPENSATION
| | | | | | | | | | | | | | |
| NOTE 11 STOCK-BASED COMPENSATION |
On March 2, 2016,3, 2020, the Helmerich & Payne, Inc. 20162020 Omnibus Incentive Plan (the “2016“2020 Plan”) was approved by our stockholders. The 20162020 Plan is a stock and cash-based incentive plan that, among other things, authorizes the Board or Human Resources Committee of the Board to grant non-qualifiedexecutive officers, employees and non-employee directors stock options, stock appreciation rights, restricted shares and restricted stockshare units (including performance share units), share bonuses, other share-based awards to selected employees and to non-employee Directors.cash awards. Restricted stock may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than market price of the underlying stock on the date of grant. Stock options expire 10ten years after the grant date. Awards outstanding inunder the Helmerich & Payne, Inc. 20052010 Long-Term Incentive Plan and the Helmerich & Payne, Inc. 2010 Long-Term2016 Omnibus Incentive Plan (collectively the “2010 Plan”(the "2016 Plan") remain subject to the terms and conditions of those plans. Beginning with fiscal year 2019, we replaced stock options with performance share units as a component of our executives' long-term equity incentive compensation. As a result, there were no stock options granted during the fiscal years ended September 30, 2021 and 2020. We have also eliminated stock options as an element of our non-employee director compensation program. At September 30, 2021, we had 2.7 million outstanding stock options and 2.5 million exercisable stock options with weighted-average exercise prices of $63.34 and $63.57, respectively.
During the fiscal year ended September 30,
2018, there were 693,873 non-qualified stock options and 411,9772021, 700,982 shares of restricted stock awards
and 312,600 performance share units were granted under the
20162020 Plan.
An additional 213,904 of restricted stock grants were awarded outside of the 2016 Plan.
A summary of compensation cost for stock-based payment arrangements recognized in
drilling services operating expense, research and development expense and selling, general and administrative expense
on our Consolidated Statements of Operations, in fiscal years
2018, 20172021, 2020 and
20162019 is as follows:
| | | | | | | | | |
| | September 30, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
Compensation expense | | | | | | | | | |
Stock options | | $ | 7,913 | | $ | 7,439 | | $ | 8,290 |
Restricted stock | | | 23,774 | | | 18,744 | | | 16,093 |
| | $ | 31,687 | | $ | 26,183 | | $ | 24,383 |
Stock Options
Vesting requirements for stock options are determined by the Human Resources Committee of our Board of Directors. Options currently outstanding began vesting one year after the grant date with 25 percent of the options vesting for four consecutive years.
We use the Black-Scholes formula to estimate the fair value of stock options granted to employees. The fair value of the options is amortized to compensation expense on a straight-line basis over the requisite service periods of the stock awards, which are generally the vesting periods.
| | | | | | | | | | | | | | | | | |
| September 30, |
| (in thousands) | 2021 | | 2020 | | 2019 |
| Stock-based compensation expense | | | | | |
| Drilling services operating | $ | 5,927 | | | $ | 9,086 | | | $ | 7,132 | |
| Research and development | 1,271 | | | 765 | | | 328 | |
| Selling, general and administrative | 20,660 | | | 29,960 | | | 26,832 | |
| Restructuring charges | — | | | (3,482) | | | — | |
| $ | 27,858 | | | $ | 36,329 | | | $ | 34,292 | |
.The weighted-average fair value calculations for options granted within the fiscal period are based on the following weighted-average assumptions set forth in the table below. Options that were granted in prior periods are based on assumptions prevailing at the date of grant.
| | | | | | | |
| | 2018 | | 2017 | | 2016 | |
Risk-free interest rate (1) | | 2.2 | % | 2.0 | % | 1.8 | % |
Expected stock volatility (2) | | 36.1 | % | 38.9 | % | 37.6 | % |
Dividend yield (3) | | 4.7 | % | 3.7 | % | 4.6 | % |
Expected term (in years) (4) | | 6.0 | | 5.5 | | 5.5 | |
| (1)
| | The risk-free interest rate is based on U.S. Treasury securities for the expected term of the option.
|
| (2)
| | Expected volatilities are based on the daily closing price of our stock based upon historical experience over a period which approximates the expected term of the option.
|
| (3)
| | The dividend yield is based on our current dividend yield.
|
| (4)
| | The expected term of the options granted represents the period of time that they are expect to be outstanding. We estimate term of option granted based on historical experience with grants and exercise.
|
Based on these calculations, the weighted-average fair value per option granted to acquire a share of common stock was $13.17, $20.48 and $13.12 per share for fiscal years 2018, 2017 and 2016, respectively.
The following summary reflects the stock option activity for our common stock and related information for fiscal years 2018, 2017 and 2016 (shares in thousands):
| | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | | | Weighted-Average | | | | Weighted-Average | | | | Weighted-Average |
| | Shares | | Exercise Price | | Shares | | Exercise Price | | Shares | | Exercise Price |
Outstanding at October 1, | | 3,278 | | $ | 56.41 | | 3,312 | | $ | 51.74 | | 2,776 | | $ | 48.51 |
Granted | | 694 | | | 59.03 | | 396 | | | 76.61 | | 876 | | | 58.25 |
Exercised | | (375) | | | 36.88 | | (415) | | | 38.04 | | (220) | | | 31.52 |
Forfeited/Expired | | (98) | | | 70.77 | | (15) | | | 68.32 | | (120) | | | 61.80 |
Outstanding on September 30, | | 3,499 | | $ | 58.62 | | 3,278 | | $ | 56.41 | | 3,312 | | $ | 51.74 |
Exercisable on September 30, | | 2,193 | | $ | 56.31 | | 2,167 | | $ | 50.87 | | 2,225 | | $ | 46.66 |
Shares available to grant | | 5,140 | | | | | 5,624 | | | | | 6,600 | | | |
The following table summarizes information about stock options at September 30, 2018 (shares in thousands):
| | | | | | | | | | | | |
| | Outstanding Stock Options | | Exercisable Stock Options |
| | | | Weighted-Average | | Weighted-Average | | | | Weighted-Average |
Range of Exercise Prices | | Options | | Remaining Life | | Exercise Price | | Options | | Exercise Price |
$0.00 to $21.07 | | 180 | | 0.2 | | $ | 21.07 | | 180 | | $ | 21.07 |
$21.07 to $59.76 | | 2,417 | | 5.9 | | | 55.16 | | 1,418 | | | 53.03 |
$59.76 to $68.83 | | 358 | | 6.3 | | | 68.66 | | 275 | | | 68.83 |
$68.83 to $81.31 | | 544 | | 7.1 | | | 79.79 | | 320 | | | 79.86 |
| | 3,499 | | | | | | | 2,193 | | | |
At September 30, 2018, the weighted-average remaining life of exercisable stock options was 4.36 years and the aggregate intrinsic value was $30.9 million with a weighted-average exercise price of $56.31 per share.
The number of options vested or expected to vest at September 30, 2018 was 1,306,087 with an aggregate intrinsic value of $10.6 million and a weighted-average exercise price of $62.49 per share.
As of September 30, 2018, the unrecognized compensation cost related to the stock options was $7.3 million. That cost is expected to be recognized over a weighted-average period of 2.3 years.
The total intrinsic value of options exercised during fiscal years 2018, 2017 and 2016 was $9.9 million, $13.1 million and $6.3 million, respectively.
The grant date fair value of shares vested during fiscal years 2018, 2017 and 2016 was $8.8 million, $6.7 million and $9.6 million, respectively.
Restricted stock awards consist of our common
stock andstock. Awards granted prior to September 30, 2020 are time-vested over
four years, and awards granted after September 30, 2020 are time vested over three
to six years.
Non-forfeitable dividends are paid on non-vested shares of restricted stock. We recognize compensation expense on a straight-line basis over the vesting period. The fair value of restricted stock awards is determined based on the closing price of our shares on the grant date. As of September 30,
2018,2021, there was
$34.4$28.0 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
2.42.0 years.
A summary of the status of our restricted stock awards as of September 30, 2018,2021, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2018, 20172021, 2020 and 2016,2019, is as follows (sharesfollows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| (shares in thousands) | 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 restricted stock outstanding at October 1, | 1,280 | | | $ | 49.81 | | | 1,085 | | | $ | 61.28 | | | 1,001 | | | $ | 63.74 | |
Granted1 | 701 | | | 25.61 | | | 781 | | | 39.99 | | | 475 | | | 58.45 | |
Vested2 | (534) | | | 51.79 | | | (501) | | | 59.46 | | | (371) | | | 64.32 | |
| Forfeited | (35) | | | 35.76 | | | (85) | | | 48.98 | | | (20) | | | 60.85 | |
| Non-vested restricted stock outstanding at September 30, | 1,412 | | | $ | 37.36 | | | 1,280 | | | $ | 49.81 | | | 1,085 | | | $ | 61.28 | |
(1)Restricted stock shares include restricted phantom stock units under our Director Deferred Compensation Plan. These phantom stock units confer the economic benefits of owning company stock without the actual ownership, transfer or issuance of any shares. During the fiscal year ended September 30, 2021, 18,906 restricted phantom stock units were granted and 20,616 restricted phantom stock units vested during the same period.
(2)The number of restricted stock awards vested includes shares that we withheld on behalf of our employees to satisfy the statutory tax withholding requirements.
2021 FORM 10-K|87
Performance Units
We have made awards to certain employees that are subject to market-based performance conditions ("performance units"). Subject to the terms and conditions set forth in thousands):the applicable performance share unit award agreements and the 2020 Plan, grants of performance units are subject to a vesting period of three years (the “Vesting Period”) that is dependent on the achievement of certain performance goals. Such performance unit grants consist of 2 separate components. Performance units that comprise the first component are subject to a three-year performance cycle. Performance units that comprise the second component are further divided into 3 separate tranches, each of which is subject to a separate one-year performance cycle within the full three-year performance cycle. The vesting of the performance units is generally dependent on (i) the achievement of the Company’s total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Group”) over the applicable performance cycle, and (ii) the continued employment of the recipient of the performance unit award throughout the Vesting Period.
| | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | | | 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, | | 659 | | $ | 70.76 | | 648 | | $ | 64.24 | | 668 | | $ | 67.03 |
Granted | | 626 | | | 59.53 | | 292 | | | 78.69 | | 294 | | | 58.25 |
Vested (1) | | (258) | | | 70.60 | | (271) | | | 63.81 | | (256) | | | 64.75 |
Forfeited | | (26) | | | 66.73 | | (10) | | | 68.09 | | (58) | | | 63.65 |
Outstanding on September 30, | | 1,001 | | $ | 63.74 | | 659 | | $ | 70.76 | | 648 | | $ | 64.24 |
The grant date fair value of performance units was determined through use of the Monte Carlo simulation method. The Monte Carlo simulation method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined Peer Group companies' stock, risk free rate of return and cross-correlations between the Company and our Peer Group companies. The valuation model assumes dividends are immediately reinvested. As of September 30, 2021, there was $9.5 million of unrecognized compensation cost related to unvested performance units. That cost is expected to be recognized over a weighted-average period of 1.9 years.
A summary of the status of our performance units as of September 30, 2021, 2020 and 2019 and changes in non-vested performance units outstanding during the fiscal years ended September 30, 2021, 2020 and 2019 is presented below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| (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, | 337 | | | $ | 51.09 | | | 145 | | | $ | 62.66 | | | $ | — | | | $ | — | |
| Granted | 313 | | | 29.77 | | | 259 | | | 43.40 | | | 145 | | | 62.66 | |
| Dividend rights performance units credited | 60 | | | 49.64 | | | — | | | — | | | — | | | — | |
| Forfeited | (11) | | | 43.40 | | | (67) | | | 46.35 | | | — | | | — | |
Non-vested performance units outstanding September 30,1 | 699 | | | $ | 41.55 | | | 337 | | | $ | 51.09 | | | $ | 145 | | | $ | 62.66 | |
(1) Of the total non-vested performance units at the end of the period, specified performance criteria has been achieved with respect to 88,440 performance units which is calculated based on the payout percentage for the completed performance period. The vesting and number of the remainder of non-vested performance units reflected at the end of the period is contingent upon our achievement of specified target performance criteria. If we meet the specified maximum performance criteria, approximately 547,392 additional performance units could vest or become eligible to vest.
