SECURITIES AND EXCHANGE COMMISSION
☒
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| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended September 30, 2020
OR
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For the fiscal year ended September 30, 2018
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| ☐ | OR
|
☐
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
|
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
|
Delaware | 73-0679879 |
(State or Other Jurisdictionother jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Incorporation or Organization)
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1437 S. Boulder Ave., Suite 1400, Tulsa, Oklahoma
| 74119‑3623
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(Address of Principal Executive Offices)
| (Zip Code)
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(918) 742‑5531
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Registrant’s telephone number, including area code
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1437 South Boulder Avenue, Suite 1400, Tulsa, Oklahoma74119
(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:
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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‑well‑known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☒ No ☐ Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐No☒ Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No ☐ Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☒ No ☐Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☐
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a
non‑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, 2020, the last business day of the Registrant’s most recently completed second fiscal quarter, the aggregate market value of the Registrant’s common stock held by
non‑non‑affiliates was approximately $7.25$1.68 billion based on the closing price of such stock on the New York Stock Exchange on such date of $66.56.$15.65.
Number of shares of common stock outstanding at November 8, 2018: 109,038,462DOCUMENTS INCORPORATED BY REFERENCE
12, 2020: 107,601,988
Portions of the Registrant’s 20192020 Proxy Statement for the Annual Meeting of Stockholders to be held on March 5, 20192, 2021 are incorporated by reference into Part III of this Form 10‑10‑K. The 20192020 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.
INDEX TO FORM
10‑10‑KYEAR ENDED SEPTEMBER 30, 2018
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;
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our business strategy; | ·
| | the volatility of future oil and natural gas prices;
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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;
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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;
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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;
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the volatility of future oil and natural gas prices; | ·
| | expansion and growth of our business and operations;
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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;
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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;
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the effect, impact, potential duration or other implications of the ongoing outbreak of a novel strain of coronavirus ("COVID-19") and the oil price collapse in 2020, and any expectations we may have with respect thereto; | ·
| | 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;
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changes in worldwide rig supply and demand, competition, or technology; | ·
| | our financial condition and liquidity;
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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
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expansion and growth of our business and operations; | ·
| | potential long-lived asset impairments.
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our belief that the final outcome of our legal proceedings will not materially affect our financial results;impact of federal and state legislative and regulatory actions, including as a result of the U.S. presidential election, affecting our costs and increasing operation restrictions or delay and other adverse impacts on our business;
environmental or other liabilities, risks, damages or losses, whether related to storms or hurricanes (including wreckage or debris removal), collisions, grounding, blowouts, fires, explosions, other accidents, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;
our financial condition and liquidity;
tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes; and
potential long-lived asset impairments.
Important factors that could cause actual results to differ materially from our expectations or results discussed in the forward‑forward‑looking statements are disclosed in this Form 10‑10‑K under Item 1A—1A— “Risk Factors,” as well as in Factors” and Item 7—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. 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:
North America Solutions, Offshore Gulf of Mexico, and International Solutions. During the third quarter of fiscal year 2020, as part of our restructuring efforts (see Note 19—Restructuring Charges to our Consolidated Financial Statements) and consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, we implemented organizational changes. We are moving from a product-based offering, such as a rig or separate technology package, to an integrated solution-based approach by combining proprietary rig technology, automation software, and digital expertise into our rig operations. Operations previously reported within the former U.S. Land
Offshore and
International Land. DuringH&P Technologies operating and reportable segments are now managed and presented within 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.America Solutions reportable segment. 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.
During the fiscal year ended September 30, 2020, our North America Solutions operations were primarily located in Colorado, Ohio, Oklahoma, New Mexico, North Dakota, Pennsylvania, Texas, West Virginia and Wyoming. Our
researchOffshore Gulf of Mexico operations were conducted in Louisiana and
development endeavors include ongoing improvementsin U.S. federal waters in the Gulf of
our rig fleetMexico. Our International Solutions operations had rigs located in four international locations during fiscal year 2020: Argentina, Bahrain, Colombia and
advancements in rig technology, including our FlexApp™ services, development of a proprietary Bit Guidance System™, offered as a service through MOTIVE Drilling Technologies, Inc.United Arab Emirates (“
MOTIVE”U.A.E.”)
, which we acquired in June 2017, and 3D geomagnetic reference modeling and measurement while drilling survey correction services, offered through Magnetic Variation Services, LLC (“MagVAR”), which we acquired in December 2017. .
We also own, develop and operate limited commercial real estate properties. Our real estate investments, which are located exclusively within Tulsa, Oklahoma, include a shopping center containing approximately
441,000 leasable square feet, multi‑tenant industrial warehouse properties containing approximately one million389,000 leasable square feet and approximately 210 acres of undeveloped real estate. Our research and development endeavors include both internal development and external acquisition of developing technologies. On October 1, 2019, we elected to utilize a wholly-owned insurance captive (“Captive”) to insure the deductibles for our workers’ compensation, general liability and automobile liability insurance programs. The Company and the Captive maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of significant events covered under these programs. Our real estate operations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are included in "Other."The following map andshows the number of working rigs by basin in our North America Solutions reportable segment as of September 30, 2020:
The following table sets forth certain information concerning our U.S. landNorth America Solutions drilling rigs as of September 30, 2018:
2020: | | | | | | | | | | |
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 |
|
| | | | | | | | | | | | |
| North America Solutions Fleet |
| Current 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 | 156 |
| 42 |
| 7 |
| — |
| 163 |
| 42 |
|
| OK | 26 |
| 4 |
| 2 |
| — |
| 28 |
| 4 |
|
| NM | 25 |
| 12 |
| — |
| — |
| 25 |
| 12 |
|
| ND | 10 |
| 4 |
| 4 |
| — |
| 14 |
| 4 |
|
| CO | 2 |
| 1 |
| 11 |
| 2 |
| 13 |
| 3 |
|
| PA | 3 |
| — |
| 4 |
| — |
| 7 |
| — |
|
| OH | 5 |
| 1 |
| — |
| — |
| 5 |
| 1 |
|
| WY | 4 |
| — |
| — |
| — |
| 4 |
| — |
|
| WV | 3 |
| 3 |
| — |
| — |
| 3 |
| 3 |
|
| Totals | 234 |
| 67 |
| 28 |
| 2 |
| 262 |
| 69 |
|
| |
| (1) | AC drive, minimum of 1,500 horsepower drawworks, minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and multiple-well pad capability. |
| The FlexRig3
|
| (2) | AC drive, 1,500 horsepower drawworks, 500,000 or 750,000 lbs. hookload rating, 5,000 or 7,500 psi mud circulating system, may or may not have multiple-well pad capability. |
The following table sets forth certain information concerning our Offshore Gulf of Mexico drilling rigs as of September 30, 2020:
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| | | | | | | | | | | | |
| Offshore Gulf of Mexico Fleet |
Current Location | Shallow Water (1) | Deep Water (1) | Total Fleet |
| Total Available | Rigs Contracted | Total Available | Rigs Contracted | Total Available | Rigs Contracted |
Louisiana (2) | 3 |
| — |
| — |
| — |
| 3 |
| — |
|
| Gulf of Mexico | 2 |
| 2 |
| 3 |
| 3 |
| 5 |
| 5 |
|
| Totals | 5 |
| 2 |
| 3 |
| 3 |
| 8 |
| 5 |
|
| |
| (1) | Deep water rigs operate on floating facilities and shallow water rigs operate on fixed facilities. |
| |
| (2) | Rigs are idle, stacked on land and not in state waters. |
The following table sets forth certain information concerning our International Solutions drilling rigs as of September 30, 2020:
|
| | | | | | | | | | | | | | | | | | | | |
| International Solutions Fleet |
| Current Location | AC (FlexRig® 3) (1) | AC (FlexRig® 4) (2) | Other AC | SCR (3) | Total Fleet |
| Total Available | Rigs Contracted | Total Available (1) | Rigs Contracted | Total Available (1) | Rigs Contracted | Total Available (1) | Rigs Contracted | Total Available | Rigs Contracted |
| Argentina | 12 |
| 2 |
| 4 |
| — |
| — |
| — |
| 4 |
| — |
| 20 |
| 2 |
|
| Colombia | 2 |
| — |
| 2 |
| — |
| 1 |
| — |
| 2 |
| — |
| 7 |
| — |
|
| Bahrain | — |
| — |
| 3 |
| 3 |
| — |
| — |
| — |
| — |
| 3 |
| 3 |
|
| U.A.E. | 2 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| 2 |
| — |
|
| Totals | 16 |
| 2 |
| 9 |
| 3 |
| 1 |
| — |
| 6 |
| — |
| 32 |
| 5 |
|
| |
| (1) | Other than one super–spec rig (as described above) in Argentina, the FlexRig®3 is equipped with an AC drive, 1,500 horsepower drawworks, and a 750,000 lb. mast, Varco TDS-11HP top drive and Gardner Denver PZ-11 mud pumps.hookload rating. It can be equipped with an optional skiddingskid or walking system, for pad workthird mud pump, and 7,500 psi high pressure mud system. This rig is capable of horizontal and vertical drilling.The other 11 rigs in Argentina are equipped with skid systems. |
| |
| (2) | | The FlexRig4FlexRig® 4 model ishas a trailerized rigsmall footprint and is 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-11two 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.
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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 offshore 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.
|
| (2)
| | Rigs are idle, stacked on land and not in state waters.
|
The following table sets forth certain information concerning our international land drilling rigs as of September 30, 2018:
| | | | | | | | | | |
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 |
| (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 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 rigs present in the country, pursuant to which the rigs, together with associated equipment and machinery will be sold to a third party to be recycled. Prior to the sale that was executed on October 1, 2018, certain components of these rigs that are not subject to the sale agreement were transferred to the United States. As such, these rigs have been excluded from the table.
wells. |
Drilling Services and SolutionsContract 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 focused on unconventional shale basins. In South America and the Middle East, our customers primarily include major international and national oil companies. We don’tdo not operate any legacy mechanical rigs.
Revenue
We had revenues from individual customers, within our North America Solutions segment, that areconstituted 10 percent or more of our total revenues as follows:
|
| | | |
| (in thousands) | 2018 |
| EOG Resources, Inc. | $ | 258,194 |
|
We did not have any individual customers that represented 10% or more of our total consolidated revenues are as follows:in fiscal years 2019 or 2020.
| | | | | | | | | |
(In thousands) | 2018 | | 2017 | | 2016 |
EOG Resources, Inc. | $ | 258,194 | | $ | 163,582 | | $ | 124,262 | |
The following table presents our average active rigs per day (a measure of activity and utilization over the fiscal year) and average utilization for the fiscal years 2018, 2017,2020, 2019, and 2016:
2018: | | | | | | | | | | | | | | | | | | | |
| | 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 |
| | 2020 (1) | | 2019 (2) | | 2018 | | 2020 | | 2019 | | 2018 | | 2020 | | 2019 (3) | | 2018 |
| Average active rigs per day | 134.3 |
| | 224.1 |
| | 213.6 |
| | 5.3 |
| | 5.9 |
| | 5.6 |
| | 12.6 |
| | 17.6 |
| | 18.3 |
|
Average utilization (4) | 47 | % | | 67 | % | | 61 | % | | 66 | % | | 74 | % | | 70 | % | | 40 | % | | 55 | % | | 49 | % |
| |
| (1) | At the beginning of the third quarter of fiscal year 2020, the fleet was downsized by 37 rigs. See Note 5—Property, Plant and Equipment to our Consolidated Financial Statements. |
| |
| (2) | At the end of the third quarter of fiscal year 2019, the fleet was downsized by 51 rigs. See Note 5—Property, Plant and Equipment to our Consolidated Financial Statements. |
| |
| (3) | At the end of the third quarter of fiscal year 2019, the fleet was downsized by two rigs. See Note 5—Property, Plant and Equipment to our Consolidated Financial Statements. |
| |
| (4) | A rig is considered to be utilized when it is operatedoperating (or otherwise deployed for a customer) or being moved, assembled or dismantled pursuant to a drilling contract, or stacked under contract. |
North America Solutions Segment
We believe we operate the largest 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 a leading market share in 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,
2018,2020, we had
overapproximately 20 percent of the total market share in U.S. land drilling and
over 40approximately 29 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 with 234 rigs, of which 67 were under contract at September 30, 2018, 2322020. In total, 69 of our 350262 marketed rigs were under contract, 13654 were under fixed‑fixed‑term contracts, and 9615 were working well-to-well. Overwell-to-well as of September 30, 2020.
Our drilling technology solutions within this segment enables a holistic solution-based approach that includes products, services and capabilities. This approach provides performance-driven drilling services intended to deliver greater levels of accuracy, consistency, optimization and a reduction of human error to create higher quality wellbores. This technology is intended to address our customers' unique challenges and should result in less wellbore tortuosity and reduce positional uncertainty in the past threedirectional drilling process. During fiscal years,year 2019, we have reinvestedreleased AutoSlide®, which integrates the MOTIVEBit Guidance System® and several FlexApps to function within the FlexRig® operating system and fully automates the control of mud motors while sliding during the vertical, the curve, and the lateral hole sections during horizontal drilling operations. Currently, our AutoSlide® application is commercially available in all U.S. oil and gas basins. Many components of our fleet, upgrading over 162 rigsdigital technology, including the MOTIVE Bit Guidance System® technology and MagVarTM survey correction, can be used on any rig, regardless of the drilling or service provider, allowing our customers to industry-leading super-spec designed to drill the most complex unconventional wells.benefit from these technologies on all rigs.
Our
U.S. LandNorth America Solutions segment contributed approximately
8383.1 percent ($1.5 billion) of our consolidated operating revenues during fiscal year 2020, compared to approximately 86.7 percent ($2.4 billion) and 84.2 percent ($2.1 billion) of our consolidated operating revenues during fiscal
yearyears 2019 and 2018,
compared with approximately 80 percent ($1.4 billion) and 77 percent ($1.2 billion) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively. In
the United States, we drawNorth America, our customers
are primarily from the major oil companies, large independent oil companies,
and small cap oil
companies.companies and private independent companies (including private equity-backed companies).
Offshore
Gulf of Mexico Segment
Our Offshore
DrillingGulf of Mexico segment has been in operation since 1968 and currently consists of eight
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, six2020, five of the eight offshore rigs were under contract. Our Offshore Gulf of Mexico operations contributed approximately 68.1 percent ($143.1 million) of our consolidated operating revenues during fiscal year 2020, compared to approximately 5.3 percent ($147.6 million) and 5.7 percent ($142.5 million) of our consolidated operating revenues during fiscal yearyears 2019 and 2018, compared to approximately 8 percent ($136.3 million) and 9 percent ($138.6 million) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively. Revenues from drilling services performed for our largest offshore drilling customer totaled approximately 6081.1 percent ($85.8116.1 million) of offshore revenues during fiscal year 2018.
2020.
International
LandSolutions Segment
Our International
LandSolutions segment operates primarily in Argentina,
and Colombia,
in addition to smaller operations in Bahrain and U.A.E. During the fourth quarter of fiscal year 2018, we ceased operations in Ecuador. As of September 30,
2018,2020, we had
215 land rigs contracted for work in locations outside of the United States. Our International
LandSolutions operations contributed approximately
108.1 percent ($144.2 million) of our consolidated operating revenues during fiscal year 2020, compared to approximately 7.6 percent ($211.7 million) and 9.6 percent ($238.4 million) of our consolidated operating revenues during fiscal
yearyears 2019 and 2018,
compared with approximately 12 percent ($213.0 million) and 14 percent ($229.9 million) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively.
ArgentinaAs of September 30, 2018,2020, we had 1920 rigs in Argentina. Revenues generated by Argentine drilling operations contributed approximately 84.8 percent ($84.4 million) of our consolidated operating revenues during fiscal year 2020 compared to approximately 5.9 percent ($165.7 million) and 7.6 percent ($190.0 million) of our consolidated operating revenues during fiscal yearyears 2019 and 2018, compared to approximately 9 percent ($157.3 million) and 10 percent ($159.4 million) of our consolidated operating revenues during fiscal years 2017 and 2016, respectively. Revenues from drilling services performed for our two largest customers in Argentina totaled approximately 73.6 percent of our consolidated operating revenues and approximately 7143.9 percent of our international operating revenues during fiscal year 2018.2020. The Argentine drilling contracts are primarily with large international or national oil companies.
Colombia As of September 30, 2018, we believe2020, 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 20.4 percent ($6.4 million) of our consolidated operating revenues in fiscal year 2020, compared to approximately 1.1 percent ($29.8 million) and 1.6 percent ($38.8 million) of our consolidated operating revenues in fiscal year 2018, compared to approximately 2 percent ($37.6 million) and 1 percent ($20.5 million) of our consolidated operating revenues during fiscal years 20172019 and 2016,2018, respectively. Revenues from drilling services performed for our two largest customers in Colombia totaled approximately 10.4 percent of our consolidated
operating revenues and approximately 134.4 percent of our internationaloperating revenues during fiscal year 2018.2020. The Colombian drilling contracts are primarily with large international or national oil companies. Bahrain As of September 30, 2020, we had three rigs in Bahrain. Revenues generated by Bahrain drilling operations contributed approximately 1.6 percent ($28.7 million) of our consolidated operating revenues in fiscal year 2020, compared to approximately 0.4 percent ($11.5 million) and 0.4 percent ($9.5 million) of our consolidated operating revenues during fiscal years 2019 and 2018, respectively. All of our revenues in Bahrain are from a partner of the local national oil company.
United Arab Emirates As of September 30, 2020, we had two rigs in the U.A.E. Revenues generated by U.A.E. drilling operations contributed approximately 1.4 percent ($24.7 million) of our consolidated operating revenues in fiscal year 2020, compared to approximately 0.2 percent ($4.7 million) in fiscal year 2019 and nominal amounts in fiscal year 2018.
Other Operations include additional non-reportable operating segments.
Revenues included in “other” consist of drilling technology services as well as real estate rental income. Our drilling technology focuses on improving the efficiency and accuracy of drilling operations and wellbore quality through the following service offerings: (i) a proprietary Bit Guidance System™, offered as a service through MOTIVE, which we acquired in June 2017, and (ii) 3D geomagnetic reference modeling and measurement while drilling survey correction services, offered through MagVAR, which we acquired in December 2017.We also own, develop and operate limited commercial real estate properties. Our real estate investments, which are located exclusively within Tulsa, Oklahoma, include a shopping center multi‑tenant industrial warehouse properties, and undeveloped real estate.
We have established a wholly-owned captive insurance company
On October 1, 2019, we elected to utilize the Captive 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 Captive to finance the risk of loss to equipment and rig property assets. The amountCompany and the Captive 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, dependingCaptive, typically on a monthly basis, for the estimated losses based on the amountexternal actuarial analysis. The Company is also utilizing the Captive to provide stop-loss coverage over its self-insured employee health plan, which covers insured claims in excess of premiums paid toemployee deductibles. The Company did not previously purchase any stop-loss coverage.
During the
captive insurance company,third quarter of fiscal year 2019, the
timingCompany established an incubator program for new research and
amountdevelopment projects, the results 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 resultwhich have been included in the transfer of certain assets from Helmerich & Payne International Drilling Co. to other wholly-owned subsidiaries of Helmerich & Payne, Inc. We believe that reorganizing these businesses into separate wholly-owned subsidiaries of Helmerich & Payne, Inc. will foster operational efficiency, simplify our organizational structure and provide additional clarity in our internal reporting. Any such internal reorganization would not impact"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 FlexRig1FlexRig® 1 and FlexRig2FlexRig® 2 rigs and were designed to drill wells with a depth of between 8,000 and 18,000 feet. From 2002 to 2004, we designed, built and delivered 32 of the next generation, AC drive rigs, known as “FlexRig3,“FlexRig® 3 rigs,” which incorporated new drilling technology and improved the safety and environmental design. The FlexRig3sFlexRig® 3 rigs found immediate success by delivering higher value wells to the customer. This wascustomer and marked the beginning of the AC land rig revolution. We also changed our pricing and contracting strategy, and beginning in 2005, predominantly all new 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® 3 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
H&P has a strategic advantage isdue to our ability to utilize our AC rig design and operational and engineering expertise to exploit different well depths and designs that customers demand. In 2006, we introduced the FlexRig4,FlexRig®4 drilling rig, which was designed to efficiently drill shallower wells on multi-well pads. The FlexRig4FlexRig® 4 design offers two options that include trailerized or multi-well pad drilling capability, both of which incorporate additional environmental and safety by design improvements. While the trailerized FlexRig4FlexRig® 4 design provides for more efficient moves between individual well pads, the multi-well pad design uses a skidding capability that allows for drilling multiple wells from a single pad, which results in asignificantly reduced environmental impact and increased production from a smaller footprint. In 2011, we announced the introduction of the FlexRig5.FlexRig® 5 drilling rig. The FlexRig5FlexRig® 5 drilling rig was designed for deeper wells than the FlexRig4FlexRig® 4 drilling rig and long lateral drilling of multiple wells from a single location and is designed for drilling horizontally in unconventional shale reservoirs. The new design preserves the key performance features of the FlexRig3FlexRig® 3 rig design but adds a bi-directional skidding system and equipment capacities suitable for wells in excess of 25,000 feet of measured depth.We
In 2016, we saw the progression of longer lateral wells and the technical challenges involved in drilling longer lateral wells. At that time, we began delivering rigs to the market that were equipped and capable of drilling the longer lateral wells. The industry would later refer to these rigs as super-spec rigs, which have an important advantagethe following specific characteristics: AC drive, minimum 1,500 horsepower drawworks, minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and multiple-well padcapability. Additionally, our competency in the super-spec space in thatdesign and construction as well as our FlexRig3’s and FlexRig5’s are ideally suited for super-spec upgrades, and we have more upgradeable rigs thanfinancial strength enabled us to efficiently upgrade our competitors. Going forward, we will continue to focus on investing capital to grow the size of our super-spec fleet. During fiscal year 2018, we converted two FlexRig4’s to super-spec capacity and upgraded 52 of our other existing rigs to super-spec, including 51 FlexRig3’s and one FlexRig5.resulting in what we believe to be the largest fleet of super-spec rigs in the world. As of September 30, 2018,2020, we held over 40approximately 29 percent of the super-spec market share in the U.S. land drilling. Our competency in designdrilling market with 234 super-spec rigs. In 2017, we introduced our first walking rig by reconfiguring our skid designed FlexRig® 3 drilling rigs. Since then, we have reconfigured, converted, and construction allows us to efficiently upgrade ourupgraded a total of 44 FlexRig® drilling rigs to super-spec and our financial strength enables us to continue such upgrades as long as market demand for such rigs remains high and there remains a supply of economically viable super-spec 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 the challenge of providing safe, high quality and consistent results, we utilize process excellence techniques that are developed internally. We provide experienced drilling and maintenance support for our operations, which provides value by reducing nonproductive time in our operations and improving drilling performance through our Rig Systems Monitoring and Support Center 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 fabrication andOur assembly facility
is located near Houston,
Texas as well as a fabrication facility near Tulsa, Oklahoma. Additionally, we lease an industrialTexas. Our facility near Tulsa, Oklahoma
that we utilizeis utilized for
FlexRig equipment repairsoverhauling, recertification, and
overhauls.repairs.
During fiscal year 2018,2020, we commercializedcontinued to see adoption and growth with our technologies and automation focused solutions. Our FlexApp services,solutions, which include several new software applications that layer on top of our FlexRig® drilling control systems.system, continue to add value for our customers. Our AutoSlide® service, which is powered by our Motive Bit Guidance System® technology, continued to grow in commercial feet steered, new customer adoption and the number of deployments. Our MagVarTM, Drillscan® and Motive Bit Guidance System® solutions continue to be available on both H&P and third-party rigs. These solutions continue to provide differentiated value for our customers in the areas of drilling engineering, wellbore placement, and wellbore quality. Our path to autonomous drilling continues to evolve with several solutions in Alpha and Beta testing. All of our automation focused solutions and applications are enabled by our uniform digital fleet and are designed to provide additional value to our customers’customers' well programs by providing a platform for machine-human collaboration during the drilling process to improve efficiency. The FlexApps can helpAll of our technologies play an important role in deployingdeveloping our strategy as we strivehead towards autonomous drilling.
The FlexAppstechnologies that are currently in use include the following:
| | |
Application Name
| | Description
|
FlexTorque™
Application Name | Description |
| FlexTorque™ | Hardware and software designed to decrease downhole drilling vibration and "slip-stick" during drilling. This increaseshelps with drilling efficienciesefficiency and extendsis intended to help extend bit and downhole tool life eliminating customers'to help reduce 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 reduceshelps reduce downhole drag and the potential for stuck pipe. Additionally, it allows forIt also helps support more effective directional drilling. |
FlexB2D™ | | Software to engage and disengage the bit during connections in an established controlled and consistent manner allowing for betterthat is intended to help extend 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 help maximize the bit's rate of penetration, which we have automated, allowingthat is intended to allow the drilling control system to achieve the ideal mechanical specific energy at the bit. |
FlexGuide™
AutoSlide® | | Powered by both Motive’s Bit Guidance System® technology and utilizes machine learning and automation to help interface with FlexRig® control systems to allow for automatic slide drilling via computer control. |
MagVarTM | Solution intended to help improve surveying accuracy and contribute to increased horizontal well economics while reducing collision risk. |
DrillScan® | Industry leader in physics-based modeling software to help select bottom hole assemblies and help provide real-time drilling dynamics evaluation. |
MOTIVE and MagVAR software that utilizes a drill bitBit Guidance System® | Automated directional drilling guidance system and geomagnetic survey correction, respectively, allowing for higherthat helps improve wellbore quality wellbores with a scalable, repeatable data driven platform approach and a reduction of surveying uncertainty by 50-60% while increasingto help increase horizontal well economics and reducinghelp reduce risk. |
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. 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,
2018,2020, we had
25979 rigs under contract, compared to 218 and
118259 rigs under contract as of September 30,
20172019 and
2016,2018, respectively. For further information concerning risks associated with our business, including volatility surrounding oil and natural gas prices and the impact of low oil prices on our business, see Item 1A— “Risk Factors” and Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this Form
10‑10‑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 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 all2020, a majority of our drilling services were performed on a “daywork” contract basis, under which we charged a rate per day, with the price determined by the location, depth and complexity of the well to be drilled, operating conditions, the duration of the contract, and the competitive forces of the market. We may also enter into contracts where we charge a fixed rate per foot of hole drilled to a stated depth, with a fixed rate per day for the remainder of the hole. Contracts performed on a “footage” basis generally involve a greater element of risk to
the contractorH&P compared to contracts performed on a “daywork” basis. Also, we may enter into
“turnkey”“lump-sum” contracts under which we charge a fixed sum to deliver a hole to a stated depth and agree to furnish services such as testing, coring and casing the hole which are not normally done on a “footage” basis.