The weighted-average fair value calculations for performance units granted within the fiscal period are based on the following weighted-average assumptions set forth in the table below.
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Risk-free interest rate1 | 0.2 | % | | 1.6 | % | | 2.7 | % |
Expected stock volatility2 | 62.3 | % | | 34.8 | % | | 35.9 | % |
| Expected term (in years) | 3.1 | | 3.2 | | 3.0 |
(1)The risk-free interest rate is based on U.S. Treasury securities for the expected term of the 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 performance units.
2021 FORM 10-K|88
| (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 11 EARNINGS (LOSSES) PER COMMON SHARE
ASC 260, Earnings per Share, requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividends or dividend equivalents as a separate class of securities in calculating earnings per share. We have granted and expect to continue to grant to employees restricted stock grants that contain non-forfeitable rights to dividends. Such grants are considered participating securities under ASC 260. As such, we are required to include these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.
Basic earnings per share is computed utilizing the two-class method and is calculated based on the weighted-average number of common shares outstanding during the periods presented.
Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options, non-vested restricted stock and performance units.
Under the two-class method of calculating earnings per share, dividends paid and a portion of undistributed net income, but not losses, are allocated to unvested restricted stock grants that receive dividends, which are considered participating securities.
The following table sets forth the computation of basic and diluted earnings (loss) per share:
| | | | | | | | | |
| | September 30, |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
| | | | | | | | | |
Numerator: | | | | | | | | | |
Income (loss) from continuing operations | | $ | 493,010 | | $ | (127,863) | | $ | (52,990) |
Loss from discontinued operations | | | (10,338) | | | (349) | | | (3,838) |
Net income (loss) | | | 482,672 | | | (128,212) | | | (56,828) |
Adjustment for basic earnings per share | | | | | | | | | |
Earnings allocated to unvested shareholders | | | (4,346) | | | (1,811) | | | (1,858) |
Numerator for basic earnings per share: | | | | | | | | | |
From continuing operations | | | 488,664 | | | (129,674) | | | (54,848) |
From discontinued operations | | | (10,338) | | | (349) | | | (3,838) |
| | | 478,326 | | | (130,023) | | | (58,686) |
Adjustment for diluted earnings per share: | | | | | | | | | |
Effect of reallocating undistributed earnings of unvested shareholders | | | 7 | | | — | | | — |
Numerator for diluted earnings per share: | | | | | | | | | |
From continuing operations | | | 488,671 | | | (129,674) | | | (54,848) |
From discontinued operations | | | (10,338) | | | (349) | | | (3,838) |
| | $ | 478,333 | | $ | (130,023) | | $ | (58,686) |
Denominator: | | | | | | | | | |
Denominator for basic earnings per share - weighted-average shares | | | 108,851 | | | 108,500 | | | 107,996 |
Effect of dilutive shares from stock options and restricted stock | | | 536 | | | — | | | — |
Denominator for diluted earnings per share - adjusted weighted-average shares | | | 109,387 | | | 108,500 | | | 107,996 |
Basic earnings per common share: | | | | | | | | | |
Income (loss) from continuing operations | | $ | 4.49 | | $ | (1.20) | | $ | (0.50) |
Loss from discontinued operations | | | (0.10) | | | — | | | (0.04) |
Net income (loss) | | $ | 4.39 | | $ | (1.20) | | $ | (0.54) |
Diluted earnings per common share: | | | | | | | | | |
Income (loss) from continuing operations | | $ | 4.47 | | $ | (1.20) | | $ | (0.50) |
Loss from discontinued operations | | | (0.10) | | | — | | | (0.04) |
Net income (loss) | | $ | 4.37 | | $ | (1.20) | | $ | (0.54) |
| | | | | | | | | | | | | | | | | |
| September 30, |
| (in thousands, except per share amounts) | 2021 | | 2020 | | 2019 |
| Numerator: | | | | | |
| Loss from continuing operations | $ | (337,459) | | | $ | (496,392) | | | $ | (32,510) | |
| Income (loss) from discontinued operations | 11,309 | | | 1,895 | | | (1,146) | |
| Net loss | (326,150) | | | (494,497) | | | (33,656) | |
| Adjustment for basic earnings (loss) per share | | | | | |
| Losses allocated to unvested shareholders | (1,350) | | | (2,647) | | | (3,102) | |
| Numerator for basic earnings (loss) per share: | | | | | |
| From continuing operations | (338,809) | | | (499,039) | | | (35,612) | |
| From discontinued operations | 11,309 | | | 1,895 | | | (1,146) | |
| (327,500) | | | (497,144) | | | (36,758) | |
| | | | | |
| | | | | |
| Numerator for diluted earnings (loss) per share: | | | | | |
| From continuing operations | (338,809) | | | (499,039) | | | (35,612) | |
| From discontinued operations | 11,309 | | | 1,895 | | | (1,146) | |
| $ | (327,500) | | | $ | (497,144) | | | $ | (36,758) | |
| Denominator: | | | | | |
| Denominator for basic earnings (loss) per share - weighted-average shares | 107,818 | | | 108,009 | | | 109,216 | |
| Effect of dilutive shares from stock options, restricted stock and performance share units | — | | | — | | | — | |
| Denominator for diluted earnings (loss) per share - adjusted weighted-average shares | 107,818 | | | 108,009 | | | 109,216 | |
| Basic earnings (loss) per common share: | | | | | |
| Loss from continuing operations | $ | (3.14) | | | $ | (4.62) | | | $ | (0.33) | |
| Income (loss) from discontinued operations | 0.10 | | | 0.02 | | | (0.01) | |
| Net loss | $ | (3.04) | | | $ | (4.60) | | | $ | (0.34) | |
| Diluted earnings (loss) per common share: | | | | | |
| Loss from continuing operations | $ | (3.14) | | | $ | (4.62) | | | $ | (0.33) | |
| Income (loss) from discontinued operations | 0.10 | | | 0.02 | | | (0.01) | |
| Net loss | $ | (3.04) | | | $ | (4.60) | | | $ | (0.34) | |
We had a net loss for fiscal years 20172021, 2020, and 2016.2019. Accordingly, our diluted earnings per share calculation for those years were equivalent to our basic earnings per share calculation since diluted earnings per share excluded any
assumed exercise of equity awards. These were excluded because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable period.
The following potentially dilutive average shares attributable to outstanding equity awards were excluded from the calculation of diluted earnings (losses) per share because their inclusion would have been anti-dilutive:
| | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | (in thousands, except per share amounts) |
Shares excluded from calculation of diluted earnings per share | | | 1,559 | | | 1,008 | | | 1,788 |
Weighted-average price per share | | $ | 68.28 | | $ | 74.38 | | $ | 63.73 |
2021 FORM 10-K|89
| | | | | | | | | | | | | | | | | |
| (in thousands, except per share amounts) | 2021 | | 2020 | | 2019 |
| Potentially dilutive shares excluded as anti-dilutive | 3,894 | | | 4,004 | | | 3,031 | |
| Weighted-average price per share | $ | 57.23 | | | $ | 60.72 | | | $ | 63.33 | |
NOTE 12 FAIR VALUE MEASUREMENT OF FINANCIAL INSTRUMENTS
| | | | | | | | | | | | | | |
| NOTE 13 FAIR VALUE MEASUREMENT OF FINANCIAL INSTRUMENTS |
We have certain assets and liabilities that are required to be measured and disclosed at fair value. Fair value is defined as the exchange price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date. We use the fair value hierarchy established in ASC 820-10 to measure fair value to prioritize the inputs:
| ·
| | Level 1 — Quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity can access at the measurement date.
|
| ·
| | Level 2 — Observable inputs, other than quoted prices included in Level 1, such as quoted prices for similar assets or liabilities in active markets; quoted prices for similar assets and liabilities in markets that are not active; or other inputs that are observable or can be corroborated by observable market data.
|
•Level 1 — Quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity can access at the measurement date. | ·
| | 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•Level 2 — Observable inputs, other than quoted prices included in Level 1, such as quoted prices for similar techniques that use significant unobservable inputs.
|
The assets heldor liabilities in a Non-Qualified Supplemental Savings Planactive markets; quoted prices for similar assets and liabilities in markets that are carriednot 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, 2021, our financial instruments measured at fair value utilizing Level 1 inputs include cash equivalents, U.S. agency issued debt securities, equity securities with active markets and totaled $16.2 millionmoney market funds. For these items, quoted current market prices are readily available. Our restricted assets consist of cash equivalents with the current portion included in prepaid expenses and $13.9 million atother, and the noncurrent portion included in other assets.
At September 30, 2018 and 2017, respectively. The2021, assets are comprised of mutual fundsmeasured at fair value using Level 2 inputs include corporate bonds measured using broker quotations that areutilize observable market inputs.
Our financial instruments 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 included3 unobservable inputs primarily consist of potential earnout payments associated with our business acquisitions in other income (expense) in the Consolidated Statements of Operations. The securities are recorded at fair value.
fiscal year 2019.
Our non-financial assets, such as intangible assets
goodwill and property, plant and equipment, are recorded at fair value when acquired in a business combination or when an impairment charge is recognized. If measured at fair value in the Consolidated Balance Sheets, these would generally be classified within Level 2 or 3 of the fair value hierarchy. Refer to Note
3—Business Combinations, Note 5—4—Property, Plant and Equipment
and Note 6—Goodwill and Intangible Assets for
detailsadditional disclosure on
thesethe fair value
measurements.of our assets classified as held-for-sale as of September 30, 2021.
The carrying value of other current assets, accrued liabilities and other liabilities approximated fair value at September 30, 2021 and 2020.
2021 FORM 10-K|90
The following table summarizes our assets and liabilities measured at fair value presented in our Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2021 |
| (in thousands) | Fair Value | | Level 1 | | Level 2 | | Level 3 |
| Recurring fair value measurements: | | | | | | | |
| Cash and cash equivalents | $ | 917,534 | | | $ | 917,534 | | | $ | — | | | $ | — | |
| 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 | | | — | |
| | | | | | | |
| Other current assets | 18,350 | | | 18,350 | | | — | | | — | |
| | | | | | | |
| Investments: | | | | | | | |
| Non-qualified supplemental savings plan | 18,221 | | | 18,221 | | | — | | | — | |
| Debt and equity securities | 17,223 | | | 13,858 | | | — | | | 3,365 | |
| Cornerstone investment in ADNOC Drilling | 100,000 | | | 100,000 | | | — | | | — | |
| Total investments | 135,444 | | | 132,079 | | | — | | | 3,365 | |
| | | | | | | |
| Other assets | 832 | | | 832 | | | — | | | — | |
| Total assets measured at fair value | $ | 1,270,860 | | | $ | 1,074,545 | | | $ | 192,950 | | | $ | 3,365 | |
| | | | | | | |
| Liabilities: | | | | | | | |
| Contingent consideration | $ | 2,996 | | | $ | — | | | $ | — | | | $ | 2,996 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2020 |
| (in thousands) | Fair Value | | Level 1 | | Level 2 | | Level 3 |
| Recurring fair value measurements: | | | | | | | |
| Cash and cash equivalents | $ | 487,884 | | | $ | 487,884 | | | $ | — | | | $ | — | |
| Short-term investments: | | | | | | | |
| Certificates of deposit | 1,370 | | | — | | | 1,370 | | | — | |
| Corporate debt securities | 78,156 | | | — | | | 78,156 | | | — | |
| U.S. government and federal agency securities | 7,817 | | | 7,817 | | | — | | | — | |
| Other | 1,992 | | | 1,992 | | | — | | | — | |
| Total short-term investments | 89,335 | | | 9,809 | | | 79,526 | | | — | |
| | | | | | | |
| Other current assets | 45,577 | | | 45,577 | | | — | | | — | |
| | | | | | | |
| Investments: | | | | | | | |
| Non-qualified supplemental savings plan | 19,819 | | | 19,819 | | | — | | | — | |
| Debt and equity securities | 11,766 | | | 7,274 | | | 3,992 | | | 500 | |
| Total investments | 31,585 | | | 27,093 | | | 3,992 | | | 500 | |
| | | | | | | |
| Other assets | 3,286 | | | 3,286 | | | — | | | — | |
| Total assets measured at fair value | $ | 657,667 | | | $ | 573,649 | | | $ | 83,518 | | | $ | 500 | |
| | | | | | | |
| Liabilities: | | | | | | | |
| Contingent consideration | $ | 9,123 | | | $ | — | | | $ | — | | | $ | 9,123 | |
Cash Equivalents and Investments (Short and Long-Term)
The majority of cash equivalents are invested in
highly-liquidhighly liquid money-market mutual funds invested primarily in direct or indirect obligations of the U.S.