“Turnkey”“Lump-sum” contracts entail varying degrees of risk greater than the usual “footage” contract. We also actively pursue “performance daywork”
contracts.contracts, pursuant to which we are compensated based upon our performance against a mutually agreed upon set of predetermined targets. These contracts typically have a lower
base dayrate
portion andbut give us the opportunity to
share in the well cost savings based onreceive additional compensation by meeting or exceeding certain
key performance
indicators thattargets. The risks associated with these contracts relate to the failure to reach the agreed upon performance targets. If we do not meet these targets, we will not receive additional compensation beyond the base dayrate and will recognize less overall drilling services revenue than we would by utilizing other types of contracts. We are
mutually agreed onseeing a growing adoption of performance contracts by
ourselvesour customers and
our customers.we expect this trend to continue.
The duration of our drilling contracts are generally either
“well‑to‑“well‑to‑well” 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.
Contract Backlog
As of September 30, 2018 and 2017, our drilling
Drilling contract backlog beingis the expected future dayrate revenue from executed contracts. We calculate backlog as the total expected revenue from fixed-term contracts with originaland do not include any anticipated contract renewals as part of its calculation. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of 365 daysunsatisfied 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 greater,decides to terminate the contract early and pay an early termination payment. In the event of an early termination payment, the timing of the recognition of backlog and the total amount of revenue may differ; however, the overall associated cash flow is preserved. As such, management finds backlog a useful metric for future planning and budgeting, whereas investors consider it in estimating future revenue and cash flows of the Company. As of September 30, 2020, and 2019, our drilling contract backlog was $1.1$0.7 billion and $1.3$1.2 billion, respectively. The decrease in backlog at September 30, 20182020 from September 30, 20172019 is primarily due to contract pricing modificationsprevailing market conditions causing a decline in the number of drilling contracts executed and a changeto some extent an increase in certain contracts from fixed term to well-to-well related to our international land segment in fiscal year 2018.the number of early terminations of contracts. Approximately 2633.3 percent of the total September 30, 20182020 backlog is reasonably expected to be filled in fiscal year 2022 and thereafter.
Fixed-term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term. As a result of the depressed market conditions and negative outlook for the near term, beginning in the second quarter of fiscal year 2020, certain of our customers, as well as those of our competitors, have opted to renegotiate or early terminate existing drilling contracts. Such renegotiations have included requests to lower the contract dayrate in exchange for additional terms, temporary stacking of the rig, and other proposals. During the fiscal years ended September 30, 2020 and thereafter. Included in backlog is2019, early termination revenue expected to be recognized after the periods presented in which early termination noticeassociated with term contracts was received prior$73.4 million and $11.3 million, respectively.
In response to the
endcurrent market conditions, several operators included in our North America Solutions operating segment have opted to place their rigs in an idle-but-contracted state as an alternative to early termination. This includes "warm stacking" and "cold stacking." Warm stacking occurs when a rig remains on-site while pausing drilling activity, while cold stacking occurs when a rig is demobilized and returned to the yard temporarily until next steps are determined. When rigs are stacked, they remain under the terms of the
period. Upon adoptioncontract but typically pay a reduced rate, where the remaining term days are generally not reduced, but our operating expenses are reduced. In many instances for stacked rigs, for the total days stacked there are proportional days added to the original contract length at the original contracted rate. As of
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 backlogSeptember 30, 2020, there are five rigs that are warm stacked, five rigs that are cold stacked within the
Notes to the Consolidated Financial Statements included in Part II, Item 8– “Financial Statements and Supplementary Data” of this report.North America Solutions segment. The following table sets forth the total backlog by reportable segment as of September 30, 20182020 and 2017,2019, and the percentage of the September 30, 20182020 backlog reasonably expected to be filled in fiscal year 20202022 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
|
| | | | | | | | | | |
| | Total Backlog Revenue | | Percentage Reasonably Expected to be Filled in Fiscal Year 2022 and Thereafter |
| (in billions) | September 30, 2020 | | September 30, 2019 | |
| North America Solutions | $ | 0.6 |
| | $ | 1.0 |
| | 33.3 | % |
| Offshore Gulf of Mexico | — |
| | — |
| | — |
|
| International Solutions | 0.1 |
| | 0.2 |
| | 39.3 |
|
| | $ | 0.7 |
| | $ | 1.2 |
| | |
|
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, a customer is not required to pay ansuch as sustained unacceptable performance by us, no early termination fee. There may alsopayment would be instances where a customer is financially unable or refusespaid to pay an early termination fee. In addition, contract termsus. Early terminations could be modified or extended after the initial contract is signed. Accordingly,cause the actual amount of revenue earned mayto vary from the backlog reported. For further information, seeSee Item 1A—“Risk “Risk Factors — Our current backlog of contract drilling services and solutions revenue may continue to decline and may not be ultimately realized as fixed‑fixed‑term contracts and may, in certain instances, be terminated without an early termination payment.”Employees
One
" within this Form 10-K regarding fixed-term contract risk. Additionally, see Item 1A— “Risk Factors — The impact and effects of public health crises, pandemics and epidemics, such as the ongoing outbreak of COVID-19, have adversely affected and are expected to continue to adversely affect our core values is striving for a culture that embraces organizational healthbusiness, financial condition and actively controlling and removing exposures (“C.A.R.E.”) for the safety and wellbeingresults 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.operations
" within this Form 10-K. Employees
As of September 30,
2018,2020, we had
8,7803,634 employees within the United States
(12 of whom were part‑time employees) and 997504 employees in our international operations. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be robust. None of our U.S. employees are represented by a union. However, some of our international employees are unionized.Human Capital Objectives and Programs
We strive to create a culture and work environment that enables us to attract, train, promote, and retain a diverse group of talented employees who together can help us gain a competitive advantage.
Recruiting
Our recruiting practices and decisions on whom to hire are among our most important activities. In a downturn year such as fiscal year 2020, we maintain relationships with former employees and prioritize recalling our most experienced people for field positions. In addition, we utilize social media, local job fairs and educational organizations across the United States to find diverse, motivated and responsible employees.
Core Values and Culture
Fostering and maintaining a strong, healthy culture is a key strategic focus. Our core values reflect who we are and the way our employees interact with one another, our customers, partners and shareholders. Our core value of Actively C.A.R.E. means that we treat one another with respect. We care about each other, and from a safety perspective, our employees are committed to Controlling and Removing Exposures for themselves and others. Our core value of Service Attitude means that we do our part and more for those around us. We consider the needs of others and provide solutions to meet their needs. Our core value of Innovative Spirit means that we constantly work to improve and are willing to try new approaches. We make decisions with the long-term view in mind. Our core value of teamwork means that we listen to one another and work across teams toward a common goal. We collaborate to achieve results and focus on success for our customers and shareholders. Finally, we do the right thing. That means we are honest and transparent. We tackle tough situations, make decisions, and speak up when needed.
To further encourage living out our core values, during fiscal year 2020, an average of 10 organizational health sessions per month were conducted with employee teams.
Education and Training
We are dedicated to the continual training and development of our employees, especially of those in field operations, to ensure we can develop future managers and leaders from within our organization. Our training starts right at the beginning with on-boarding procedures that focus on safety, responsibility, ethical conduct and inclusive teamwork.
In addition to on–boarding training, we provide extensive ongoing training and career development focused on:
compliance with our Code of Business Conduct and Ethics and laws applicable to our business
skills and competencies directly related to employees' positions; and
| |
| • | responsibility for personal safety and the safety of fellow employees, others on location and the environment. |
Safety Training and Serious Injury and/or Fatality ("SIF") Reduction Program
Over the last three years, 94% of our Rig Managers and 91% of Drillers received in-field coaching from a Safety Leadership Coach and employees received, on average, 26 hours of training.
One of our most critical responsibilities is the safety of our employees and the employees of our customers. Traditional approaches to safety focused on lagging indicators that centered on reacting to injuries after they occurred. However, we believe the best approach is to focus on exposures (leading indicators) and controlling and removing them, thus helping prevent injuries before they occur. Accordingly, we have moved to tracking potential SIFs with annual goals targeted at reducing SIFs. In calendar year 2019, we focused on reducing the number of SIF incidents by improving pre-job planning tools as a means for reducing incidents with SIF potential, year-over-year reduction in incidents related to handling of tubulars and year-over-year increase in seatbelt usage among employees based on self-reported seatbelt use.
Educational Assistance Plan
We offer an Educational Assistance Plan for eligible employees pursuing an undergraduate degree and, in some cases, post-graduate degrees.
Health and Welfare
We support our employees’ and their families’ health by offering full medical, dental, and vision insurance for employees and their families, life insurance and long-term disability plans, and health and dependent care flexible spending accounts. We foster teamwork and a sense of community amongst our employees through our H&P Way Fund that provides assistance to employees and their families experiencing emergencies.
Retirement
We provide a variety of resources and services to help our employees for Retirement. H&P offers a comprehensive retiree medical plan for those who meet eligibility requirements. In addition, we provide a 401(k) plan with a company match.
Insurance and Risk Management
Our operations are subject to a number of operational risks, including personal injury and death, environmental, and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us. Furthermore, if a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on our business, financial condition and results of operations.
We have indemnification agreements with many of our customers and we also maintain liability and other forms of insurance. In general, our drilling contracts contain provisions requiring our customers to indemnify us for, among other things, pollution and reservoir damage. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts by us, or subcontractors and/or suppliers or by reason of state anti-indemnity laws. Our customers and other third parties may also dispute these indemnification provisions, or we may be unable to transfer these risks to our drilling customers or other third parties by contract or indemnification agreements.
We insure
working land rigs and related equipment at values that approximate the current replacement costs on the inception date of the policies. However, we self-insure large deductibles under these policies. We also carry insurance with varying deductibles and coverage limits with respect to
stacked rigs, offshore platform rigs, and “named wind storm” risk in the Gulf of Mexico.
We have insurance coverage for comprehensive general liability, automobile liability, workers’ compensation and employer’s liability, and certain other specific risks. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. We retain a significant portion of our expected losses under our workers’ compensation, general liability and automobile liability programs. We self-insure a number of other risks including loss of earnings and business interruption 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 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.”
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.2021. 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 theUnited 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.”
We marked our 100 year anniversary in 2020 in a cyclical industry that at times has proven to be highly volatile. Much planning and work goes into our Company by all its employees, both past and present, to ensure our sustainability. The Company continues to refine its comprehensive sustainability strategy rooted in our core value to "do the right thing," as discussed under "— Human Capital Objectives and Programs — Core Values and Culture." This strategy uses data to better understand our impacts in areas like emissions, diversity, and safety so we can make any necessary improvements.
Improving Lives Through Affordable and Responsible Energy
We believe affordable and responsible energy improves lives globally. With a focus on leading-edge technology, we strive to deliver industry-leading efficiency, safety, and value while continuing to reduce the environmental impact of our solutions.
Energy has been essential to human life, but the forms of energy that have been relied on have evolved over time. People have relied upon and harnessed energy from resources like fire, water, wind, horsepower, fossil fuels, nuclear, solar, and more, with each having its own unique societal benefits and costs.
At a certain point, the directioncontinued 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 design, build and operate rigs that make drilling for oil and gas safer and more efficient. Focused on the drilling segment of the oil and gas production 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.
Below is a description of responsibility. Our most criticalthe roles that H&P plays, in the oil and gas value chain, as a drilling solutions provider in comparison to the roles that participants in other sectors of the oil and gas industry play.
H&P:
makes drilling for oil safer and more efficient;
build and renovates drilling rigs at two industrial facilities in Texas and Oklahoma;
oversees drilling operations on its rigs on customer sites;
drills predominantly on-shore in the United States (88 percent of available rigs are on onshore);
makes significant and impactful investments in research and development and new technologies;
employs over 4,100 people; and
provides robust benefit plans to protect the physical and financial health of its valued employees.
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 is thereforefor the safetyprevention of fugitive releases or emissions associated with the oil and gas production process;
engage in oil and gas transport, refining or storage; and
engage in downstream operations.
Human Capital
For a description of our employees and the employees of our customers. To be successful, we strive to be leaders in innovation, technology, cost competitiveness, safety, customer service, relationship tending, and reputation management. To maintain this leadership edge and generate shareholder value, we invest in our employees, customers, communities, and other stakeholders in the ways listed below.Recruiting
Our recruiting practices, education and decisions on whom to hire are among our most important activities. In addition to traditional school recruiting events, we utilize social media and local job fairs across the U.S. to find diverse, motivated and responsible employees.
Education and Training
The employment opportunities we offer are key to successful recruiting. To attract motivated employees, we rely on our organizational development team. This team offers talent management, mentoring programs, change management initiatives, and diversity, inclusion and succession management programs, as well as educational assistance programs and ongoing training and development opportunities.
Health and Welfare
We support our employees’ and their families’ health with full medical, dental, and vision insurance for employees, and their families, life insuranceemployee benefits, see "— Human Capital Programs and long-term disability plans, and health care and dependent care flexible spending accounts. We foster teamwork and a sense of community amongst our employees through our H&P Way Fund that provides assistance to employees and their families experiencing emergencies.
Retirement
We provide a 401(k) plan with a company match.
Safety
All of our safety programs are designed to comply with applicable laws and industry standards as well as to benefit employees, customers and communities. We have a dedicated Health, Safety and Environmental (“HSE”) function overseen by senior executives and implemented at every H&P drilling rig and facility worldwide. Our safety-focused C.A.R.E. program promotes employee and customer safety and well-being. In addition, we incorporate safety features into our rig designs through our Safety by Design program. The success of our safety initiatives, including our C.A.R.E. and Safety by Design programs, and the Company’s performance with respect to safety metrics are important elements of the compensation of our executives, as discussed further in our proxy statement.
Our Safety by Design program helps us:
| ·
| | Identify and work to eliminate hazards in the rig design phase
|
Objectives" above. | ·
| | Use leading-edge technology to enhance efficiency and thus reduce the number and severity of safety risks
|
Available Information | ·
| | Standardize designs, which can reduce the variability in the types of rigs we use to allow our employees to have a greater familiarity with the rigs than would be achieved if they had to master a wider variety of rig types
|
| ·
| | Design and configure loads and interconnects with rig moves in mind. By striving to integrate equipment to the greatest extent possible, we minimize risks associated with moves and risks associated with double handling
|
Our COE promotes process excellence and safety by providing experienced drilling and maintenance real-time support around the clock to our operations. Our COE Call Center and Real-Time Monitoring Groups are staffed with experienced systems technicians who work with field personnel to leverage each group’s knowledge in troubleshooting rig
events. In addition, experienced engineers monitor safety critical alarms and perform daily safety performance and data analysis throughout the fleet.
In the event that an incident does occur, we have developed and implemented a comprehensive Emergency Management and Crisis Response Plan to help ensure H&P has the ability to respond promptly and effectively to the most severe adverse situations or crises.
Environmental Management
H&P does not itself lease properties used for the operations of its customers. However, many of our customers operate in regions that have stringent safety and environmental laws and regulations, with which we comply as applicable. The standards we employ include:
| ·
| | Applying industry-accepted environmental best practices
|
| ·
| | Minimizing rig physical footprints, and using technology to configure drilling rigs, where appropriate, for space efficient multi-well pads, all to minimize the impact on the environment in which we and our customers operate
|
| ·
| | Conversion of many of our rigs to allow partial substitution of cleaner burning natural gas as a fuel source to reduce air emissions
|
| ·
| | Upgrading our drilling rig fleet to utilize AC drive power and control systems which are more energy efficient and have significantly lower noise levels as compared to SCR and mechanical drilling rigs
|
| ·
| | Using a variety of recycling and other initiatives in our facilities and operations to minimize waste
|
Ethics and Compliance
We expect corporate, professional and personal responsibility from each of our employees as well as compliance with high ethical standards to achieve operational excellence. In addition to the corporate governance oversight provided by the Board of Directors and its committees, management observes and enforces our Code of Business Conduct and Ethics (“Code”) described on our website. Our Code provides employees with the tools to make consistent, ethical decisions and emphasizes the duty to report any concerns or violations.
In addition to our Code, we have and enforce a Code of Ethics for Principal Executive Officers and Senior Financial Officers and a Foreign Corrupt Practices Act Compliance Policy.
We believe this focus on finding and getting the best out of our people, our programs, our standards and our technology collectively support our operations, our reputation and our returns.
Available Information
Our website is located at www.hpinc.com. Annual reports on Form 10‑10‑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/), 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.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.
Business and Operating Risks
The impact and effects of public health crises, pandemics and epidemics, such as the ongoing outbreak of COVID-19, have adversely affected and are expected to continue to adversely affect our business, financial condition and results of operations.
Public health crises, pandemics and epidemics, such as the ongoing outbreak of COVID-19, have adversely impacted and are expected to continue to adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our services. Fear of such events has also altered the level of capital spending by oil and gas companies for exploration and production activities and adversely affected the economies and financial markets of many countries (or globally), resulting in an economic downturn that has affected demand for our services. For instance, the outbreak of COVID-19 and its development into a pandemic has caused governmental authorities in many countries in which we operate to impose mandatory closures, seek voluntary closures and impose restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions. Among other matters, these actions have resulted in our "remote work" model for office personnel and the quarantine of some of our personnel, which, in turn, has caused the inability or unwillingness of certain personnel to access our offices, rigs or customer facilities and could decrease organizational effectiveness. Governmental authorities have also implemented multi-step policies with the goal of re-opening various sectors of the economy. However, certain jurisdictions began re-opening only to return to restrictions in the face of increases in new COVID-19 cases, while other jurisdictions are continuing to re-open or have nearly completed the re-opening process despite increases in COVID-19 cases. The COVID-19 outbreak may significantly worsen during the upcoming months, which may cause governmental authorities to reconsider restrictions on business and social activities. In the event governmental authorities increase restrictions, the re-opening of the economy may be further curtailed. We have experienced, and expect to continue to experience, some resulting disruptions to our business operations, as these restrictions have significantly impacted, and may continue to impact, many sectors of the economy. In addition, the perceived risk of infection and health risk associated with COVID-19, and the illness of many individuals across the globe, has resulted in many of the same effects intended by such governmental authorities to stop the spread of COVID-19. Further, in early March 2020, the increase in crude oil supply resulting from production escalations from OPEC+ combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Although OPEC+ subsequently agreed to cut oil production and has extended such production cuts through December 2020, crude oil prices remain depressed as a result of an increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. These events have had, and could continue to have, an adverse impact on numerous aspects of our business, financial condition and results of operations, including, but not limited to, our growth, costs, labor or equipment shortages, logistics constraints, customer demand for our services and industry demand generally, capital spending by oil and gas companies, our liquidity, the price of our securities and trading markets with respect thereto, our ability to access capital markets, asset impairments and other accounting changes, certain of our customers experiencing bankruptcy or otherwise becoming unable to pay vendors, including us, and the global economy and financial markets generally. The ultimate extent of the impact of COVID-19 on our business, financial condition and results of operations will depend largely on future developments, including the duration and spread of the outbreak within the United States and the parts of the world in which we operate and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the development and availability of effective treatments and vaccines, all of which are highly uncertain and cannot be predicted with certainty at this time.
Our business depends on the level of activity in the oil and natural gas industry, which is significantly impacted by the volatility of oil and natural gas prices and other factors.
Our business depends on the conditions of the land and offshore oil and natural gas industry. Demand for our services and the rates we are able to charge for such services depend on oil and natural gas industry exploration and production activity and expenditure levels, which are directly affected by trends in oil and natural gas prices and market expectations regarding such prices.
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 outbreak 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+ has 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,prices for our services, which couldhas had and is expected to continue to have a material adverse effect on our business, financial condition and results of operations.
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;
|
| ·
| | uncertainty in capital and commodities markets and the ability of oil and natural gas producers to access capital;
|
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; | ·
| | expectations about future oil and natural gas prices and production levels;
|
uncertainty in capital and commodities markets and the ability of oil and natural gas producers to access capital; | ·
| | 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 availability of and constraints in storage and transportation capacity, including, for example, concerns regarding storage availability that has been exacerbated by the significant reduction in demand and corresponding oversupply of oil and natural gas as a result of the global COVID-19 pandemic, as well as takeaway constraints experienced in the Permian Basin over the past several years; | ·
| | actions of The Organization of Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production levels, including announcements of potential changes to such levels;
|
the worldwide economy; | ·
| | the levels of production of oil and natural gas of non-OPEC countries;
|
expectations about future oil and natural gas prices and production levels; | ·
| | the continued development of shale plays which may influence worldwide supply and prices;
|
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; | ·
| | tax policies of the United States and other countries involved in global energy markets;
|
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; | ·
| | political and military conflicts in oil producing regions or other geographical areas or acts of terrorism in the United States or elsewhere;
|
the levels of production of oil and natural gas of non-OPEC countries; | ·
| | technological advances that are related to oil and natural gas recovery or that affect the global demand for energy;
|
the continued development of shale plays which may influence worldwide supply and prices; | ·
| | the development and exploitation of alternative energy sources;
|
tax policies of the United States and other countries involved in global energy markets; | ·
| | legal and other limitations or restrictions on exportation and/or importation of oil and natural gas;
|
political and military conflicts in oil producing regions or other geographical areas or acts of terrorism in the United States or elsewhere; | ·
| | local and international political, economic and weather conditions, especially in oil and natural gas producing countries;
|
technological advances that are related to oil and natural gas recovery or that affect the global demand for energy; | ·
| | laws and governmental regulations affecting the use of oil and natural gas; and
|
the development and exploitation of alternative energy sources; | ·
| | the environmental and other laws and governmental regulations affecting exploration and development of oil and natural gas reserves.
|
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.
Global economic conditions and volatility in oil and gas prices may adversely affect our business.
Global economic conditions and/or volatility in oil and natural gas prices may impact the ability or desire of our customers to maintain or increase spending on exploration and development drilling. Furthermore, our customers, vendors and/or suppliers may be unable to access financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations.
An economic slowdown or recession in the United States or in any other country that significantly affects the supply of or demand for oil or natural gas could negatively impact our operations and therefore adversely affect our results.
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 not quickly deteriorate again due to one or more factors. These conditions could have a material adverse effect on our business, financial condition and results of operations.
The
contract drilling
services and solutions business is highly competitive, and
an excessa surplus of available drilling rigs may adversely affect our rig utilization and profit margins.
The contract drilling business is highly competitive.
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, 2020, 223 of our available rigs were not under contract. Further, as a result of the significant reduced demand for oil and natural gas services due to the global COVID-19 pandemic, certain of our competitors may engage in bankruptcy proceedings, debt refinancing transactions, management changes, or other strategic initiatives in an attempt to reduce operating costs to maintain a position in the market. This could result in such competitors emerging with stronger or healthier balance sheets and in turn an improved ability to compete with us in the future. We may also see corporate consolidations among our competitors, which could significantly alter industry conditions and competition within the industry, and have a material adverse effect on our business, financial condition and results of operations. New technologies may cause our drilling methods and equipment to become less competitive and it may become necessary to incur higher levels of capital expenditures in order to keep pace with the bifurcation of rigsdisruptive trends in the drilling industry, and growthindustry. Growth through the building of new drilling rigs and improvement of existing rigs is not assured.
The market for our services is characterized by continual technological developments that have resulted in, and will likely continue to result in, substantial improvements in the functionality and performance of rigs and equipment. Our customers increasingly demand the services of newer, higher specification drilling rigs. This results in a bifurcation of the drilling fleet and is evidenced by the higher specification drilling rigs (e.g., AC rigs) generally operating at higher overall utilization levels and dayrates than the lower specification drilling rigs (e.g., SCR rigs). In addition, a significant number of lower specification rigs are being stacked and/or removed from service.
As a result of this demand for high-spec rigs, a higher level of capital expenditures will be required to maintain and improve existing rigs and equipment and purchase and construct newer, higher specification drilling rigs to meet the increasingly sophisticated needs of our customers.Although we take measures to ensure that we develop and use advanced oil and natural gas drilling technology, changes in technology or improvements
in competitors’ equipmentby competitors could make our equipment less competitive. There can be no assurance that we will:
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| | have sufficient capital resources to improve existing rigs or build new, technologically advanced drilling rigs;
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| | 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;
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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, businessmaintain crews necessary to operate existing or additional drilling rigs; or prospects as a result of improving existing drilling rigs or building new drilling rigs.
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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 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.
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.
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 business is subject to cybersecurity risks.
Our operations depend on effective and secure information technology systems. Threats to information technology systems, including as a result of cyberattacks and cyber incidents, continue to grow. Cybersecurity risks could include, but are not limited to, malicious software, attempts to gain unauthorized access to our data and the unauthorized release, corruption or loss of our data and personal information, interruptions in communication, loss of our intellectual property or theft of our FlexRig® and other sensitive or proprietary technology, loss or damage to our data delivery systems, or other cybersecurity and infrastructure systems, including our property and equipment. In response to the COVID-19 pandemic, the Company moved to a "remote work" model for office personnel in March 2020. This model has significantly increased the use of remote networking and online conferencing services that enable employees to work outside of our corporate infrastructure and, in some cases, use their own personal devices. This has resulted in increased demand for information technology resources and exposes the Company to additional cybersecurity risks, including unauthorized access to sensitive information as a result of increased remote access and other cybersecurity related incidents.
These cybersecurity risks could:
disrupt our operations and damage our information technology systems,
negatively impact our ability to compete,
enable the theft or misappropriation of funds,
cause the loss, corruption or misappropriation of proprietary or confidential information,
expose us to litigation, and
result in injury to our reputation, downtime, loss of revenue, and increased costs to prevent, respond to or mitigate cybersecurity events.
It is possible that our business, financial and other systems could be compromised, which could go unnoticed for a prolonged period of time. While various procedures and controls are being utilized to mitigate exposure to such risk, there can be no assurance that the procedures and controls that we implement, or which we cause third party service providers to implement, will be sufficient to protect our systems, information or other property. Additionally, customers or third parties upon whom we rely face similar threats, which could directly or indirectly impact our business and operations. The occurrence of a cyber incident or attack could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to incur additional costs to continue to modify or enhance our protective measures or to investigate or remediate the effects of cyber incidents.
Our acquisitions, dispositions and investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.
We continually seek opportunities to maximize efficiency and value through various transactions, including purchases or sales of assets, businesses, investments, or joint venture interests. For example, in November 2018 and August 2019, we completed the acquisitions of Angus Jamieson Consulting and DrillScan Energy SAS, respectively. These strategic transactions, among others, are intended to (but may not) result in the realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or income, or the reduction of risk. Acquisition transactions may use cash on hand or be financed by additional borrowings or by the issuance of our common stock. These transactions may also affect our liquidity, consolidated results of operations and consolidated financial condition.