Government.Government and in federally insured deposit accounts. The carrying amount of cash and cash equivalents approximates fair value due to the short maturity of those investments.
The carrying value of other current assets, accrued liabilities and other liabilities approximated fair value at September 30, 2018 and 2017.
2021 FORM 10-K|91
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 following table summarizes oursecurities are recorded at fair value.
Our long-term investments include equity securities and assets held in a Non-Qualified Supplemental Savings Plan ("Savings Plan"). Our assets that we hold in the Savings Plan are comprised of mutual funds that are measured using Level 1 inputs. Additionally, we hold equity securities in Schlumberger, Ltd., which is classified as Level 1 and based on the quoted stock price.
We also hold various other equity securities without readily determinable fair values that are classified as Level 3. These equity securities are measured at cost, less any impairments.
As a result of the change in the fair value presentedof our long-term investments, we recorded a gain of $6.7 million for the year ended September 30, 2021.
During September 2021, the Company made a $100.0 million cornerstone investment in ADNOC Drilling in advance of its announced IPO. ADNOC Drilling’s IPO completed on October 3, 2021 and our $100.0 million investment represents 159.7 million shares of ADNOC Drilling, equivalent to a 1 percent ownership stake. Our investment is subject to a three-year lockup period and is classified as a long-term investment within Investments in our Consolidated Balance
Sheet asSheets. As of September 30,
2018: | | | | | | | | | | | | |
| | 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 | | | 17,518 | | | — | | | 17,518 | | | — |
U.S. government and federal agency securities | | | 22,443 | | | 22,443 | | | — | | | — |
Total short-term investments | | | 41,461 | | | 22,443 | | | 19,018 | | | — |
Cash and cash equivalents | | | 284,355 | | | 284,355 | | | — | | | — |
Investments | | | 82,496 | | | 82,496 | | | — | | | — |
Other current assets | | | 39,830 | | | 39,830 | | | — | | | — |
Other assets | | | 2,000 | | | 2,000 | | | — | | | — |
Total assets measured at fair value | | $ | 450,142 | | $ | 431,124 | | $ | 19,018 | | $ | — |
| | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | |
Contingent earnout liability | | $ | 11,160 | | $ | — | | $ | — | | $ | 11,160 |
At September 30, 2018, our financial instruments measured at fair value utilizing2021, this investment was classified as a Level 1 inputs include cash equivalents, U.S. Agency issued debt securities, equity securities with active markets, and money market funds that are classified as restricted assets. The current portion of restricted amounts are included in prepaid expenses and other, and the noncurrent portion is included in other assets. For these items, quoted current market prices are readily available.
At September 30, 2018, assets measured at fair value using Level 2 inputs include certificates of deposit, municipal bonds and corporate bonds measured using broker quotations that utilize observable market inputs.
Our financial instruments measured using Level 3 inputs consist of potential earnout payments associated with the acquisition of MOTIVE in fiscal year 2017. The valuation techniques used for determining the fair value of the potential earnout payments use a Monte Carlo simulation which evaluates numerous potential earnings and pay out scenarios.
investment.
Contingent Consideration
The following table presents a reconciliation of changes in the fair value of our financial assets and liabilities classified as Level 3 fair value measurements in the fair value hierarchy for fiscal years 2021 and 2020:
| | | | | | | | | | | |
| (in thousands) | 2021 | | 2020 |
| Net liabilities at beginning of period | $ | 9,123 | | | $ | 18,373 | |
| Additions | — | | | 1,500 | |
| Total gains or losses: | | | |
| Included in earnings | 1,123 | | | (2,500) | |
Settlements1 | (7,250) | | | (8,250) | |
| Net liabilities at end of period | $ | 2,996 | | | $ | 9,123 | |
(1)Settlements represent earnout payments that have been earned or paid during the indicated periods:period.
| | | | | | |
| | 2018 | | 2017 |
| | (in thousands) |
| | | | | | |
Net liabilities at beginning of period | | $ | 14,879 | | $ | — |
Total gains or losses: | | | | | | |
Included in earnings | | | 6,906 | | | 14,879 |
Settlements (1) | | | (10,625) | | | — |
Net liabilities at end of period | | $ | 11,160 | | $ | 14,879 |
| (1)
| | Settlements represent earnout payments that have been earned or paid during the period.
|
The following information presents the supplemental fair value information about current and long-term fixed-rate debt at September 30, 20182021 and 2020: | | | | | | | | | | | |
| September 30, |
| (in millions) | 2021 | | 20201 |
| Current portion of long-term debt | | | |
| Carrying value | $ | 483.5 | | | $ | — | |
| Fair value | $ | 541.6 | | | $ | — | |
| | | |
| Long-term debt, net | | | |
| Carrying value | $ | 542.0 | | | $ | 480.7 | |
| Fair value | $ | 554.3 | | | $ | 534.5 | |
(1)As of September 30, 2017.2021 we reclassified the outstanding 2025 Notes to Current Portion of Long-Term Debt on our Consolidated Balance Sheets. On October 27, 2021, we redeemed these notes. See Note 7—Debt to our Consolidated Financial Statements.
| | | | | | |
| | September 30, |
| | 2018 | | 2017 |
| | (in millions) |
Carrying value of long-term fixed-rate debt | | $ | 494.0 | | $ | 492.9 |
Fair value of long-term fixed-rate debt | | $ | 509.3 | | $ | 529.0 |
The fair value for the
$500$541.6 million
current portion of fixed-rate debt
wasand the $554.3 million of long-term fixed-rate debt are based on broker quotes at September 30,
2018.2021. The notes are classified within Level 2 of the fair value hierarchy as they are not actively traded in markets.
On an ongoing basis we evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment
87
2021 FORM 10-K|92
charge is recorded and a new cost basis established. We review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. When securities are sold, the cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold.
The estimated fair value of our available-for-sale securities, reflected on our Consolidated Balance Sheets as Investments, is based on Level 1 inputs. The following is a summary of available-for-sale securities, which excludes assets held in a Non-Qualified Supplemental Savings Plan:
| | | | | | | | | | | | |
| | | | | Gross | | Gross | | Estimated |
| | | | | Unrealized | | Unrealized | | Fair |
| | Cost | | Gains | | Losses | | Value |
| | (in thousands) |
Equity Securities: | | | | | | | | | | | | |
September 30, 2018 | | $ | 38,473 | | $ | 44,023 | | $ | — | | $ | 82,496 |
September 30, 2017 | | $ | 38,473 | | $ | 31,700 | | $ | — | | $ | 70,173 |
NOTE 13 EMPLOYEE BENEFIT PLANS
| | | | | | | | | | | | | | |
| NOTE 14 EMPLOYEE BENEFIT PLANS |
We maintain a domestic noncontributory defined benefit pension plan covering certain U.S. employees who meet certain age and service requirements. In July 2003, we revised the Helmerich & Payne, Inc. Employee Retirement Plan (“Pension Plan”) to close the Pension Plan to new participants effective October 1, 2003, and reduce benefit accruals for current participants through September 30, 2006, at which time benefit accruals were discontinued and the Pension Plan was frozen.
The following table provides a reconciliation of the changes in the pension benefit obligations and fair value of Pension Plan assets over the two-year period ended September 30, 20172021 and a statement of the funded status as of September 30, 20182021 and 2017:2020:
| | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | |
| | (in thousands) | |
Accumulated Benefit Obligation | | $ | 106,205 | | $ | 109,976 | |
Changes in projected benefit obligations | | | | | | | |
| (in thousands) | | (in thousands) | 2021 | | 2020 |
| Accumulated benefit obligation | | Accumulated benefit obligation | $ | 110,352 | | | $ | 116,146 | |
| Changes in projected benefit obligations: | | Changes in projected benefit obligations: | |
Projected benefit obligation at beginning of year | | $ | 109,976 | | $ | 109,731 | Projected benefit obligation at beginning of year | $ | 116,146 | | | $ | 119,845 | |
Interest cost | | | 4,077 | | | 4,053 | Interest cost | 2,925 | | | 3,598 | |
Actuarial (gain) loss | | | (2,143) | | | 3,633 | |
| Actuarial loss | | Actuarial loss | 7,111 | | | 4,310 | |
Benefits paid | | | (5,705) | | | (7,441) | Benefits paid | (15,749) | | | (11,607) | |
| Other | | Other | (81) | | | — | |
Projected benefit obligation at end of year | | $ | 106,205 | | $ | 109,976 | Projected benefit obligation at end of year | $ | 110,352 | | | $ | 116,146 | |
Change in plan assets | | | | | | | |
| Change in plan assets: | | Change in plan assets: | | | |
Fair value of plan assets at beginning of year | | $ | 92,816 | | $ | 90,748 | Fair value of plan assets at beginning of year | $ | 86,103 | | | $ | 91,142 | |
Actual return on plan assets | | | 7,754 | | | 9,470 | Actual return on plan assets | 11,835 | | | 6,535 | |
Employer contribution | | | 32 | | | 39 | Employer contribution | 5,066 | | | 33 | |
Benefits paid | | | (5,705) | | | (7,441) | Benefits paid | (15,749) | | | (11,607) | |
Fair value of plan assets at end of year | | $ | 94,897 | | $ | 92,816 | Fair value of plan assets at end of year | $ | 87,255 | | | $ | 86,103 | |
Funded status of the plan at end of year | | $ | (11,308) | | $ | (17,160) | Funded status of the plan at end of year | $ | (23,097) | | | $ | (30,043) | |
Fluctuations in actuarial losses during the period are primarily due to changes in the discount rate, interest rates, and the mortality table. The mortality table issued by the Society of Actuaries in October 2020 was used for the September 30, 2021 pension calculation.
The amounts recognized in the Consolidated Balance Sheets at September 30, 20182021 and 20172020 are as follows (in thousands):follows:
| | | | | | | | | | | | | | | | |
| (in thousands) | | (in thousands) | 2021 | | 2020 |
Accrued liabilities | | $ | (58) | | $ | (45) | Accrued liabilities | $ | — | | | $ | (18) | |
Noncurrent liabilities-other | | | (11,250) | | | (17,115) | Noncurrent liabilities-other | (23,097) | | | (30,025) | |
Net amount recognized | | $ | (11,308) | | $ | (17,160) | Net amount recognized | $ | (23,097) | | | $ | (30,043) | |
The amounts recognized in Accumulated Other Comprehensive
Income (Loss)Loss at September 30,
20182021 and
2017,2020, and not yet reflected in net periodic benefit cost, are as
follows (in thousands): | | | | | | |
Net actuarial loss | | $ | (21,693) | | $ | (28,873) |
| | | | | | | | | | | |
| (in thousands) | 2021 | | 2020 |
| Net actuarial loss | $ | 26,268 | | | $ | 33,923 | |
The amount recognized in Accumulated Other Comprehensive Income (Loss) and not yet reflected in periodic benefit cost expected to be amortized in next year’s periodic benefit cost is a net actuarial loss of $1.2 million.
The weighted average assumptions used for the pension calculations were as follows:
| | | | | | | | | | | | | | | | | | | | | | |
| | September 30, | | September 30, |
| | 2018 | | 2017 | | 2016 | | | 2021 | | 2020 | | 2019 |
Discount rate for net periodic benefit costs | | 3.79 | % | 3.64 | % | 4.27 | % | Discount rate for net periodic benefit costs | 2.66 | % | | 3.16 | % | | 4.27 | % |
Discount rate for year-end obligations | | 4.27 | % | 3.79 | % | 3.64 | % | Discount rate for year-end obligations | 2.75 | % | | 2.66 | % | | 3.16 | % |
Expected return on plan assets | | 6.06 | % | 6.17 | % | 5.89 | % | Expected return on plan assets | 3.50 | % | | 4.65 | % | | 5.60 | % |
The mortality table issued by the Society
We made a voluntary contribution of
Actuaries in October 2018 was used for the September 30, 2018 pension calculation. The new mortality information reflects improved life expectancies and projected mortality improvements.We did not make any contributions to the Pension Plan$5.0 million in fiscal year 2018.2021. In fiscal year 2019,2022, we do not expect minimum contributions required by law to be needed. However, we may make contributions in fiscal year 20192022 if needed to fund unexpected distributions in lieu of liquidating pension assets.