These transactions also involve risks, and we cannot ensure that:
any acquisitions we attempt will be completed on the terms announced, or at all;
any acquisitions would result in an increase in income or provide an adequate return of capital or other anticipated benefits;
any acquisitions would be successfully integrated into our operations and internal controls;
the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, or that we will appropriately quantify the exposure from known risks;
any disposition would not result in decreased earnings, revenue, or cash flow;
use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other uses; or
any dispositions, investments, or acquisitions, including integration efforts, would not divert management resources.
We have allocated a portion of the purchase price of certain acquisitions to goodwill and other intangible assets. Generally, the amount allocated to goodwill is the excess of the purchase price over the net identifiable assets acquired. At September 30, 2020, we had goodwill of $45.7 million and other intangible assets, net of $81.0 million. If we experience future negative changes in our business climate or our results of operations such that we determine that goodwill or intangible assets are impaired, we will be required to record impairment charges with respect to such assets.
Technology disputes could negatively impact our operations or increase our costs.
Drilling rigs use proprietary technology and equipment which can involve potential infringement of a third party’s rights, or a third party’s infringement of our rights, including patent rights. The majority of the intellectual property rights relating to our drilling rigs and technology services are owned by us or certain of our supplying vendors. However, in the event that we or one of our customers or supplying vendors becomes involved in a dispute over infringement of intellectual property rights relating to equipment or technology owned or used by us, we may lose access to important equipment or technology, be required to cease use of some equipment or technology be forced to modify our drilling rigs or technology, or be required to pay license fees or royalties for the use of equipment or technology. In addition, we may lose a competitive advantage in the event we are unsuccessful in enforcing our rights against third parties. As a result, any technology disputes involving us or our customers or supplying vendors could have a material adverse impact on our business, financial condition and results of operations.
Unexpected events could disrupt our business and adversely affect our results of operations.
Unexpected or unanticipated events, including, without limitation, computer system disruptions, unplanned power outages, fires or explosions at drilling rigs, natural disasters such as hurricanes and tornadoes, war or terrorist activities, supply disruptions, failure of equipment, changes in laws and/or regulations impacting our businesses, pandemic illness and other unforeseeable circumstances that may arise from our increasingly connected world or otherwise, could adversely affect our business. It is not possible for us to predict the occurrence or consequence of any such events. However, any such events could create unforeseen liabilities, reduce our ability to provide drilling and related technology services, reduce demand for our services, or make it more difficult or costly to provide services, any of which may ultimately have a material adverse effect on our business, financial condition and results of operations.
Reliance on management and competition for experienced personnel may negatively impact our operations or financial results.
We greatly depend on the efforts of our executive officers and other key employees to manage our operations. Similarly, we utilize highly skilled personnel in operating and supporting our businesses and in developing new technologies. In times of high utilization, it can be difficult to find and retain qualified individuals and, during the recent period of sustained declines in oil and natural gas prices, there have been reductions in the oil field services workforce, both of which could result in higher labor costs. The loss of members of management or the inability to attract and retain qualified personnel could have a material adverse effect on our business, financial condition and results of operations. In addition, the unexpected loss of members of management, qualified personnel or a significant number of employees due to disease, including COVID-19, disability, or death, could have a detrimental effect on us.
The loss of one or a number of our large customers could have a material adverse effect on our business, financial condition and results of operations.
In fiscal year 2020, we received approximately 46 percent of our consolidated operating revenues from our ten largest drilling services and solutions customers and approximately 20 percent of our consolidated operating revenues from our three largest customers (including their affiliates). If one or more of our larger customers terminated their contracts, failed to renew existing contracts with us, or refused to award us with new contracts, it could have a material adverse effect on our business, financial condition and results of operations. Further, consolidation among oil and natural gas exploration and production companies may reduce the number of available customers.
Our current backlog of drilling services and solutions revenue may continue to decline and may not be ultimately realized as fixed‑term contracts and may, in certain instances, be terminated without an early termination payment.
Fixed‑term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to us. Even if an early termination payment is owed to us, a customer may be unable or may refuse to pay the early termination payment. We also may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, such as depressed market conditions. As of September 30, 2020, our drilling services backlog was approximately $0.7 billion for future revenues under firm commitments. Our drilling services backlog may decline over time as existing contract term coverage may not be offset by new term contracts or price modifications for existing contracts, as a result of any number of factors, such as low or declining oil prices and capital spending reductions by our customers. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse impact on our business, financial condition and results of operations.
Our contracts with national oil companies may expose us to greater risks than we normally assume in contracts with non-governmental customers.
We currently own and operate rigs and have deployed technology under contracts with foreign national oil companies. In the future, we may expand our international solutions operations and enter into additional, significant contracts with national oil companies. The terms of these contracts may contain non-negotiable provisions and may expose us to greater commercial, political, operational and other risks than we assume in other contracts. Foreign contracts may expose us to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, or under certain conditions that may not provide us with an early termination payment. We can provide no assurance that increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted, or the amount of technology deployed, to national oil companies with commensurate additional contractual risks. Risks that accompany contracts with national oil companies could ultimately have a material adverse impact on our business, financial condition and results of operations.
Our drilling services operating expense includes fixed costs that may not decline in proportion to decreases in rig utilization and dayrates.
Our drilling services operating expense includes all direct and indirect costs associated with the operation, maintenance and support of our drilling equipment, which is often not affected by changes in dayrates and utilization. During periods of reduced revenue and/or activity, certain of our fixed costs (such as depreciation) may not decline and often we may incur additional costs. During times of reduced utilization, reductions in costs may not be immediate as we may incur additional costs associated with maintaining and cold stacking a rig, or we may not be able to fully reduce the cost of our support operations in a particular geographic region due to the need to support the remaining drilling rigs in that region. Accordingly, a decline in revenue due to lower dayrates and/or utilization may not be offset by a corresponding decrease in drilling services and solutions expense, which could have a material adverse impact on our business, financial condition and results of operations.
We depend on a limited number of vendors, some of which are thinly capitalized, and the loss of any of which could disrupt our operations.
Certain key rig components, parts and equipment are either purchased from or fabricated by a single or limited number of vendors, and we have no long‑term contracts with many of these vendors. Shortages could occur in these essential components due to an interruption of supply, the acquisition of a vendor by a competitor, increased demands in the industry or other reasons beyond our control. Similarly, certain key rig components, parts and equipment are obtained from vendors that are, in some cases, thinly capitalized, independent companies that generate significant portions of their business from us or from a small group of companies in the energy industry. These vendors may be disproportionately affected by any loss of business, downturn in the energy industry or reduction or unavailability of credit. If we are unable to procure certain of such rig components, parts or equipment, our ability to maintain, improve, upgrade or construct drilling rigs could be impaired, which could have a material adverse effect on our business, financial condition and results of operations.
Shortages of drilling equipment and supplies could adversely affect our operations.
The drilling services and solutions business is highly cyclical. During periods of increased demand for drilling services and solutions and periods of supply chain disruption, including as a result of COVID-19, delays in delivery and shortages of drilling equipment and supplies can occur. Suppliers may experience quality control issues as they seek to rapidly increase production of equipment and supplies necessary for our operations. Additionally, suppliers may seek to increase prices for equipment and supplies, which we are unable to pass through to our customers, either due to contractual obligations or market constraints in the drilling services and solutions business. These risks are intensified during periods when the industry experiences significant new drilling rig construction or refurbishment. Any such delays or shortages could have a material adverse effect on our business, financial condition and results of operations.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our international employees are unionized, and efforts may be made from time to time to unionize other portions of our workforce. We may in the future be subject to strikes or work stoppages and other labor disruptions in connection with unionization efforts or renegotiation of existing contracts with unions representing our international employees. For example, worker strikes of short duration are common in Argentina and our operations have experienced such strikes in the past. Additional unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs, reduce our revenues or limit our operational flexibility.
Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.
Since our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse effect on our business, financial condition and results of operations.
Our business and results of operations may be adversely affected by foreign political, economic and social instability risks, foreign currency restrictions and devaluation, and various local laws associated with doing business in certain foreign countries.
We currently have drilling operations in South America (primarily Argentina and Colombia) and the Middle East. In the future, we may further expand the geographic reach of our operations. As a result, we are exposed to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of social unrest, strikes, terrorism, war, kidnapping of employees, nationalization, forced negotiation or modification of contracts, difficulty resolving disputes (including technology disputes) and enforcing contract provisions, expropriation of equipment as well as expropriation of oil and gas exploration and drilling rights, taxation policies, foreign exchange restrictions and restrictions on repatriation of income and capital, currency rate fluctuations, increased governmental ownership and regulation of the economy and industry in the markets in which we operate, economic and financial instability of national oil companies, and restrictive governmental regulation, bureaucratic delays and general hazards associated with foreign sovereignty over certain areas in which operations are conducted.
South American countries, in particular, have historically experienced uneven periods of economic growth, as well as recession, periods of high inflation and general economic and political instability. From time to time, these risks have impacted our business. For example, in Argentina, while our dayrate is denominated in U.S. dollars, we are paid in Argentine pesos. The Argentine branch of one of our second-tier subsidiaries then remits U.S. dollars to its U.S. parent by converting the Argentine pesos into U.S. dollars through the Argentine Foreign Exchange Market and repatriating the U.S. dollars. Argentina also has a history of implementing currency controls, which restrict the conversion and repatriation of U.S. dollars, including controls which were implemented in September 2019 and September 2020. As a result of these currency controls, our ability to remit funds from our Argentine subsidiary to its U.S. parent has been limited. Argentina’s economy is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent three-year period based on inflation data published by the respective governments. Nonetheless, all of our foreign operations use the U.S. dollar as the functional currency and local currency monetary assets and liabilities are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. For fiscal year 2020, we experienced aggregate foreign currency losses of $7.6 million in Argentina. Our aggregate foreign currency losses across all of our operations for fiscal years 2020 and 2019 were $8.8 million and $8.2 million, respectively. However, in the future, we may incur larger currency devaluations, foreign exchange restrictions or other difficulties repatriating U.S. dollars from Argentina or elsewhere, which could have a material adverse impact on our business, financial condition and results of operations.
Additionally, there can be no assurance that there will not be changes in local laws, regulations and administrative requirements or the interpretation thereof, which could have a material adverse effect on the profitability of our operations or on our ability to continue operations in certain areas. Because of the impact of local laws, our future operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we have limited control or hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities. There can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable.
The future occurrence of one or more international events arising from the types of risks described above could have a material adverse impact on our business, financial condition and results of operations.
Financial Risks
Covenants in our debt agreements restrict our ability to engage in certain activities.
Our current debt agreements pertaining to certain long‑term unsecured debt and our unsecured revolving credit facility contain, and our future financing arrangements likely will contain, various covenants that may in certain instances restrict our ability to, among other things, incur, assume or guarantee additional indebtedness, incur liens, sell or otherwise dispose of all or substantially all of our assets, enter into new lines of business, and merge or consolidate. In addition, our credit facility requires us to maintain a funded leverage ratio (as defined therein) of less than or equal to 50 percent and certain priority debt (as defined therein) may not exceed 17.5 percent of our net worth (as defined therein). Such restrictions may limit our ability to successfully execute our business plans, which may have adverse consequences on our operations.
We may be required to record impairment charges with respect to our drilling rigs and other assets.
We evaluate our drilling rigs and other assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Lower utilization and dayrates adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates may result in the recognition of impairment charges if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of an asset group may not be recoverable. Drilling rigs in our fleet may become impaired in the future if oil and gas prices remain low for a prolonged period of time, decline further or if market conditions deteriorate or if we restructured our drilling fleet. For example, in fiscal years 2020 and 2019, we recognized impairment charges of $563.2 million and $224.3 million, respectively, related to tangible assets and equipment. If we experience future negative changes in our business climate such that we determine that one or more of our asset groups are impaired, we will be required to record additional impairment charges with respect to such asset groups.
Any impairment could have a material adverse effect on our consolidated financial statements. The facts and circumstances included in our impairment assessments are described in Part II, Item 8— “Financial Statements and Supplementary Data.”
A downgrade in our credit ratings could negatively impact our cost of and ability to access capital.
Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by major U.S. credit rating agencies. Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, commodity pricing levels, industry conditions and other considerations, including the impact of COVID-19. A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.
Our ability to access capital markets could be limited.
From time to time, we may need to access capital markets to obtain financing. Our ability to access capital markets for financing could be limited by oil and gas prices, our existing capital structure, our credit ratings, the state of the economy, the health or market perceptions of the drilling and overall oil and gas industry, the liquidity of the capital markets and other factors, including the impact of COVID-19. There have also been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities as well as to pressure lenders and other financial services companies to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves, which, if successful, could limit our ability to access capital markets. Many of the factors that affect our ability to access capital markets are outside of our control. No assurance can be given that we will be able to access capital markets on terms acceptable to us when required to do so, which could have a material adverse impact on our business, financial condition and results of operations.
Our marketable securities may lose significant value due to credit, market and interest rate risks.
At September 30, 2020, we had marketable securities, primarily consisting of equity in Schlumberger, Ltd., with a total fair value of approximately $7.3 million. The total fair value of the security was $16.3 million at September 30, 2019. At November 12, 2020, the fair value increased to approximately $8.1 million. The value of this investment is subject to general credit, liquidity, market and interest rate risks, which may be exacerbated by unusual events, such as the COVID-19 pandemic. A further significant loss in value of the investment would negatively impact our debt ratio and financial strength.