2021 FORM 10-K|93
Components of the net periodic pension expense (benefit) were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, | | Year Ended September 30, |
| | 2018 | | 2017 | | 2016 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | 2019 |
Interest cost | | $ | 4,077 | | $ | 4,053 | | $ | 4,266 | Interest cost | $ | 2,925 | | | $ | 3,598 | | | $ | 4,389 | |
Expected return on plan assets | | | (5,555) | | | (5,130) | | | (5,616) | Expected return on plan assets | (3,722) | | | (4,784) | | | (5,523) | |
Recognized net actuarial loss | | | 1,926 | | | 2,891 | | | 2,083 | Recognized net actuarial loss | 3,205 | | | 2,718 | | | 1,229 | |
Settlement | | | 913 | | | 1,640 | | | 4,964 | Settlement | 3,448 | | | 3,001 | | | 1,953 | |
| Other | | Other | (81) | | | — | | | — | |
Net pension expense | | $ | 1,361 | | $ | 3,454 | | $ | 5,697 | Net pension expense | $ | 5,775 | | | $ | 4,533 | | | $ | 2,048 | |
We record settlement expense when benefit payments exceed the total annual
service and interest costs.
The following table reflects the expected benefits to be paid from the Pension Plan in each of the next five fiscal years, and in the aggregate for the five years thereafter (in thousands).:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Year Ended September 30, | Year Ended September 30, | Year Ended September 30, |
2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 – 2028 | | Total | |
| 2022 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 – 2031 | | Total |
$ | 18,075 | | $ | 7,433 | | $ | 5,684 | | $ | 6,351 | | $ | 6,665 | | $ | 31,813 | | $ | 76,021 | 7,316 | | | $ | 7,731 | | | $ | 8,483 | | | $ | 7,018 | | | $ | 7,406 | | | $ | 30,990 | | | $ | 68,944 | |
Included in the Pension Plan is an unfunded supplemental executive retirement plan.
Investment Strategy and Asset Allocation
Our investment policy and strategies are established with a long-term view in mind. The investment strategy is intended to help pay the cost of the Pension Plan while providing adequate security to meet the benefits promised under the Pension Plan. We maintain a diversified asset mix to minimize the risk of a material loss to the portfolio value that might occur from devaluation of any single investment. In determining the appropriate asset mix, our financial strength and ability to fund potential shortfalls are considered. Pension Plan assets are invested in portfolios of diversified public-market equity securities and fixed income securities. The Pension Plan does not directly hold securities of the Company.
The expected long-term rate of return on Pension Plan assets is based on historical and projected rates of return for current and planned asset classes in the Pension Plan’s investment portfolio after analyzing historical experience and future expectations of the return and volatility of various asset classes.
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 20192022 and the asset allocation for the Pension Plan at the end of fiscal years 20182021 and 2017,2020, by asset category, follows:
| | | | | | | | |
| | | | Percentage | | |
| | | | of Plan | | |
| | Target | | Assets at | | | | | | | | | | | | | | | | |
| | Allocation | | September 30, | | | Target Allocation | | September 30, |
Asset Category | | 2019 | | 2018 | | 2017 | | Asset Category | 2022 | | 2021 | | 2020 |
U.S. equities | | 45 | % | 52 | % | 50 | % | U.S. equities | 17 | % | | 46 | % | | 42 | % |
International equities | | 20 | | 15 | | 16 | | International equities | 12 | | | 17 | | | 22 | |
Fixed income | | 35 | | 33 | | 34 | | Fixed income | 71 | | | 37 | | | 36 | |
Real estate and other | | — | | — | | — | | |
Total | | 100 | % | 100 | % | 100 | % | Total | 100 | % | | 100 | % | | 100 | % |
2021 FORM 10-K|94
The fair value of Pension Plan assets at September 30, 20182021 and 2017,2020, summarized by level within the fair value hierarchy described in Note 12—13—Fair Value Measurement of Financial Instruments, are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value as of September 30, 2018 | | September 30, 2021 |
| | Total | | Level 1 | | Level 2 | | Level 3 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | Total | | Level 1 | | Level 2 | | Level 3 |
Short-term investments | | $ | 2,745 | | $ | 2,745 | | $ | — | | $ | — | Short-term investments | $ | 2,444 | | | $ | 2,444 | | | $ | — | | | $ | — | |
Mutual funds: | | | | | | | | | | | | | Mutual funds: | |
Domestic stock funds | | | 18,361 | | | 18,361 | | | — | | | — | Domestic stock funds | 35,212 | | | 35,212 | | | — | | | — | |
Bond funds | | | 17,918 | | | 17,918 | | | — | | | — | Bond funds | 17,679 | | | 17,679 | | | — | | | — | |
Balanced funds | | | 17,977 | | | 17,977 | | | — | | | — | Balanced funds | 17,520 | | | 17,520 | | | — | | | — | |
International stock funds | | | 14,548 | | | 14,548 | | | — | | | — | International stock funds | 14,379 | | | 14,379 | | | — | | | — | |
Total mutual funds | | | 68,804 | | | 68,804 | | | — | | | — | Total mutual funds | 84,790 | | | 84,790 | | | — | | | — | |
Domestic common stock | | | 23,232 | | | 20,771 | | | 2,461 | | | — | |
Oil and gas properties | | | 116 | | | — | | | — | | | 116 | Oil and gas properties | 21 | | | — | | | — | | | 21 | |
Total | | $ | 94,897 | | $ | 92,320 | | $ | 2,461 | | $ | 116 | Total | $ | 87,255 | | | $ | 87,234 | | | $ | — | | | $ | 21 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value as of September 30, 2017 | | September 30, 2020 |
| | Total | | Level 1 | | Level 2 | | Level 3 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | Total | | Level 1 | | Level 2 | | Level 3 |
Short-term investments | | $ | 3,488 | | $ | 3,488 | | $ | — | | $ | — | Short-term investments | $ | 1,541 | | | $ | 1,541 | | | $ | — | | | $ | — | |
Mutual funds: | | | | | | | | | | | | | Mutual funds: | |
Domestic stock funds | | | 18,377 | | | 18,377 | | | — | | | — | Domestic stock funds | 35,660 | | | 35,660 | | | — | | | — | |
Bond funds | | | 18,357 | | | 18,357 | | | — | | | — | Bond funds | 17,328 | | | 17,328 | | | — | | | — | |
Balanced funds | | | 18,222 | | | 18,222 | | | — | | | — | Balanced funds | 17,447 | | | 17,447 | | | — | | | — | |
International stock funds | | | 14,583 | | | 14,583 | | | — | | | — | International stock funds | 14,044 | | | 14,044 | | | — | | | — | |
Total mutual funds | | | 69,539 | | | 69,539 | | | — | | | — | Total mutual funds | 84,479 | | | 84,479 | | | — | | | — | |
Domestic common stock | | | 19,692 | | | 19,692 | | | — | | | — | |
Oil and gas properties | | | 97 | | | — | | | — | | | 97 | Oil and gas properties | 83 | | | — | | | — | | | 83 | |
Total | | $ | 92,816 | | $ | 92,719 | | $ | — | | $ | 97 | Total | $ | 86,103 | | | $ | 86,020 | | | $ | — | | | $ | 83 | |
The
As of September 30, 2021 and 2020, the Pension Plan’s financial assets utilizing Level 1 inputs are valued based on quoted prices in active markets for identical securities.
The Pension Plan’s Level 2 financial assets include foreign common stock. TheAs of September 30, 2021 and 2020, the Pension Plan’s assets utilizing Level 3 inputs consist of oil and gas properties. The fair value of oil and gas properties is determined by Wells Fargo Bank, N.A., based upon actual revenue received for the previous twelve-month period and experience with similar assets.
The following table sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the fiscal years ended September 30, 2018 and 2017:
| | | | | | |
| | Oil and Gas Properties |
| | Year Ended |
| | September 30, |
| | 2018 | | 2017 |
| | (in thousands) |
Balance, beginning of year | | $ | 97 | | $ | 177 |
Unrealized gains (losses) relating to property still held at the reporting date | | | 19 | | | (80) |
Balance, end of year | | $ | 116 | | $ | 97 |
Defined Contribution Plan
Substantially all employees on the U.S. payroll may elect to participate in our 401(k)/Thrift Plan by contributing a portion of their earnings. We contribute an amount equal to 100 percent of the first
five5 percent of the participant’s compensation subject to certain limitations. The annual expense incurred for this defined contribution plan was
$26.6$13.6 million,
$16.6$23.8 million and
$21.6$30.5 million in fiscal years
2018, 20172021, 2020 and
2016,2019, respectively.
During fiscal year 2016, we determined that employee workforce reductions which started during 2015 and continued into 2016 due to reduced drilling activity resulted in a partial plan termination of the 401(k)/Thrift Plan. Partial plan terminations result in affected participants becoming fully vested in Company contributions and actual earnings thereon at the termination date. As a result of the partial plan termination status, we accrued additional employer contributions totaling $6.3 million in general and administrative expense in fiscal year 2016.