We may not be able to generate cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations.
Our ability to make future scheduled payments on or to refinance our debt obligations, including any future debt obligations, depends on our financial position, results of operations and cash flows. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal and interest on our indebtedness. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investment decisions and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness. Furthermore, these alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial position at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would be a default (if not waived) and would likely result in a reduction of our credit rating, which could harm our ability to seek additional capital or restructure or refinance our indebtedness.
Changes in the method of determining the London Interbank Offered Rate, or the replacement of the London Interbank Offered Rate with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under our current debt agreements, including the 2018 Credit Facility (as defined herein), may bear interest at rates based on the London Interbank Offered Rate (“LIBOR”). On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The 2018 Credit Facility provides for a mechanism to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In the United States, the Alternative Reference Rates Committee has proposed the Secured Overnight Financing Rate ("SOFR") as an alternative to LIBOR for use in contracts that are currently indexed to U.S. dollar LIBOR and has proposed a paced market transition plan to SOFR. It is not presently known whether SOFR or any other alternative reference rates that have been proposed will attain market acceptance as replacements of LIBOR. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows.
Legal and Regulatory Risks
The physical effects of climate change and the regulation of greenhouse gases and climate change could have a negative impact on our business. The physical and regulatory effects of climate change could have a negative impact on our operations, our customers’ operations and the overall demand for our
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.
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, theThe U.S. President ofannounced the United States announced that the U.S. planned to withdraw from the Paris Agreement and to seek negotiations to either reenter the Paris Agreement on different terms or establish a new
framework agreement. The Paris Agreement provides for a four-year exit process beginning when itin June 2017. This withdrawal formally took effect in November 2016, which would result in an effective exit date of November4, 2020. The United States’ adherence to the exit process is uncertain and/or the terms onand timeline under which the United States may reenter the Paris Agreement, or a separately negotiated agreement, are unclear at this time.
The aim of the Paris Agreement was to hold the increase in the average global temperature to well below
2ºC (3.6ºF) above pre-industrial levels with efforts to limit the rise to 1.5ºC (2.7ºF) to protect against the more severe consequences of climate forecasted by scientific studies. These consequences include increased coastal flooding, droughts and associated 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.
It is not possible at this time to predict the timing and effect of climate change or to predict the
timing or effect of
rejoining the Paris Agreement or whether additional GHG legislation, regulations or other measures will be
adopted.adopted at the federal, state or local levels. However, more aggressive efforts by governments and non-governmental organizations to reduce GHG emissions appear likely based on the findings set forth in the 2018 IPCC Report and any such future laws and regulations could result in increased compliance costs,
or additional operating
restrictions.restrictions or affect the demand for our customers' products and, accordingly, our services. For example, a coalition of over 20 governors of U.S. states formed the United States Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have committed to advance the objectives of the Paris Agreement at the state or local level despite the federal withdrawal. To this end, the California governor issued an executive order on September 23, 2020 ordering actions to pursue GHG emissions reductions, including a direction to the California State Air Resources Board to develop and propose regulations to require increasing volumes of new zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the sale of new gasoline vehicles by 2035. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse impact on our business, financial condition and results of operations. Further, to the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of or access to capital. Climate change and GHG regulation could also negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide. An increased focus by the public on the reduction of GHG emissions as well as the results of the physical impacts of climate change could affect the demand for our customers’ products and have a negative effect on our business.
Beyond financial and regulatory impacts, the projected severe effects of climate change have the potential to directly affect our facilities and operations and those of our customers. See above “—Our drilling and technology related operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.”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
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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| | any acquisitions we attempt will be completed on the terms announced, or at all;
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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 legislation and regulatory initiatives relating to hydraulic fracturing or other aspects of the oil and gas industry could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide.
Several political and regulatory authorities, governmental bodies, and environmental groups devote resources to campaigns aimed at eradicating hydraulic fracking. We do not engage in any hydraulic fracturing activities. However, it is a common practice in our industry for our customers to recover natural gas and oil from shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations using water, sand and other additives pumped under high pressure into the formation. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure, waste disposal and/or well construction requirements on oil and gas development, including hydraulic fracturing operations, or otherwise seek to ban fracturing activities altogether. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Members of the U.S. Congress are analyzing, and a number of federal agencies are analyzing, or have historically been requested to review, and, under a new administration, may be requested to review again, a variety of environmental issues associated with hydraulic fracturing and the possibility of more stringent regulation. At September 30, 2020, we had approximately 15 rigs placed on federal land and eight rigs in federal waters. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide. For example, the Environmental Protection Agency has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels. Widespread regulation significantly restricting or prohibiting hydraulic fracturing or other drilling activity by our customers could have a material adverse impact on our business, financial condition and results of operations.
Further, we conduct drilling activities in numerous states, including Oklahoma, where seismic activity may occur. In recent years, Oklahoma has experienced an increase in earthquakes. Although the extent of any correlation has been and remains the subject of studies of both federal and state agencies, some parties believe that there is a correlation between hydraulic fracturing related activities and the increased occurrence of seismic activity. As a result, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing activities. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques, operational delays or increased operating and compliance costs in the production of oil and natural gas from shale plays, added difficulty in performing hydraulic fracturing, and potentially a decline in the completion of new oil and gas wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the services we provide.
Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti‑bribery legislation could adversely affect our business.
The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti‑bribery laws in other jurisdictions, including the United Kingdom Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to non-U.S. officials for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti‑bribery laws may conflict with local customs and practices and impact our business. Although we have programs in place requiring compliance with anti‑bribery legislation, any failure to comply with the FCPA or other anti‑bribery legislation could subject us to civil and criminal penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operation. In addition, investors could negatively view potential violations, inquiries or allegations of misconduct under the FCPA or similar laws, which could adversely affect our reputation and the market for our shares. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs or other assets.
Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.
The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs. For example, the EU has adopted EU General Data Protection Regulation 2016/679 (Regulation (EU) 2016/679 of the European Parliament and of the Council of 27 April 2016), which imposes severe penalties of up to the greater of 4% of worldwide turnover or 20 million Euro.
Any failure, or perceived failure, by us to comply with applicable data protection laws could result in heightened risk of litigation, including private rights of action, and proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of cyber incidents or attacks, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Government policies, mandates, and regulations specifically affecting the energy sector and related industries, regulatory policies or matters that affect a variety of businesses, taxation polices, and political instability could adversely affect our financial condition and results of operations.
Energy production and trade flows are subject to government policies, mandates, regulations, and trade agreements. Governmental policies affecting the energy industry, such as taxes, tariffs, duties, price controls, subsidies, incentives, foreign exchange rates, economic sanctions and import and export restrictions, can influence the viability and volume of production of certain commodities, the volume and types of imports and exports, whether unprocessed or processed commodity products are traded, and industry profitability. For example, the decision of the U.S. government to impose tariffs on certain Chinese imports and the resulting retaliation by the Chinese government imposing a 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.
The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. We design much of our own equipment and fabricate and upgrade such equipment in facilities that we operate. We also design and develop our own technology. If such equipment or technology fails to perform as expected, or if we fail to maintain or operate the equipment properly, there could be personal injuries, property damage, and environmental contamination, which could result in claims against us. Our ownership and use of proprietary technology and equipment could also result in infringement of intellectual property claims against us. See above “— Technology disputes could negatively impact our operations or increase our costs." In addition, during periods of depressed market conditions we may be subject to an increased risk of our customers, vendors, former employees and others initiating legal proceedings against us. Further, actions or decisions we have taken or may take as a consequence of COVID-19 may result in investigations, litigation or legal claims against us. Lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations. Any litigation or claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.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
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 ofsignificant net operating lossesdeferred tax liability could affect our financial condition, income tax provision, net income, and tax credits.
cash flows.
We are subject to income taxes in the United States and numerous other jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes and other tax liabilities. In the ordinary course of our business, there are many transactions and calculations where the ultimate tax determination is uncertain. We are regularly audited by tax authorities. Although we believe our tax estimates are reasonable, the final determination of tax audits and any related litigation could be materially different than what is reflected in income tax provisions and accruals. An audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows in the period or periods challenged. Tax rates in the various jurisdictions in which our subsidiaries are organized and conduct their operations may change significantly as a result of political or economic factors beyond our control. It is also possible that future changes to tax laws (including tax treaties in any of the jurisdictions that we operate in) could impact our ability to realize the tax savings recorded to date. Our ability to benefit from our deferred tax assets depends on us having sufficient future taxable income to utilize our net operating loss and tax credit carryforwards before they expire. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes an annual limitation on the amount of net operating losses and other pre-change tax attributes (such as tax credits) that may be used to offset taxable income by a corporation that has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more shareholders (or groups of shareholders) that are each deemed to own at least 5 percent of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage during a rolling three-year period. As of September 30, 2018, we have not experienced an ownership change and, therefore, our utilization of our net operating loss carryforwards was not subject to an annual limitation. However, if we were to experience ownership changes in the future as a result of subsequent shifts in our stock ownership, our ability to use our pre-change net operating loss carryforwards to offset future taxable income may be subject to limitations, which could potentially result in increased future tax liability to us. Furthermore, our acquisition of MOTIVE caused MOTIVE to undergo an ownership change and, as a result, the pre-change net operating losses of MOTIVE are subject to limitation under Section 382; however, based on the amount of such net operating losses subject to the limitation, we do not expect that the application of the Section 382 limitation will have a material impact on our overall future tax liabilities. In addition, at the state level, there may be periods during which the use of net operating loss carryforwards is suspended or otherwise limited, which could accelerate or permanently increase state taxes owed. In any case, our net operating loss and tax credit carryforwards are subject to review and potential disallowance upon audit by
the tax authorities of the jurisdictions where these tax attributes are incurred. Additionally, our future effective tax rates could be adversely affected by changes in tax laws (including tax treaties) or their interpretation.
On December 22, 2017, the President of the United States signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Reform Act”) that significantly reforms the Code. The Tax Reform Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, (v) imposes new limitations on the deductibility of interest expense, (vi) imposes a type of minimum tax designed to reduce the benefits derived from intercompany transactions and payments that result in base erosion, and (vii) provides for more general changes to the taxation of corporations, including changes to cost recovery rules. These tax law changes could have the effect of causing us to incur income
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 considered to be other than temporary, the change in value is recorded as a charge through earnings. During the fourth quarter of fiscal year 2016, we determined that a loss was other‑than‑temporary and we recognized a $26.0 million
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 equipmentaforementioned factors as well as expropriation of oilothers 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 timesubject 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
change.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.
Risks Related to Our Common Stock and Corporate Structure
We may reduce or suspend our dividend in the future.
We have paid a quarterly dividend for many years. Our most recent quarterly dividend was $0.25 per share. In the future, our Board of Directors may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position the Company for long‑term success. The declaration and amount of future dividends is at the discretion of our Board of Directors and will depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our Board of Directors deems relevant. The likelihood that dividends will be reduced or suspended is increased during periods of prolonged market weakness or uncertainty, such as the current downturn as a result of the COVID-19 outbreak and the oil price collapse in 2020. In addition, our ability to pay dividends may be limited by agreements governing our indebtedness now or in the future. There can be no assurance that we will not reduce our dividend or that we will continue to pay a dividend in the future.
The market price of our common stock may be highly volatile, and investors may not be able to generate cash to service allresell shares at or above the price paid.
The trading price of our
indebtedness, andcommon stock may be
forcedvolatile. 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
take other
actions to satisfyfactors described in this “Risk Factors” section and elsewhere in this Form 10-K, may have a significant impact on the market price of our
obligations.Ourcommon stock:
changes in customer needs, expectations or trends and our ability to make future scheduled payments onmaintain relationships with key customers;
our ability to implement our business strategy;
changes in our capital structure, including the issuance of additional debt;
public announcements (including the timing of these announcements) regarding our business, financial performance and prospects or to refinancenew products or services, product enhancements, technological advances or strategic actions, such as acquisitions, restructurings or significant contracts, by our debt obligations,competitors or us;
trading activity in our stock, including any future debt obligations, depends onportfolio transactions in our financial position,stock by us, our executive officers and directors, and significant stockholders or trading activity that results from the ordinary course rebalancing 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,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 significant from time to time;
our inclusion in, or removal from, any stock indices;
investor perception of us and the industry and markets in which we operate;
increased focus by the investment community on sustainability practices at higher interest ratesour company and may require us to comply with more onerous covenants, which could further restrict our business operations. Any failure to make paymentsin 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 interestsecurities analysts who follow us;
regulatory or legal developments in the United States and principal on our outstanding indebtedness on a timely basis would be a default (if not waived)foreign countries where we operate; and would likely result
general financial, domestic, international, economic, and market conditions, including overall fluctuations 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
the U.S. equity markets. defined therein) may not exceed 17.5 percent of our net worth (as defined therein). Such restrictions may limit our ability to successfully execute our business plans, which may have adverse consequences on our operations.
Certain provisions of our corporate governing documents could make an acquisition of our company more difficult.
The following provisions of our charter documents, as currently in effect, and Delaware law could discourage potential proposals to acquire us, delay or prevent a change in control of us or limit the price that investors may be willing to pay in the future for shares of our common stock:
| ·
| | our certificate of incorporation permits our Board of Directors to issue and set the terms of preferred stock and to adopt amendments to our bylaws;
|
| ·
| | our bylaws contain restrictions regarding the right of stockholders to nominate directors and to submit proposals to be considered at stockholder meetings;
|
our 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
|
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.
|
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. Item 1B. UNRESOLVED STAFF COMMENT
| |
| 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 20182020 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, Texas as well as a
fabrication facility and a maintenance and overhaul facility near Tulsa, Oklahoma.
We also own several commercial real estate properties for investment purposes. Our real estate investments are located exclusively within Tulsa, Oklahoma, and include a shopping center multi-tenant industrial warehouse properties, and undeveloped real estate.
Item 3. LEGAL PROCEEDINGS
See Note 17—Commitments and Contingencies to our Consolidated Financial Statements for information regarding our legal proceedings.
Venezuela Expropriation
Our wholly‑owned subsidiaries, Helmerich & Payne International Drilling Co. and Helmerich & Payne de Venezuela, C.A. filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A. and PDVSA Petroleo, S.A. We are seeking damages for the taking of our Venezuelan drilling business in violation of international law and for breach of contract. While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery.
Item 4. MINE SAFETY DISCLOSURES
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, 2018,12, 2020, there were
394425 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 Drilling Index. All cumulative returns assume an initial investment of $100, the reinvestment of dividends and are calculated on a fiscal year basis ending on September 30 of each year.
| | | | | | | | | | | | |
| | | | 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 2015 | | Sep 2016 | | Sep 2017 | | Sep 2018 | | Sep 2019 | | Sep 2020 |
| Helmerich & Payne, Inc. | 100.00 | | 148.00 | | 122.00 | | 163.00 | | 109.00 | | 60.00 |
| S&P 500 Index | 100.00 | | 115.00 | | 136.00 | | 159.00 | | 166.00 | | 189.00 |
| Dow Jones U.S. Select Oil Equipment & Services Index | 100.00 | | 110.00 | | 102.00 | | 105.00 | | 55.00 | | 27.00 |
| PHLX Oil Service Index | 100.00 | | 106.00 | | 94.00 | | 100.00 | | 48.00 | | 25.00 |
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 “Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Stock Portfolio Held”Operations — Liquidity and Capital Resources — Investing Activities — Marketable Securities” included in this Form
10‑10‑K.Item 6. SELECTED FINANCIAL DATA
| |
| Item 6. | SELECTED FINANCIAL DATA |
The following table summarizes selected financial information and should be read in conjunction with Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8—
“Financial “Financial Statements and Supplementary Data” included in this Form
10‑10‑K.Five‑
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 | |
|
| | | | | | | | | | | | | | | | | | | |
| (in thousands except per share amounts) | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| Statements of Operations Selected Data | | | | | | | | | |
| Operating revenues | $ | 1,773,927 |
| | $ | 2,798,490 |
| | $ | 2,487,268 |
| | $ | 1,804,741 |
| | $ | 1,624,332 |
|
| Depreciation and amortization | 481,885 |
| | 562,803 |
| | 583,802 |
| | 585,543 |
| | 598,587 |
|
| Selling, general and administrative | 167,513 |
| | 194,416 |
| | 199,257 |
| | 147,548 |
| | 140,486 |
|
| Income (loss) from continuing operations | (496,392 | ) | | (32,510 | ) | | 493,010 |
| | (127,863 | ) | | (52,990 | ) |
| Income (loss) from discontinued operations | 1,895 |
| | (1,146 | ) | | (10,338 | ) | | (349 | ) | | (3,838 | ) |
| Net income (loss) | (494,497 | ) | | (33,656 | ) | | 482,672 |
| | (128,212 | ) | | (56,828 | ) |
| | | | | | | | | | |
| Per Share Data | | | | | | | | | |
| Basic earnings (loss) per share from continuing operations | $ | (4.62 | ) | | $ | (0.33 | ) | | $ | 4.49 |
| | $ | (1.20 | ) | | $ | (0.50 | ) |
| Basic earnings (loss) per share from discontinued operations | 0.02 |
| | (0.01 | ) | | (0.10 | ) | | — |
| | (0.04 | ) |
| Basic earnings (loss) per share | $ | (4.60 | ) | | $ | (0.34 | ) | | $ | 4.39 |
| | $ | (1.20 | ) | | $ | (0.54 | ) |
| | | | | | | | | | |
| Diluted earnings (loss) per share from continuing operations | $ | (4.62 | ) | | $ | (0.33 | ) | | $ | 4.47 |
| | $ | (1.20 | ) | | $ | (0.50 | ) |
| Diluted earnings (loss) per share from discontinued operations | 0.02 |
| | (0.01 | ) | | (0.10 | ) | | — |
| | (0.04 | ) |
| Diluted earnings (loss) per share | $ | (4.60 | ) | | $ | (0.34 | ) | | $ | 4.37 |
| | $ | (1.20 | ) | | $ | (0.54 | ) |
| | | | | | | | | | |
| Cash dividends declared per common share | $ | 2.38 |
| | $ | 2.84 |
| | $ | 2.82 |
| | $ | 2.80 |
| | $ | 2.78 |
|
| | | | | | | | | | |
| Balance Sheet Data | | | | | | | | | |
| Cash, cash equivalents and short-term investments | $ | 577,219 |
| | $ | 400,903 |
| | $ | 325,816 |
| | $ | 565,866 |
| | $ | 949,709 |
|
| Property, plant and equipment, net | 3,646,341 |
| | 4,502,084 |
| | 4,857,382 |
| | 5,001,051 |
| | 5,144,733 |
|
Total assets (1) | 4,829,621 |
| | 5,839,515 |
| | 6,214,867 |
| | 6,439,988 |
| | 6,832,019 |
|
Total debt (2) | 487,148 |
| | 487,148 |
| | 500,000 |
| | 500,000 |
| | 500,000 |
|
| Total shareholders' equity | 3,318,514 |
| | 4,012,223 |
| | 4,382,735 |
| | 4,164,591 |
| | 4,560,925 |
|
Debt to capital ratio (3) | 12.8 | % | | 10.8 | % | | 10.2 | % | | 10.7 | % | | 9.9 | % |
Net debt to net capital ratio (4) | (2.7 | )% | | 2.1 | % | | 3.8 | % | | (1.6 | )% | | (9.9 | )% |
Net working capital (5) | $ | 194,198 |
| | $ | 381,708 |
| | $ | 490,663 |
| | $ | 401,499 |
| | $ | 368,965 |
|
| |
| (1) | | Total assets for all years include amounts related to discontinued operations. Our Venezuelan subsidiary was classified as discontinued operations on June 30, 2010, after the seizure of our drilling assets in that country by the Venezuelan government. |
| |
| (2) | Total debt excludesunamortized discount and debt issuance cost. Refer to Note 8—Debt. |
| |
| (3) | The debt to capital ratio is calculated by dividing total debt by total capitalization (total debt, excluding unamortized discount and debt issuance cost, plus shareholders’ equity). The debt to capital ratio is not a measure of operating performance or liquidity defined by U.S. GAAP and may not be comparable to similarly titled measures presented by other companies. |
| (3)
|
| (4) | Net debt to net capital ratio is calculated as the excess of our total debt over total cash, cash equivalents and short-term investments divided by total shareholders' equity plus any positive net debt balances. The net debt to net capital ratio is not a measure of operating performance or liquidity defined by U.S. GAAP and may not be comparable to similarly titled measures presented by other companies. |
| Net
|
| (5) | For the purpose of understanding the impact on our Cash Flow from Operations, net working capital is calculated as current assets, excluding cash and short-term investments, less current liabilities.liabilities, excluding dividends payable, short–term debt and the current portion of long–term debt. Net working capital is not a measure of operating performance or liquidity defined by U.S. GAAP and may not be comparable to similarly titled measures presented by other companies. |
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 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-- “Risk Factors.” Accordingly, past results and trends should not be used by investors to anticipate future results or trends.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,
2018,2020, our drilling rig fleet included a total of
390302 drilling rigs. Our
contract drilling
services and solutions segments consist of the
U.S. LandNorth America Solutions segment with
350262 rigs, the Offshore
Gulf of Mexico segment with
8eight offshore platform rigs and the International
LandSolutions segment with 32 rigs as of September 30,
2018.2020. At the close of fiscal year
2018,2020, we had
25979 contracted rigs, of which
15356 were under a
fixed termfixed-term contract and
10623 were working well-to-well, compared to 218 contracted rigs at
the same time during the prior year. As the U.S. land drilling industry recovered from an all-time low of approximately 380 active rigs in the summer of 2016 to over 1,000 rigs as of September 30,
2018, we led the way in reactivating rigs in the United States and gained significant market share in the process. We believe that our success during this time frame is validation of the capabilities of our land drilling fleet and our decisions during the downturn to prepare for an eventual improvement in the business, and our ability to deliver best-in-class field performance and customer satisfaction.2019. Our long-term strategy remains focused on innovation, technology, safety, operational excellence and reliability. As we move forward, we believe that our advanced uniform rig fleet,
technology offerings, financial strength,
long term contract backlog and strong customer and employee base position us very well to
respond to continued volatile market conditions and take advantage of future opportunities.
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. Since the beginning of the calendar year 2020, crude oil prices fell from approximately $60 per barrel to the low-to-mid-$20 per barrel range, lower in some cases. Consequently, we have seen a significant decrease in customer 2020 capital budgets representing a decline of nearly 50% from calendar year 2019 levels. There has been a corresponding dramatic decline in the demand for land rigs, such that the overall rig count for calendar year 2020 will average significantly less than in calendar year 2019.
During calendar year 2020, our North American Solutions rig count has declined from 195 contracted rigs at December 31, 2019 to 69 contracted rigs at September 30, 2020. Of the 69 contracted rigs at September 30, 2020, 58 are active with 11 stacked. When contracted rigs are stacked, they remain under the terms of the contract but typically pay a reduced rate, where the remaining term days are generally not reduced, but our operating expenses are typically reduced. We experienced much of our rig count decline during our second and third fiscal quarters with the absolute level of our rigs remaining relatively stable during the fourth fiscal quarter. Additionally, during our fourth fiscal quarter, the market experienced a stabilization of crude oil prices in the $40 per barrel range. At such levels, we believe our customers will have more robust capital budgets entering into 2021 and are already seeing evidence of this in our near-term rig count activity projections. Consequently, we believe we will experience a higher level of rig activity in fiscal year 2021 compared to super-specwhere we stand today. However, given the current levels of commodity prices and the lasting impacts of the global pandemic, we do not expect or anticipate customers' capital budgets will support activity levels like those experienced prior to meet our customers’ needs. In addition, there will be more opportunities driven by our marketing effortsMarch 2020.
Utilization for our nonsuper-spec FlexRig® fleet peaked in late calendar year 2018 with 216 of 221 super-spec rigs (e.g. FlexRig4)working (98 percent utilization); however, the recent decline in the demand for land rigs resulted in customers idling a large portion of our super-spec FlexRig® fleet. At September 30, 2020, we had 167 idle super-spec rigs out of our FlexRig® fleet of 234 super-spec rigs (29% percent utilization).
Collectively, our other business segments, Offshore Gulf of Mexico and International Solutions, are exposed to the same macro environment adversely affecting our North America Solutions segment and those unfavorable factors are creating similar challenges for these business segments as well.
H&P recognizes the uncertainties and concerns caused by the COVID-19 pandemic; however, we have managed the Company over time to be in a position of strength both financially and operationally when facing uncertainties of this magnitude. The COVID-19 pandemic has had an indirect, yet significant financial impact on the Company. The global response to coping with the pandemic has resulted in a drop in demand for crude oil, which, when combined with a more than adequate supply of crude oil, has resulted in a sharp decline in crude oil prices, causing our customers to have pronounced pullbacks in their operations and planned capital expenditures. The direct impact of COVID-19 on H&P's operations has created some challenges that we believe the Company is adequately addressing to ensure a robust continuation of our operations albeit at a lower activity level.
The Company is an ‘essential critical infrastructure’ company as defined by the Department of Homeland Security and the Cybersecurity and Infrastructure Security Agency and, as such, continues to operate rigs and technology solutions, providing valuable services to our customers in support of the global energy infrastructure.