NOTE 14 SUPPLEMENTAL BALANCE SHEET INFORMATION
| | | | | | | | | | | | | | |
| NOTE 15 SUPPLEMENTAL BALANCE SHEET INFORMATION |
The following reflects the activity in our reserve for
bad debtexpected credit losses on trade receivables for fiscal years
2018, 20172021, 2020 and
2016: | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | (in thousands) |
Reserve for bad debt: | | | | | | | | | |
Balance at October 1, | | $ | 5,721 | | $ | 2,696 | | $ | 6,181 |
Provision for (recovery of) bad debt | | | 2,193 | | | 2,016 | | | (2,013) |
(Write-off) recovery of bad debt | | | (1,697) | | | 1,009 | | | (1,472) |
Balance at September 30, | | $ | 6,217 | | $ | 5,721 | | $ | 2,696 |
| | | | | | | | | | | | | | | | | |
| (in thousands) | 2021 | | 2020 | | 2019 |
| Reserve for credit losses: | | | | | |
| Balance at October 1, | $ | 1,820 | | | $ | 9,927 | | | $ | 6,217 | |
| Provision for credit loss | 203 | | | 2,203 | | | 2,321 | |
| (Write-off) recovery of credit loss | 45 | | | (10,310) | | | 1,389 | |
| Balance at September 30, | $ | 2,068 | | | $ | 1,820 | | | $ | 9,927 | |
2021 FORM 10-K|95
Accounts receivable, prepaid expenses and other current assets, accrued liabilities and long-term liabilities at September 30, 20182021 and 20172020 consist of the following:
| | | | | | | | | | | | | | | | |
| | September 30, | | September 30, |
| | 2018 | | 2017 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 |
Accounts receivable, net of reserve: | | | | | | | Accounts receivable, net of reserve: | | | |
Trade receivables | | $ | 530,859 | | $ | 398,348 | Trade receivables | $ | 204,424 | | | $ | 150,249 | |
Income tax receivable | | | 34,343 | | | 78,726 | Income tax receivable | 24,470 | | | 42,374 | |
Total accounts receivable, net of reserve | | $ | 565,202 | | $ | 477,074 | Total accounts receivable, net of reserve | $ | 228,894 | | | $ | 192,623 | |
| | | | | | | |
Prepaid expenses and other current assets: | | | | | | | Prepaid expenses and other current assets: | | | |
Restricted cash | | $ | 39,830 | | $ | 32,439 | Restricted cash | $ | 18,350 | | | $ | 45,577 | |
Deferred mobilization | | | 6,484 | | | 6,458 | Deferred mobilization | 3,734 | | | 4,528 | |
Prepaid insurance | | | 6,149 | | | 4,060 | Prepaid insurance | 7,313 | | | 8,655 | |
Prepaid value added tax | | | 1,931 | | | 3,870 | Prepaid value added tax | 7,682 | | | 7,484 | |
Prepaid maintenance and rent | | | 8,526 | | | 5,940 | Prepaid maintenance and rent | 5,540 | | | 7,273 | |
Prepaid multi-flex rig fabrication | | | 1,327 | | | — | |
| Accrued demobilization, net | | Accrued demobilization, net | 4,513 | | | 2,367 | |
| Prepaid operating expenses | | Prepaid operating expenses | 17,959 | | | — | |
Other | | | 2,151 | | | 2,356 | Other | 20,837 | | | 13,421 | |
Total prepaid expenses and other current assets | | $ | 66,398 | | $ | 55,123 | Total prepaid expenses and other current assets | $ | 85,928 | | | $ | 89,305 | |
Accrued liabilities: | | | | | | | Accrued liabilities: | | | |
Accrued operating costs | | $ | 37,528 | | $ | 36,949 | Accrued operating costs | $ | 20,872 | | | $ | 10,942 | |
Payroll and employee benefits | | | 80,915 | | | 54,941 | Payroll and employee benefits | 69,311 | | | 27,068 | |
Taxes payable, other than income tax | | | 50,683 | | | 35,638 | Taxes payable, other than income tax | 25,329 | | | 39,762 | |
Self-insurance liabilities | | | 15,887 | | | 22,159 | Self-insurance liabilities | 40,060 | | | 36,518 | |
Deferred income | | | 20,527 | | | 25,893 | Deferred income | 8,546 | | | 9,266 | |
Deferred mobilization | | | 9,662 | | | 9,828 | |
| 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 | 4,662 | | | 5,705 | |
Accrued income taxes | | | 7,375 | | | 8,011 | Accrued income taxes | 881 | | | — | |
Escrow | | | 11,258 | | | 4,690 | Escrow | 138 | | | 138 | |
Litigation and claims | | | 1,749 | | | 1,779 | Litigation and claims | 1,463 | | | 393 | |
| Contingent liability | | Contingent liability | 5,985 | | | 4,926 | |
| Operating lease liability | | Operating lease liability | 12,624 | | | 11,364 | |
| Accrued interest | | Accrued interest | 930 | | | 937 | |
Other | | | 8,920 | | | 8,869 | Other | 6,167 | | | 8,423 | |
Total accrued liabilities | | $ | 244,504 | | $ | 208,757 | Total accrued liabilities | $ | 283,492 | | | $ | 155,442 | |
Noncurrent liabilities — Other: | | | | | | | Noncurrent liabilities — Other: | | | |
Pension and other non-qualified retirement plans | | $ | 35,051 | | $ | 37,989 | Pension and other non-qualified retirement plans | $ | 47,263 | | | $ | 54,043 | |
Self-insurance liabilities | | | 39,380 | | | 29,037 | Self-insurance liabilities | 40,910 | | | 37,369 | |
Contingent earnout liability | | | 11,160 | | | 14,879 | |
Deferred mobilization | | | 2,738 | | | 7,689 | |
| Contingent liability | | Contingent liability | 1,759 | | | 4,197 | |
| Deferred revenue | | Deferred revenue | 1,003 | | | 2,955 | |
Uncertain tax positions including interest and penalties | | | 2,870 | | | 3,562 | Uncertain tax positions including interest and penalties | 2,578 | | | 2,895 | |
| Operating lease liability | | Operating lease liability | 37,864 | | | 33,886 | |
Payroll tax deferral1 | | Payroll tax deferral1 | 15,424 | | | 10,205 | |
Other | | | 2,407 | | | 8,253 | Other | 956 | | | 1,630 | |
Total noncurrent liabilities — other | | $ | 93,606 | | $ | 101,409 | Total noncurrent liabilities — other | $ | 147,757 | | | $ | 147,180 | |
(1)Deferral related to the provisions within the Coronavirus Aid, Relief, and Economic Security Act, enacted on March 27, 2020, which allows for the deferral of the employer share of Social Security tax.
NOTE 15 COMMITMENTS AND CONTINGENCIES
| | | | | | | | | | | | | | |
| NOTE 16 COMMITMENTS AND CONTINGENCIES |
Equipment, parts and supplies are ordered in advance to promote efficient construction and capital improvement progress. At September 30,
2018,2021, we had purchase commitments for equipment, parts and supplies of approximately
$110.4$48.1 million.
2021 FORM 10-K|96
Lease Obligations
Refer to Note 5—Leases for additional information on our lease obligations.
We are contingently liable to sureties in respect of bonds issued by the
normal course of our business, we enter into agreements with financial institutions to provide letters of credit and surety bondssureties in connection with certain commitments entered into by
us.us in the normal course of business. We
are contingently liable to these financial institutions in respect of such letters of credit and bonds and have agreed to indemnify the
financial institutionssureties for any payments made by them in respect of such
letters of credit and bonds.
None of these balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements.Lease Obligations
At September 30, 2018, we were leasing our corporate office headquarters near downtown Tulsa, Oklahoma. We also lease other office space and equipment for use in operations.
Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of a year at September 30, 2018 are as follows:
| | | |
| | Amount |
Fiscal Year | | (in thousands) |
2019 | | $ | 9,113 |
2020 | | | 6,670 |
2021 | | | 4,357 |
2022 | | | 3,985 |
2023 | | | 3,721 |
Thereafter | | | 5,095 |
Total | | $ | 32,941 |
Total rent expense was $13.7 million, $14.0 million and $13.5 million for fiscal years 2018, 2017 and 2016, respectively. The future minimum lease payments for our Tulsa corporate office is a material portion of the amounts shown in the table above. This lease agreement commenced on May 30, 2003 and has subsequently been amended, most recently on August 25, 2017. The agreement will expire on January 31, 2025; however, we have two five-year renewal options.
Contingencies
We are party to legal proceedings and regulatory actions from time to time, including a number of cases which are currently pending. We maintain insurance against certain business risks subject to certain deductibles. With the exception of the matters discussed below, none of these legal actions are expected to have a material adverse effect on our financial condition, cash flows or results of operations.
During the ordinary course of our business, contingencies arise resulting from an existing condition, situation or set of circumstances involving an uncertainty as to the realization of a possible gain 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 taking of their Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery. No contingent gains were recognized
The Company and its subsidiaries are parties to various other pending legal actions arising in the ordinary course of our Consolidated Financial Statements duringbusiness. 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 fiscal years ended September 30, 2018, 2017ultimate 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 2016.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 16 BUSINESS SEGMENTS AND GEOGRAPHIC INFORMATION
| | | | | | | | | | | | | | |
| NOTE 17 BUSINESS SEGMENTS AND GEOGRAPHIC INFORMATION |
Description of the Business
We are a
global contractperformance-driven drilling
solutions 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
contract 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.
At September 30, 2018, We focus on offering our contractcustomers 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 drilling business includesservices operations are organized into the following reportable operating business segments:
North America Solutions, Offshore Gulf of Mexico and International Solutions. Each reportable operating segment is a strategic business unit that is managed separately, and consolidated revenues and expenses reflect the elimination of all material intercompany transactions.Other includes additional non-reportable operating segments. Revenues Our real estate operations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are included in “other”"Other." External revenues included in “Other” primarily consist of revenue from our drilling technology services as well as rental income.
We 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 | ·
| | Allocated general and administrative costs
|
•Depreciation and amortization•Allocated general and administrative costs
•Asset impairment charges
•Restructuring charges
but excludes
acquisition related(gain) loss on sale of assets and corporate selling, general and administrative costs, corporate
costs for other depreciation,
income from asset sales and
other corporate
income and expense.restructuring charges.
2021 FORM 10-K|97
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.
Summarized financial information of our reportable segments for continuing operations for each of the fiscal years ended September 30, 2018, 2017 and 2016 is shown in the following table: | | | | | | | | | | | | | | | | | | |
| | September 30, 2018 |
| | | | | | International | | | | | | |
(in thousands) | | U.S. Land | | Offshore | | Land | | Other | | Eliminations | | Total |
External Sales | | $ | 2,068,195 | | $ | 142,500 | | $ | 238,356 | | $ | 38,217 | | $ | - | | $ | 2,487,268 |
Intersegment | | | 1,189 | | | — | | | — | | | 1,026 | | $ | (2,215) | | | - |
Total Sales | | | 2,069,384 | | | 142,500 | | | 238,356 | | | 39,243 | | | (2,215) | | | 2,487,268 |
| | | | | | | | | | | | | | | | | | |
Segment Operating Income (Loss) | | | 150,698 | | | 26,124 | | | (683) | | | (27,790) | | | — | | | 148,349 |
Depreciation and Amortization | | | 505,112 | | | 10,392 | | | 46,826 | | | 21,472 | | | — | | | 583,802 |
Total Assets | | | 5,012,378 | | | 105,439 | | | 362,033 | | | 735,017 | | | — | | | 6,214,867 |
Additions to Long-Lived Assets | | | 441,624 | | | 4,326 | | | 4,424 | | | 18,456 | | | — | | | 468,830 |
| | | | | | | | | | | | | | | | | | |
| | September 30, 2017 |
| | | | | | International | | | | | | |
(in thousands) | | U.S. Land | | Offshore | | Land | | Other | | Eliminations | | Total |
External Sales | | $ | 1,439,523 | | $ | 136,263 | | $ | 212,972 | | $ | 15,983 | | $ | — | | $ | 1,804,741 |
Intersegment | | | — | | | — | | | — | | | 862 | | | (862) | | | — |
Total Sales | | | 1,439,523 | | | 136,263 | | | 212,972 | | | 16,845 | | | (862) | | | 1,804,741 |
| | | | | | | | | | | | | | | | | | |
Segment Operating Income (Loss) | | | (94,880) | | | 24,201 | | | (7,224) | | | (9,449) | | | — | | | (87,352) |
Depreciation and Amortization | | | 499,486 | | | 11,764 | | | 53,622 | | | 20,671 | | | — | | | 585,543 |
Total Assets | | | 4,967,074 | | | 99,533 | | | 413,392 | | | 959,986 | | | — | | | 6,439,985 |
Additions to Long-Lived Assets | | | 394,508 | | | 2,847 | | | 3,400 | | | 7,351 | | | — | | | 408,106 |
| | | | | | | | | | | | | | | | | | |
| | September 30, 2016 |
| | | | | | International | | | | | | |
(in thousands) | | U.S. Land | | Offshore | | Land | | Other | | Eliminations | | Total |
External Sales | | $ | 1,242,462 | | $ | 138,601 | | $ | 229,894 | | $ | 13,275 | | $ | — | | $ | 1,624,232 |
Intersegment | | | — | | | — | | | — | | | 855 | | | (855) | | | — |
Total Sales | | | 1,242,462 | | | 138,601 | | | 229,894 | | | 14,130 | | | (855) | | | 1,624,232 |
| | | | | | | | | | | | | | | | | | |
Segment Operating Income (Loss) | | | 74,118 | | | 15,659 | | | (14,086) | | | (7,491) | | | — | | | 68,200 |
Depreciation and Amortization | | | 508,237 | | | 12,495 | | | 57,102 | | | 20,753 | | | — | | | 598,587 |
Total Assets | | | 5,005,299 | | | 105,152 | | | 487,181 | | | 1,234,323 | | | — | | | 6,831,955 |
Additions to Long-Lived Assets | | | 209,156 | | | 9,694 | | | 2,364 | | | 20,076 | | | — | | | 241,290 |
Summarized financial information of our reportable segments for the fiscal years ended September 30, 2021, 2020 and 2019 is shown in the following tables: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2019 |
| (in thousands) | North America Solutions | | Offshore Gulf of Mexico | | International Solutions | | Other | | Eliminations | | Total |
| External sales | $ | 2,426,191 | | | $ | 147,635 | | | $ | 211,731 | | | $ | 12,933 | | | $ | — | | | $ | 2,798,490 | |
| Intersegment | — | | | — | | | — | | | — | | | — | | | — | |
| Total sales | 2,426,191 | | | 147,635 | | | 211,731 | | | 12,933 | | | — | | | 2,798,490 | |
| | | | | | | | | | | |
| Segment operating income | 80,898 | | | 19,594 | | | 5,366 | | | 3,375 | | | — | | | 109,233 | |
| Depreciation and amortization | 504,466 | | | 10,010 | | | 35,466 | | | 1,523 | | | — | | | 551,465 | |
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, | | Year Ended September 30, |
| | 2018 | | 2017 | | 2016 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | 2019 |
Segment operating income (loss) | | $ | 148,349 | | $ | (87,352) | | $ | 68,200 | Segment operating income (loss) | $ | (303,494) | | | $ | (544,389) | | | $ | 109,233 | |
Income from asset sales | | | 22,660 | | | 20,627 | | | 9,896 | |
Acquisition related costs | | | (8,153) | | | — | | | — | |
Corporate selling, general and administrative costs and corporate depreciation | | | (131,254) | | | (105,816) | | | (104,062) | |
Operating income (loss) | | | 31,602 | | | (172,541) | | | (25,966) | |
| Gain on sale of assets | | Gain on sale of assets | 1,042 | | | 46,775 | | | 39,691 | |
| Corporate selling, general and administrative costs, corporate depreciation and corporate restructuring charges | | Corporate selling, general and administrative costs, corporate depreciation and corporate restructuring charges | (126,097) | | | (122,573) | | | (128,342) | |
| Operating income (loss) from continuing operations | | Operating income (loss) from continuing operations | (428,549) | | | (620,187) | | | 20,582 | |
Other income (expense) | | | | | | | | | | Other income (expense) | |
Interest and dividend income | | | 8,017 | | | 5,915 | | | 3,166 | Interest and dividend income | 10,254 | | | 7,304 | | | 9,468 | |
Interest expense | | | (24,265) | | | (19,747) | | | (22,913) | Interest expense | (23,955) | | | (24,474) | | | (25,188) | |
Gain (loss) on investment securities | | | 1 | | | — | | | (25,989) | Gain (loss) on investment securities | 6,727 | | | (8,720) | | | (54,488) | |
| Gain on sale of subsidiary | | Gain on sale of subsidiary | — | | | 14,963 | | | — | |
Other | | | 486 | | | 1,775 | | | (965) | Other | (5,657) | | | (5,384) | | | (1,596) | |
Total unallocated amounts | | | (15,761) | | | (12,057) | | | (46,701) | Total unallocated amounts | (12,631) | | | (16,311) | | | (71,804) | |
Income (loss) from continuing operations before income taxes | | $ | 15,841 | | $ | (184,598) | | $ | (72,667) | |
| Loss from continuing operations before income taxes | | Loss from continuing operations before income taxes | $ | (441,180) | | | $ | (636,498) | | | $ | (51,222) | |
2021 FORM 10-K|98
The following table reconciles segment total assets to total assets as reported on the Consolidated Balance Sheets:
| | | | | | | | | | | |
| Year Ended September 30, |
| (in thousands) | 2021 | | 2020 |
Total assets1 | | | |
| North America Solutions | $ | 3,418,569 | | | $ | 3,812,718 | |
| Offshore Gulf of Mexico | 84,580 | | | 93,501 | |
| International Solutions | 269,820 | | | 181,181 | |
| Other | 95,398 | | | 22,144 | |
| 3,868,367 | | | 4,109,544 | |
| Investments and corporate operations | 1,165,761 | | | 720,077 | |
| Total assets from continuing operations | $ | 5,034,128 | | | $ | 4,829,621 | |
(1) Assets by segment exclude investments in subsidiaries and intersegment activity.
The following table presents revenues from external customers
and long-lived assets by country based on the location of service provided:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, | | Year Ended September 30, |
| | 2018 | | 2017 | | 2016 | |
| | (in thousands) | |
| (in thousands) | | (in thousands) | 2021 | | 2020 | | 2019 |
Operating revenues | | | | | | | | | | Operating revenues | | | | | |
United States | | $ | 2,247,400 | | $ | 1,591,769 | | $ | 1,386,786 | United States | $ | 1,158,230 | | | $ | 1,626,407 | | | $ | 2,585,008 | |
Argentina | | | 190,038 | | | 157,257 | | | 159,427 | Argentina | 27,855 | | | 84,402 | | | 165,718 | |
| Bahrain | | Bahrain | 27,435 | | | 28,653 | | | 11,528 | |
| United Arab Emirates | | United Arab Emirates | 957 | | | 24,716 | | | 4,728 | |
Colombia | | | 38,793 | | | 37,554 | | | 20,488 | Colombia | 1,674 | | | 6,414 | | | 29,757 | |
Ecuador | | | — | | | 6 | | | 4,948 | |
Other Foreign | | | 11,037 | | | 18,155 | | | 52,583 | |
| Other foreign | | Other foreign | 2,417 | | | 3,335 | | | 1,751 | |
Total | | $ | 2,487,268 | | $ | 1,804,741 | | $ | 1,624,232 | Total | $ | 1,218,568 | | | $ | 1,773,927 | | | $ | 2,798,490 | |
Property, plant and equipment, net | | | | | | | | | | |
United States | | $ | 4,591,913 | | $ | 4,686,235 | | $ | 4,804,328 | |
Argentina | | | 133,617 | | | 155,978 | | | 183,286 | |
Colombia | | | 74,042 | | | 81,798 | | | 91,815 | |
Ecuador | | | 10,781 | | | 22,298 | | | 438 | |
Other Foreign | | | 47,029 | | | 54,742 | | | 64,866 | |
Total | | $ | 4,857,382 | | $ | 5,001,051 | | $ | 5,144,733 | |
NOTE 17 GUARANTOR AND NON-GUARANTOR FINANCIAL INFORMATION
In March 2015, Helmerich & Payne International Drilling Co. (“
The following table presents property, plant and equipment by country based on the
issuer”), a 100 percent owned subsidiarylocation of
Helmerich & Payne, Inc. (“parent”, “the guarantor”), issued senior unsecured notes with an aggregate principal amount of $500.0 million. The notes are fully and unconditionally guaranteed by the parent. No subsidiaries of the parent currently guarantee the notes, subject to certain provisions that if any subsidiary guarantees certain other debt of the issuer or parent, then such subsidiary will provide a guarantee of the obligation under the notes.In connection with the notes, we are providing the following condensed consolidating financial information in accordance with the Securities and Exchange Commission disclosure requirements, so that separate financial statements of the issuer are not required to be filed. Each entity in the consolidating financial information follows the same accounting policies as described in the consolidated financial statements. Condensed consolidating financial information for the issuer, Helmerich & Payne International Drilling Co., and parent, guarantor, Helmerich & Payne, Inc. is shown in the tables below.
service provided: | | | | | | | | | | | |
| Year Ended September 30, |
| (in thousands) | 2021 | | 2020 |
| Property, plant and equipment, net | | | |
| United States | $ | 3,042,140 | | | $ | 3,562,525 | |
| Argentina | 50,944 | | | 49,419 | |
| Colombia | 22,959 | | | 21,740 | |
| Other foreign | 11,244 | | | 12,657 | |
| Total | $ | 3,127,287 | | | $ | 3,646,341 | |
CONDENSED CONSOLIDATING BALANCE SHEETS
| | | | | | | | | | | | | | | |
| | September 30, 2018 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | Subsidiaries | | Eliminations | | Consolidated |
| | | | | | | | | | | | | | | |
Assets | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | — | | $ | 273,214 | | $ | 11,141 | | $ | — | | $ | 284,355 |
Short-term investments | | | — | | | 41,461 | | | — | | | — | | | 41,461 |
Accounts receivable, net of allowance | | | (29) | | | 499,644 | | | 65,859 | | | (272) | | | 565,202 |
Inventories of materials and supplies | | | — | | | 127,154 | | | 30,980 | | | — | | | 158,134 |
Prepaid expenses and other | | | 20,783 | | | 10,649 | | | 35,539 | | | (573) | | | 66,398 |
Total current assets | | | 20,754 | | | 952,122 | | | 143,519 | | | (845) | | | 1,115,550 |
| | | | | | | | | | | | | | | |
Investments | | | 16,200 | | | 82,496 | | | — | | | — | | | 98,696 |
Property, plant and equipment, net | | | 46,859 | | | 4,515,077 | | | 295,446 | | | — | | | 4,857,382 |
Intercompany receivables | | | 161,532 | | | 2,024,652 | | | 294,206 | | | (2,480,390) | | | — |
Goodwill | | | — | | | — | | | 64,777 | | | — | | | 64,777 |
Intangible assets, net | | | — | | | — | | | 73,207 | | | — | | | 73,207 |
Other assets | | | 268 | | | 907 | | | 4,080 | | | — | | | 5,255 |
Investment in subsidiaries | | | 5,981,197 | | | 172,513 | | | — | | | (6,153,710) | | | — |
| | | | | | | | | | | | | | | |
Total assets | | $ | 6,226,810 | | $ | 7,747,767 | | $ | 875,235 | | $ | (8,634,945) | | $ | 6,214,867 |
| | | | | | | | | | | | | | | |
Liabilities and Shareholders' Equity | | | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | | | |
Accounts payable | | $ | 83,819 | | $ | 43,626 | | $ | 5,483 | | $ | (264) | | $ | 132,664 |
Accrued liabilities | | | 43,449 | | | 164,542 | | | 37,093 | | | (580) | | | 244,504 |
Total current liabilities | | | 127,268 | | | 208,168 | | | 42,576 | | | (844) | | | 377,168 |
| | | | | | | | | | | | | | | |
Noncurrent liabilities: | | | | | | | | | | | | | | | |
Long-term debt | | | — | | | 493,968 | | | — | | | — | | | 493,968 |
Deferred income taxes | | | (7,112) | | | 834,714 | | | 25,534 | | | — | | | 853,136 |
Intercompany payables | | | 1,701,694 | | | 178,759 | | | 599,837 | | | (2,480,290) | | | — |
Other | | | 22,225 | | | 48,836 | | | 22,545 | | | — | | | 93,606 |
Noncurrent liabilities - discontinued operations | | | — | | | — | | | 14,254 | | | — | | | 14,254 |
Total noncurrent liabilities | | | 1,716,807 | | | 1,556,277 | | | 662,170 | | | (2,480,290) | | | 1,454,964 |
| | | | | | | | | | | | | | | |
Shareholders’ equity: | | | | | | | | | | | | | | | |
Common stock | | | 11,201 | | | 100 | | | — | | | (100) | | | 11,201 |
Additional paid-in capital | | | 500,393 | | | 52,437 | | | 1,040 | | | (53,477) | | | 500,393 |
Retained earnings | | | 4,027,779 | | | 5,910,955 | | | 169,449 | | | (6,080,404) | | | 4,027,779 |
Accumulated other comprehensive income | | | 16,550 | | | 19,830 | | | — | | | (19,830) | | | 16,550 |
Treasury stock, at cost | | | (173,188) | | | — | | | — | | | — | | | (173,188) |
Total shareholders’ equity | | | 4,382,735 | | | 5,983,322 | | | 170,489 | | | (6,153,811) | | | 4,382,735 |
| | | | | | | | | | | | | | | |
Total liabilities and shareholders’ equity | | $ | 6,226,810 | | $ | 7,747,767 | | $ | 875,235 | | $ | (8,634,945) | | $ | 6,214,867 |
| | | | | | | | | | | | | | | |
| | September 30, 2017 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | Subsidiaries | | Eliminations | | Consolidated |
| | | | | | | | | | | | | | | |
Assets | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | — | | $ | 507,504 | | $ | 13,871 | | $ | — | | $ | 521,375 |
Short-term investments | | | — | | | 44,491 | | | — | | | — | | | 44,491 |
Accounts receivable, net of allowance | | | 766 | | | 411,599 | | | 64,714 | | | (5) | | | 477,074 |
Inventories of materials and supplies | | | — | | | 102,470 | | | 34,734 | | | — | | | 137,204 |
Prepaid expenses and other | | | 12,200 | | | 6,383 | | | 36,982 | | | (442) | | | 55,123 |
Total current assets | | | 12,966 | | | 1,072,447 | | | 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 receivables | | | 90,885 | | | 1,746,662 | | | 248,540 | | | (2,086,087) | | | — |
Goodwill | | | — | | | — | | | 51,705 | | | — | | | 51,705 |
Intangible assets, net | | | — | | | — | | | 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 | | $ | 5,642,560 | | $ | 7,685,647 | | $ | 851,747 | | $ | (7,739,966) | | $ | 6,439,988 |
| | | | | | | | | | | | | | | |
Liabilities and Shareholders' Equity | | | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | | | |
Accounts payable | | $ | 82,947 | | $ | 48,092 | | $ | 4,589 | | $ | — | | $ | 135,628 |
Accrued liabilities | | | 26,698 | | | 148,491 | | | 34,015 | | | (447) | | | 208,757 |
Total current liabilities | | | 109,645 | | | 196,583 | | | 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 payables | | | 1,354,068 | | | 210,823 | | | 521,096 | | | (2,085,987) | | | — |
Other | | | 25,457 | | | 43,471 | | | 32,481 | | | — | | | 101,409 |
Noncurrent liabilities - 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 | | $ | 5,642,560 | | $ | 7,685,647 | | $ | 851,747 | | $ | (7,739,966) | | $ | 6,439,988 |
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
| | | | | | | | | | | | | | | |
| | Year Ended September 30, 2018 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | Subsidiaries | | Eliminations | | Consolidated |
| | | | | | | | | | | | | | | |
Operating revenue | | $ | — | | $ | 2,210,695 | | $ | 276,660 | | $ | (87) | | $ | 2,487,268 |
Operating costs and other | | | 14,276 | | | 2,120,465 | | | 321,863 | | | (938) | | | 2,455,666 |
| | | | | | | | | | | | | | | |
Operating income (loss) from continuing operations | | | (14,276) | | | 90,230 | | | (45,203) | | | 851 | | | 31,602 |
| | | | | | | | | | | | | | | |
Other income (expense), net | | | 526 | | | 7,363 | | | 1,466 | | | (851) | | | 8,504 |
Interest expense | | | (499) | | | (20,426) | | | (3,340) | | | — | | | (24,265) |
Equity in net income (loss) of subsidiaries | | | 498,055 | | | (11,039) | | | — | | | (487,016) | | | — |
Income (loss) from continuing operations before income taxes | | | 483,806 | | | 66,128 | | | (47,077) | | | (487,016) | | | 15,841 |
| | | | | | | | | | | | | | | |
Income tax (benefit) provision | | | 1,134 | | | (448,613) | | | (29,690) | | | — | | | (477,169) |
Income (loss) from continuing operations | | | 482,672 | | | 514,741 | | | (17,387) | | | (487,016) | | | 493,010 |
| | | | | | | | | | | | | | | |
Income from discontinued operations before income taxes | | | — | | | — | | | 23,389 | | | — | | | 23,389 |
Income tax provision | | | — | | | — | | | 33,727 | | | — | | | 33,727 |
Loss from discontinued operations | | | — | | | — | | | (10,338) | | | — | | | (10,338) |
| | | | | | | | | | | | | | | |
Net income (loss) | | $ | 482,672 | | $ | 514,741 | | $ | (27,725) | | $ | (487,016) | | $ | 482,672 |
| | | | | | | | | | | | | | | |
| | Year Ended September 30, 2017 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | 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 | | | — |
Income (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) |
Income (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 income (loss) | | $ | (128,212) | | $ | (113,892) | | $ | (10,332) | | $ | 124,224 | | $ | (128,212) |
| | | | | | | | | | | | | | | |
| | Year Ended September 30, 2016 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | 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 (benefit) provision | | | (4,052) | | | 5,127 | | | (20,752) | | | — | | | (19,677) |
Income (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 income (loss) | | $ | (56,828) | | $ | (46,856) | | $ | (14,782) | | $ | 61,638 | | $ | (56,828) |
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
| | | | | | | | | | | | | | | |
| | Year Ended September 30, 2018 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | Subsidiaries | | Eliminations | | Consolidated |
| | | | | | | | | | | | | | | |
Net income (loss) | | $ | 482,672 | | $ | 514,741 | | $ | (27,725) | | $ | (487,016) | | $ | 482,672 |
Other comprehensive income, net of income taxes: | | | | | | | | | | | | | | | |
Unrealized appreciation on securities, net | | | — | | | 9,001 | | | — | | | — | | | 9,001 |
Minimum pension liability adjustments, net | | | 1,137 | | | 4,112 | | | — | | | — | | | 5,249 |
Other comprehensive income | | | 1,137 | | | 13,113 | | | — | | | — | | | 14,250 |
Comprehensive income (loss) | | $ | 483,809 | | $ | 527,854 | | $ | (27,725) | | $ | (487,016) | | $ | 496,922 |
| | | | | | | | | | | | | | | |
| | Year Ended September 30, 2017 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | 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 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | 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) |
| | | | | | | | | | | | | | | |
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | |
| | Year Ended September 30, 2018 |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | Subsidiaries | | Eliminations | | Consolidated |
| | | | | | | | | | | | | | | |
Net cash provided by operating activities | | $ | 759 | | $ | 539,476 | | $ | 4,296 | | $ | — | | $ | 544,531 |
| | | | | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | |
Capital expenditures | | | (12,723) | | | (443,743) | | | (10,118) | | | — | | | (466,584) |
Purchase of short-term investments | | | — | | | (71,049) | | | — | | | — | | | (71,049) |
Payment for acquisition of business, net of cash acquired | | | (47,886) | | | — | | | — | | | — | | | (47,886) |
Proceeds from sale of short-term investments | | | — | | | 68,776 | | | — | | | — | | | 68,776 |
Intercompany transfers | | | 60,609 | | | (60,609) | | | — | | | — | | | — |
Proceeds from asset sales | | | — | | | 41,289 | | | 3,092 | | | — | | | 44,381 |
Net cash used in investing activities | | | — | | | (465,336) | | | (7,026) | | | — | | | (472,362) |
| | | | | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | |
Intercompany transfers | | | 308,430 | | | (308,430) | | | — | | | — | | | — |
Dividends paid | | | (308,430) | | | — | | | — | | | — | | | (308,430) |
Payments for employee taxes on net settlement of equity awards | | | (7,114) | | | — | | | — | | | — | | | (7,114) |
Proceeds from stock option exercises | | | 6,355 | | | — | | | — | | | — | | | 6,355 |
Net cash provided by (used in) financing activities | | | (759) | | | (308,430) | | | — | | | — | | | (309,189) |
| | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | — | | | (234,290) | | | (2,730) | | | — | | | (237,020) |
Cash and cash equivalents, beginning of period | | | — | | | 507,504 | | | 13,871 | | | — | | | 521,375 |
Cash and cash equivalents, end of period | | $ | — | | $ | 273,214 | | $ | 11,141 | | $ | — | | $ | 284,355 |
| | | | | | | | | | | | | | | |
| | Year Ended September 30, 2017, as adjusted |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | Subsidiaries | | Eliminations | | Consolidated |
| | | | | | | | | | | | | | | |
Net cash (used in) provided by operating activities | | $ | (4,686) | | $ | 354,711 | | $ | 11,606 | | $ | — | | $ | 361,631 |
| | | | | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | |
Capital expenditures | | | (4,264) | | | (387,392) | | | (5,911) | | | — | | | (397,567) |
Purchase of short-term investments | | | — | | | (69,866) | | | — | | | — | | | (69,866) |
Payment for acquisition of business, net cash acquired | | | (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) |
| | | | | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | |
Intercompany transfers | | | 305,515 | | | (305,515) | | | — | | | — | | | — |
Dividends paid | | | (305,515) | | | — | | | — | | | — | | | (305,515) |
Payments for employee taxes on net settlement of equity awards | | | (6,599) | | | — | | | — | | | — | | | (6,599) |
Proceeds from stock option exercises | | | 11,285 | | | — | | | — | | | — | | | 11,285 |
Net cash provided by (used in) financing activities | | | 4,686 | | | (305,515) | | | — | | �� | — | | | (300,829) |
| | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | — | | | (390,569) | | | 6,383 | | | — | | | (384,186) |
Cash and cash equivalents, beginning of period | | | — | | | 898,073 | | | 7,488 | | | — | | | 905,561 |
Cash and cash equivalents, end of period | | $ | — | | $ | 507,504 | | $ | 13,871 | | $ | — | | $ | 521,375 |
| | | | | | | | | | | | | | | |
| | September 30, 2016, as adjusted |
| | | | Helmerich & Payne | | | | | | | |
| | Helmerich & Payne, Inc. | | International Drilling Co. | | Non-Guarantor | | | | | Total |
(In thousands) | | (Guarantor) | | (Issuer) | | Subsidiaries | | Eliminations | | Consolidated |
| | | | | | | | | | | | | | | |
Net cash provided by (used in) operating activities | | $ | 2,863 | | $ | 777,756 | | $ | (26,088) | | $ | — | | $ | 754,531 |
| | | | | | | | | | | | | | | |
Cash flows from 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) |
| | | | | | | | | | | | | | | |
Cash flows from 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) |
Payments from employee taxes on net settlement of equity awards | | | (5,646) | | | — | | | — | | | — | | | (5,646) |
Proceeds from stock option exercises | | | 2,774 | | | — | | | — | | | — | | | 2,774 |
Net cash used in financing activities | | | (2,872) | | | (341,263) | | | — | | | — | | | (344,135) |
| | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | — | | | 205,638 | | | (29,461) | | | — | | | 176,177 |
Cash and cash equivalents, beginning of period | | | — | | | 692,435 | | | 36,949 | | | — | | | 729,384 |
Cash and cash equivalents, end of period | | $ | — | | $ | 898,073 | | $ | 7,488 | | $ | — | | $ | 905,561 |
NOTE 18 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
(in thousands, except per share amounts)
| | | | | | | | | | | | | | | |
2018 | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total (1) |
Operating revenues | | $ | 564,087 | | $ | 577,484 | | $ | 648,872 | | $ | 696,825 | | $ | 2,487,268 |
Operating income (loss) | | | 3,520 | | | (1,253) | | | 6,217 | | | 23,118 | | | 31,602 |
Income (loss) from continuing operations | | | 500,642 | | | (1,633) | | | (8,174) | | | 2,175 | | | 493,010 |
Net income (loss) | | | 500,106 | | | (11,879) | | | (8,008) | | | 2,453 | | | 482,672 |
Basic earnings per common share: | | | | | | | | | | | | | | | |
Income (loss) from continuing operations | | | 4.57 | | | (0.03) | | | (0.08) | | | 0.02 | | | 4.49 |
Net income (loss) | | | 4.57 | | | (0.12) | | | (0.08) | | | 0.02 | | | 4.39 |
Diluted earnings per common share: | | | | | | | | | | | | | | | |
Income (loss) from continuing operations | | | 4.55 | | | (0.03) | | | (0.08) | | | 0.02 | | | 4.47 |
Net income (loss) | | | 4.55 | | | (0.12) | | | (0.08) | | | 0.02 | | | 4.37 |
| (1)
| | The sum of earnings per share for the four quarters may not equal the total earnings per share for the fiscal year due to changes in the average number of common shares outstanding.
| | | | | | | | | | | |
| NOTE 18 RESTRUCTURING CHARGES |
In the first quarter of fiscal year 2018, net income includes a tax benefit of approximately $502.1 million, or $4.59 per share on a diluted basis, an after-tax gain from the sale of assets of $4.2 million, or $0.04 per share on a diluted basis. In
During the second quarter of fiscal year 2018, net loss includes an after-tax gain from2021, 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 $3.8 million, or $0.04 per share on a diluted basis. Inone-time severance benefits to employees who were involuntarily terminated. During the third quarter of fiscal year 2018, net loss includes an after-tax gain from the sale of assets of $3.1 million, or $0.02 per share2021, we commenced a voluntary separation program at our local office in Argentina for which we incurred one-time severance charges for employees who were voluntarily terminated.
Additionally, we continue to take measures to lower our cost structure based on a diluted basis. In the fourth quarter ofactivity levels. During fiscal year 2018, net loss includes an after-tax gain from2021, we incurred one-time moving related expenses primarily due to the saledownsizing and relocation of assetsour Houston assembly facility and various storage yards used for idle rigs. These charges are included in other restructuring expenses within the tables below.
2021 FORM 10-K|99
| | | | | | | | | | | | | | | |
2017 | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total (1) |
Operating revenues | | $ | 368,590 | | $ | 405,283 | | $ | 498,564 | | $ | 532,304 | | $ | 1,804,741 |
Operating loss | | | (49,164) | | | (65,672) | | | (28,028) | | | (29,677) | | | (172,541) |
Loss from continuing operations | | | (34,554) | | | (48,473) | | | (23,125) | | | (21,711) | | | (127,863) |
Net loss | | | (35,063) | | | (48,818) | | | (21,799) | | | (22,532) | | | (128,212) |
Basic earnings per common share: | | | | | | | | | | | | | | | |
Loss from continuing operations | | | (0.33) | | | (0.45) | | | (0.22) | | | (0.20) | | | (1.20) |
Net loss | | | (0.33) | | | (0.45) | | | (0.21) | | | (0.21) | | | (1.20) |
Diluted earnings per common share: | | | | | | | | | | | | | | | |
Loss from continuing operations | | | (0.33) | | | (0.45) | | | (0.22) | | | (0.20) | | | (1.20) |
Net loss | | | (0.33) | | | (0.45) | | | (0.21) | | | (0.21) | | | (1.20) |
| (1)
| | The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding.
|
InThe following table summarizes the first quarter of fiscalCompany's restructuring charges incurred during the year 2017, net loss includes an after-tax gain from the sale of assets of $0.6 million, or $0.01 per share on a diluted basis. In the second quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $10.1 million, or $0.09 per share on a diluted basis. Inended 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 year 2017, net loss includes2020, we implemented cost controls and began evaluating further measures to respond to the combination of weakened commodity prices, uncertainties related to the COVID-19 pandemic, and the resulting market volatility. We restructured our operations to accommodate scale during an after-tax gain fromindustry downturn and to re-organize our operations to align to new marketing and management strategies. We commenced a number of restructuring efforts as a result of this evaluation, which included, among other things, a reduction in our capital allocation plans, changes to our organizational structure, and a reduction of staffing levels. Costs incurred as of September 30, 2020 in connection with the salerestructuring were primarily comprised of assetsone-time severance benefits to employees who were voluntarily or involuntarily terminated, benefits related to forfeitures and costs related to modification of $1.3 million, or $0.01 per sharestock-based compensation awards.
The 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 a diluted basis. Inour Consolidated Statements of Operations for the fourth quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $2.3 million, or $0.02 per share on a diluted basis.years ended September 30, 2021 and 2020.
NOTE 19 SUBSEQUENT EVENTS
| | | | | | | | | | | | | | |
| NOTE 19 SUBSEQUENT EVENTS |
On October 27, 2021, we redeemed all of the outstanding 2025 Notes, which resulted in the principal payment of $487.1 million, a make-whole premium and accrued interest payment of $58.1 million and the write off of unamortized discount and debt issuance costs of $3.7 million, which will be recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 redemption. Additional details are fully discussed in Note 7—Debt.
Subsequent to September 30, 2021, we sold the assets associated with 2 lower margin service offerings, trucking and casing running services, which contributed approximately 2.8 percent to our consolidated revenues during fiscal year 2021, in 2 separate transactions. The sale of our trucking services was completed on November 3, 2021 while the sale of our casing running services was completed on November 15, 2021 for combined cash consideration less costs to sell of $5.8 million, in addition to the possibility of future earnout revenue.
On November 13, 2018,12, 2021, we entered into the 2018 Credit Facility, which will mature on November 13, 2023.settled a drilling contract dispute with YPF S.A. (Argentina). The 2018 Credit Facility has $750 million in aggregate availability withsettlement requires that YPF make a maximum of $75 million available for use as letters of credit. The 2018 Credit Facility also permits aggregate commitments under the facilityone-time cash payment to be increased by $300 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The 2018 Credit Facility is currently guaranteed by our wholly-owned direct subsidiary, HPIDC, which guarantee is subject to release following certain events set forth in the 2018 Credit Facility. The borrowings under the 2018 Credit Facility accrue interest at a spread over either the London Interbank Offered Rate (LIBOR) or the Base Rate. We also pay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined based on the debt rating for senior unsecured debt of the Company or HPIDC as determined by Moody’s and S&P. The spread over LIBOR ranges from 0.875 percent to 1.500 percent per annum and commitment fees range from 0.075 percent to 0.200 percent per annum. Based on the unsecured debt rating of HPIDC on September 30, 2018, the
spread over LIBOR would have been 1.125 percent and commitment fees would have been 0.125 percent. There is a financial covenant in the 2018 Credit Facility that requires us to maintain a total debt to total capitalization ratio of less than 50 percent. The 2018 Credit Facility contains additional terms, conditions, restrictions and covenants that we believe are usual and customary in unsecured debt arrangements for companies of similar size and credit quality, including a limitation that priority debt (as defined in the credit agreement) may not exceed 17.5 percent of the net worth of the Company. As of the closing, there were no borrowings, but there were three letters of credit outstandingH&P in the amount of $38.0approximately $11.0 million and we had $712.0 million available to borrow under the 2018 Credit Facility.
In connectionenter into drilling service contracts for 3 drilling rigs, each with entering into the 2018 Credit Facility, we terminated our $300 million unsecured credit facility under the credit agreement dated as of July 13, 2016 by and among HPIDC, as borrower, the Company, as guarantor, Wells Fargo, National Association, as administrative agent, and the lenders party thereto.
multi-year terms.106
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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
| | | | | | | | | | | | | | |
| ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
Item | | | | | | | | | | | | | | |
ITEM 9A. CONTROLS AND PROCEDURES | a)
| | Evaluation of Disclosure Controls and Procedures.
|
a) Evaluation of Disclosure Controls and Procedures. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of the end of the period covered by this report have been designed and are effective at the reasonable assurance level so that the information required to be disclosed by us in our periodic SEC filings, is recorded, processed, summarized and reported within the time periods specific in the SEC’s rules, regulations, and forms and is communicated to management. We believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. | b)
| | b) Management’s Report on Internal Control over Financial Reporting. |
A copy of our Management’s Report on Internal Control over Financial Reporting is included in Item 8 of this Form 10-K. | c)
| | c) Attestation Report of the Independent Registered Public Accounting Firm. |
A copy of the report of Ernst & Young LLP, our independent registered public accounting firm, is included in Item 8 of this Form 10-K. | d)
| | d) Changes in Internal Control Over Financial Reporting. |
Item 9B. OTHER INFORMATION
None.
| | | | | | | | | | | | | | | | ITEM 9B. OTHER INFORMATION |
| | | | | | | | | | | | | | | | ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS |
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
| | | | | | | | | | | | | | | | ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The information required by this item is incorporated herein by reference to the material under the captions “Proposal 1—Election of Directors,” “Corporate Governance,”Governance” and “Executive Officers of the Company” in Part I and “Section 16(a) Beneficial Ownership Reporting Compliance”Officers” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019,in calendar year 2022, to be filed with the SEC not later than 120 days after September 30, 2018.2021. We have adopted a Code of Ethics for Principal Executive Officer and Senior Financial Officers. The text of this code is located on our website under “Corporate Governance.“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. 2021 FORM 10-K|101
Item 11. EXECUTIVE COMPENSATION
| | | | | | | | | | | | | | | | ITEM 11. EXECUTIVE COMPENSATION |
The information required by this item regarding executive compensation, as well as director compensation and compensation committee interlocks and insider participation, is incorporated herein by reference to the material beginning with the caption “Executive Compensation Discussion and Analysis”“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 2018”Year 2021” and “Corporate Governance—Compensation Committee Interlocks and Insider Participation” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019,in calendar year 2022, to be filed with the SEC not later than 120 days after September 30, 2018.2021. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
| | | | | | | | | | | | | | | | ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The information required by this item is incorporated herein by reference to the material under the captions “Summary of All Existing Equity Compensation Plans,” “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Directors and Management” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019,in calendar year 2022, to be filed with the SEC not later than 120 days after September 30, 2018.2021. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
| | | | | | | | | | | | | | | | ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
The information required by this item is incorporated herein by reference to the material under the captions “Corporate Governance—Transactions With Related Persons, Promoters and Certain Control Persons” and “Corporate Governance—Director Independence” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019,in calendar year 2022, to be filed with the SEC not later than 120 days after September 30, 2018.2021. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
| | | | | | | | | | | | | | | | ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The information required by this item is incorporated herein by reference to the material under the caption “Proposal 2—Ratification of Appointment of Independent Auditors—Audit Fees” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019,in calendar year 2022, to be filed with the SEC not later than 120 days after September 30, 2018.2021.PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
| | | | | | | | | | | | | | | | ITEM 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 16, 2018,18, 2021, are listed below and included in Item 8—“Financial “Financial Statements and Supplementary Data” of this Form 10‑10‑K. | | | | | | | | Page | | | 56 | | 2020 | 58 | | 2019 | 59 | | 2019 | 60 | | 2019 | 61 | | 2019 | 62 | | | 63 |
2.Financial Statement Schedules: All schedules are omitted because they are not applicable or required or because the required information is contained in the financial statements or included in the notes thereto. 3.Exhibits.Exhibits: The following documents are included as exhibits to this Form 10‑10‑K. Exhibits incorporated by reference are duly noted as such. 2021 FORM 10-K|102
2021 FORM 10-K|103
| | | | | | *10.20 10.11 | | | | | | *10.21 10.12 | | | | | | *10.22 10.13 | | | | | | *10.23 10.14 | | | | | | 21*10.15 | | | | | *10.16 | | | | | *10.17 | | | | | *10.18 | | | | | *10.19 | | | | | *10.20 | | | | | *10.21 | | | | | 21 | | | | | | 23.1 | | | | | | | 31.1 | | | | | | | 31.2 | | | | | | 32.
32 | | | | | | | 101 | | Financial statements from this Form 10‑10‑K formatted in 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). |
*Management or Compensatory Plan or Arrangement. Item | | | | | | | | | | | | | | | | ITEM 16. FORM 10-K SUMMARY |
None. 2021 FORM 10-K SUMMARYNone.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized: | | | | | | | | | | HELMERICH & PAYNE, INC. | | | | By: | /s/ John W. Lindsay | | | John W. Lindsay, | | | Director, President and Chief Executive Officer | | | | Date: November 16, 2018 18, 2021 | |
2021 FORM 10-K|106
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated: Signature
| | Title
| | Date
| | | | | | | | | | | | Signature | | Title | | Date | | | | | | | /s/ John W. Lindsay | | Director, President and Chief Executive Officer | | November 16, 2018 18, 2021 | John W. Lindsay | | Officer (Principal(Principal Executive Officer)
| | | | | | | | /s/ Mark W. Smith | | Senior Vice President and Chief Financial Officer | | November 16, 2018 18, 2021 | Mark W. Smith | | (Principal Financial OfficerOfficer) | | | | | | | | | /s/ Sara M. Momper | | Vice President and Chief Accounting Officer | | November 18, 2021 | | Sara M. Momper | | (Principal Accounting Officer) | | | | | | | | /s/ Hans Helmerich | | Director and Chairman of the Board | | November 16, 2018 18, 2021 | Hans Helmerich | | | | | | | | | | /s/ DelanyDelaney Bellinger | | Director | | November 16, 2018 18, 2021 | DelanyDelaney Bellinger
| | | | | | | | | | /s/ Belgacem Chariag | | Director | | November 18, 2021 | | Belgacem Chariag | | | | | | | | | | | /s/ Kevin G. Cramton | | Director | | November 16, 2018 18, 2021 | Kevin G. Cramton | | | | | | | | | | /s/ Randy A. Foutch | | Director | | November 16, 2018 18, 2021 | Randy A. Foutch | | | | | | | | | | /s/ Paula Marshall
| | Director
| | November 16, 2018
| Paula Marshall
| | | | | | | | | | /s/ Jose R. Mas | | Director | | November 16, 2018 18, 2021 | Jose R. Mas | | | | | | | | | | /s/ Thomas A. Petrie | | Director | | November 16, 2018 18, 2021 | Thomas A. Petrie | | | | | | | | | | /s/ Donald F. Robillard, Jr. | | Director | | November 16, 2018 18, 2021 | Donald F. Robillard, Jr. | | | | | | | | | | /s/ Edward B. Rust, Jr. | | Director | | November 16, 2018 18, 2021 | Edward B. Rust, Jr. | | | | | | | | | | /s/ Mary M. VanDeWeghe | | Director | | November 18, 2021 | | Mary M. VanDeWeghe | | | | | | | | | | | /s/ John D. Zeglis | | Director | | November 16, 2018 18, 2021 | John D. Zeglis | | | | |
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