The health and safety of all H&P stakeholders - our employees, customers, and vendors - remain a top priority at the Company. Accordingly, H&P has implemented additional policies and procedures designed to protect the well-being of our stakeholders and to minimize the impact of COVID-19 on our ongoing operations. Some of the safeguards we have implemented include:
The Company mobilized a global COVID-19 response team to manage the evolving situation
The Company moved to a global "remote work" model for office personnel (beginning March 13, 2020)
The Company suspended all non-essential travel
We are adhering to Center for Disease Control ("CDC") guidelines for evaluating actual and potential COVID-19 exposures
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| ◦ | Operational and third-party personnel are required to complete a COVID-19 questionnaire prior to reporting to a field location and office personnel are required to complete one prior to returning to their respective offices in order to evaluate actual and potential COVID-19 exposures and individuals identified as being high risk are not allowed on location |
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| ◦ | The temperatures of operational personnel are taken prior to them being allowed to enter a rig site |
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| ◦ | The Company has implemented enhanced sanitization and cleaning protocols |
We are complying with local governmental jurisdiction policies and procedures where our operations reside; in some instances, policies and procedures are more stringent in our foreign operations than in our North America operations and this has resulted in a complete suspension, for a certain period of time, of all drilling operations in at least one foreign jurisdiction
As of September 30, 2020, the Company was aware that 109 out of its approximately 4,100 employees have had confirmed cases of COVID-19 since the COVID-19 outbreak began, of which we believe approximately 52% contracted the virus outside of their work location. We have had no fatalities and 100 of 109 employees who had confirmed cases have returned to work. Upon being notified that an employee has tested positive, the Company follows pre-established guidelines and places the employee on leave as appropriate. Per CDC Guidelines, employees testing positive are permitted to return to their worksite after 10 days. Employees who are considered a Level 1 exposure but who have not tested positive are required to quarantine and are permitted to return to their worksite after 14 days. In addition, the market, targetingCompany applies its enhanced sanitization procedures to the employee’s work location prior to allowing employees to re-enter the location. Since the COVID-19 outbreak began, no rigs have been fully shut down (other than temporary shutdowns for disinfecting) and such measures to disinfect facilities have not had a significant impact on customer programsservice. We believe our service levels are unchanged from pre-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. We have taken measures to reduce costs and capital expenditures to levels that better reflect a lower activity environment. Actions taken during the second quarter of fiscal year 2020 included a reduction to the annual dividend of approximately $200 million, a reduction in planned fiscal year 2020 capital spend of $95 million, and a reduction of over $50 million in fixed operational overhead. During the third quarter of fiscal year 2020, the Company took further steps to reduce its planned fiscal year 2020 capital spend by another $40 million and its selling, general and administrative cost structures by another $25 million on an annualized basis. The culmination of these cost-saving initiatives resulted in a $16.0 million restructuring charge during fiscal year 2020. We anticipate further cost reductions in our International Solutions operations as well and are working through local jurisdictional regulations to implement those measures. At September 30, 2020, the Company had cash and cash equivalents and short-term investments of $577.2 million and availability under the 2018 Credit Facility (as defined herein) of $750.0 million resulting in approximately $1.3 billion in near-term liquidity. We currently do not require super-spec capabilitiesanticipate the need to draw on the 2018 Credit Facility.
As part of the Company's normal operations, we regularly monitor the creditworthiness of our customers and canvendors, screening out those that we believe have a high risk of failure to honor their counter-party obligations either through payment or delivery of goods or services. We also perform routine reviews of our accounts receivable and other amounts owed to us to assess and quantify the ultimate collectability of those amounts. At September 30, 2020, the Company had a net allowance against its accounts receivable of $1.8 million and incurred bad debt expense of $2.2 million during fiscal year 2020. Subsequent to March 31, 2020, we adjusted our credit risk monitoring for specific customers, in response to the recent economic events described above.
The nature of the COVID-19 pandemic is inherently uncertain, and as a result, the Company is unable to reasonably estimate the duration and ultimate impacts of the pandemic, including the timing or level of any subsequent recovery. As a result, the Company cannot be offered atcertain of the degree of impact on the Company’s business, results of operations and/or financial position for future periods.
Recent Developments
Restructuring
Beginning in the third quarter of fiscal year 2020, we implemented cost controls and began evaluating further measures to respond to the combination of weakened commodity prices, uncertainties related to the COVID-19 pandemic, and the resulting market volatility. We restructured our operations to accommodate scale during an industry downturn and to re-organize our operations to align to new marketing and management strategies. We commenced a lower price point while still exceedingnumber of restructuring efforts as a result of this evaluation, which included, among other things a reduction in our return hurdles. capital allocation plans, changes to our organizational structure, and a reduction of staffing levels. Refer to Note 19—Restructuring Charges to our Consolidated Financial Statements.
Business Segments
During the third quarter of fiscal year 2020, as part of our restructuring efforts (see Note 19—Restructuring Charges to our Consolidated Financial Statements) and consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, we implemented organizational changes. We are also seeing growing interestmoving from customersa product-based offering, such as a rig or separate technology package, to enteran integrated solution-based approach by combining proprietary rig technology, automation software, and digital expertise into multi-year contracts. Ifour rig operations. Operations previously reported within the market remains strongformer U.S. Land and H&P Technologies operating and reportable segments are now managed and presented within the North America Solutions reportable segment. As a result, beginning with the third quarter of fiscal year 2020, our drilling services operations are organized into the following reportable operating business segments: North America Solutions, Offshore Gulf of Mexico and International Solutions. All prior period segment disclosures have been recast for these segment changes. Our real estate operations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are included in "Other." Consolidated revenues and expenses reflect the elimination of intercompany transactions.
Self-Insurance
On October 1, 2019, we elected to utilize a wholly-owned insurance captive (“Captive”) to insure the deductibles for our workers’ compensation, general liability and automobile liability insurance programs. Casualty claims occurring prior to October 1, 2019 will remain recorded within each of the operating segments' and future adjustments to these claims will continue to be reflected within the operating segments. Reserves for legacy claims occurring prior to October 1, 2019, will remain as liabilities in our operating segments until they have been resolved. Changes in those reserves will be reflected in segment earnings as they occur. We will continue to utilize the Captive to finance the risk of loss to equipment and rig property assets. The Company and the
supplyCaptive maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of
economically viable super-spec rigs is depleted,significant events covered under these programs. Our operating subsidiaries are paying premiums to the
potentialCaptive, typically on a monthly basis, for
newly built rigsthe estimated losses based on an external actuarial analysis. These premiums are currently held in a restricted account, resulting in a transfer of risk from our operating subsidiaries to the Captive. The actuarial estimated underwriting expenses for the fiscal year ended September 30, 2020 were approximately $16.4 million and were recorded within drilling services operating expenses in our Consolidated Statement of Operations. Intercompany premium revenues and expenses during the fiscal year ended September 30, 2020 amounted to $36.9 million, which were eliminated upon consolidation. These intercompany insurance premiums are reflected as segment operating expenses within the North America Solutions, Offshore Gulf of Mexico, and International Solutions reportable operating segments and are reflected as intersegment sales within "Other." The Company self-insures employee health plan exposures in excess of employee deductibles. Starting in the
industry may return, but we expectsecond quarter of fiscal year 2020, the Captive insurer issued a stop-loss program that
much higher levelswill reimburse the Company's health plan for claims that exceed $50,000. This program will also be reviewed at the end of
pricing and term contract coverage will be required beforeeach policy year by an outside actuary. One hundred percent of the
industry sees significant capital deployed for new build rigs.In our International Land Drilling segment, we believe that our market leading position instop-loss premium is being set aside by the Neuquén basin of Argentina may provide opportunities for us to deploy additional AC rigs from the United States. We have seen periodic spot market work for our deeper drilling 3,000 horsepower rigs in Northern Argentina. Spot market contracts doCaptive as reserves. The stop-loss program does not have a defined term and operatematerial impact on a well-by-wellconsolidated basis. In
Dispositions
During the fiscal year
2018,ended September 30, 2020, we
reactivated four rigs in Colombia with renewed interest inclosed on the
deeper drilling 3,000 horsepower rigs as well as our two FlexRig3 rigs. We expect Colombia to besale of a
relatively stable market in fiscal year 2019 with potential upside. Overall, we have seen an increase in tendering activity from our customers in the international market resulting from higher oil prices. We believe that our international land operations are a potential area of growth over the next several years, but acknowledge that such growth may be more sporadic than what we expect in the U.S. market.At this time, our Offshore Drilling operations are expected to report relatively stable utilization and cash flows in the upcoming fiscal year. We anticipate one or moreportion of our platform rigs could either be stacked or placed onreal estate investment portfolio, including six industrial sites, for total consideration, net of selling related expenses, of $40.7 million and an aggregate net book value of $13.5 million, resulting in a lower margin stack rate towards the endgain of fiscal year 2019.
Recent Developments
Acquisitions
On December 8, 2017, we completed an acquisition (“MagVAR Acquisition”) of an unaffiliated company, Magnetic Variation Services, LLC (“MagVAR”),$27.2 million, which is nowincluded within Gain on Sale of Assets on our Consolidated Statement of Operations.
In December 2019, we closed on the sale of a wholly-owned subsidiary of
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 International Drilling Co. ("HPIDC"), TerraVici Drilling Solutions, Inc. common stock. At closing, $6.0 million("TerraVici"). As a result of the cash considerationsale, 100% of TerraVici's outstanding capital stock was placed in escrow, to be releasedtransferred to the sellers twelve months afterpurchaser in exchange for approximately $15.1 million, resulting in a total gain on the acquisition closing date. Transaction costs relatedsale of TerraVici of approximately $15.0 million. Prior to the MagVAR Acquisition incurred duringsale, TerraVici was a component of the North America Solutions operating segment. This transaction does not represent a strategic shift in our operations and will not have a significant effect on our operations and financial results going forward.
Impairments
During the second quarter of fiscal year 2018 were approximately $1.2 million and are recorded2020, 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 Consolidated Statementsdemand due to the COVID-19 pandemic.
Property, Plant and Equipment and Inventory During the second quarter of Operations within selling, general and administrative expense.On June 2, 2017, we completed a merger transaction (“MOTIVE Merger”) pursuant to which an unaffiliated drilling technology company, MOTIVE Drilling Technologies, Inc., a Delaware corporation (“MOTIVE”), was merged with and into our wholly-owned subsidiary Spring Merger Sub, Inc., a Delaware corporation. MOTIVE survived the transaction and is now a wholly-owned subsidiary of the Company.
MOTIVE has a proprietary Bit Guidance System™ that is an algorithm-driven system that considers the total economic consequences of directional drilling decisions and is designed to consistently lower drilling costs through more efficient drilling and increased hydrocarbon production through smoother wellbores and more accurate well placement. Given our strong and longstanding technology and innovation focus, we believe the technology will continue to advance and provide further benefits for the industry.
At the effective time of the MOTIVE Merger, MOTIVE shareholders received aggregate cash consideration of $74.3 million, net of customary closing adjustments. During fiscal year 2018, MOTIVE shareholders received additional cash consideration2020, to maintain a competitive edge in a challenging market, the Company’s management introduced a new strategy focused on operating various types of $10.6 million in an earnout payment and may be eligible to receive up to an additional $12.5 million in potential earnout payments based on future performance. Transaction costs related to the MOTIVE Merger incurred during fiscal year 2017 were $3.2 million and are recorded in the Consolidated Statements of Operations within selling, general and administrative expense.
Additional information regarding the MagVAR and MOTIVE acquisitions is described in Note 3--Business Combinations to our consolidated financial statements. The operations for MagVAR and MOTIVE are included within our other non-reportable business segments. The MagVAR and MOTIVE Mergers were accounted for as a business combination in accordance with Accounting Standards Codification (“ASC”) 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values.
Impairments
Consistent with our policy, we evaluate our drillinghighly capable upgraded rigs and related equipment for impairment whenever events or changesphasing out the older, less capable fleet. This resulted in circumstances indicategrouping the carrying valuesuper-spec rigs of these assets may exceed the estimated undiscounted future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessment on the future marketability of specific rigs’ asset group. Given the continued low utilization within our International 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 rigs’ asset groups may potentially be impaired.
At September 30, 2018,
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 theeach asset group is not recoverable through estimated undiscounted future cash flows withand recorded a surplusnon-cash impairment charge of approximately 23 percent. $441.4 million in the Consolidated Statement of Operations for the fiscal year ended September 30, 2020. Of the $441.4 million total impairment charge recorded, $292.4 million and $149.0 million was recorded in the North America Solutions and International Solutions segments, respectively. Impairment was measured as the amount by which the net book value of each asset group exceeds its fair value. No further impairments were recognized in fiscal year 2020.
The most significant assumptions used in our undiscounted cash flow model include: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. TheThese assumptions are consistentclassified as Level 3 inputs by Accounting Standards Codification ("ASC") Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts.
In determining the fair value of each asset group, we utilized a combination of income and market approaches. The significant assumptions in the valuation are based on those of a market participant and are classified as Level 2 and Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures.
As of March 31, 2020, the Company also recorded an additional non-cash impairment charge related to in-progress drilling equipment and rotational inventory of $44.9 million and $38.6 million, respectively, which had aggregate book values of $68.4 million and $38.6 million, respectively, in the Consolidated Statement of Operations for the fiscal year ended September 30, 2020. Of the $83.5 million total impairment charge recorded for in-progress drilling equipment and rotational inventory, $75.8 million and $7.7 million was recorded in the North America Solutions and International Solutions segments, respectively.
Goodwill Consistent with our policy, we test goodwill annually for impairment in the fourth quarter of our fiscal year, or more frequently if there are indicators that goodwill might be impaired. Due to the market conditions described above, during the second quarter of fiscal year 2020, we concluded that goodwill and intangible assets might be impaired and tested the H&P Technologies reporting unit, where the goodwill balance is allocated and the intangible assets are recorded, for recoverability. This resulted in a goodwill only non-cash impairment charge of $38.3 million recorded in Asset Impairment Charge on the Consolidated Statement of Operations during the fiscal year ended September 30, 2020.
The recoverable amount of the H&P Technologies reporting unit was determined based on a fair value calculation which uses cash flow projections based on the Company’s internal budgetsfinancial projections presented to the Board covering a five-year period, and forecastsa discount rate of 14 percent. Cash flows beyond that five-year period were extrapolated using the fifth-year data with no implied growth factor. The reporting unit level is defined as an operating segment or one level below an operating segment.
The recoverable amount of the intangible assets tested for impairment within the H&P Technologies reporting unit is determined based on undiscounted cash flow projections using the Company’s financial projections presented to the Board covering a five-year period and extrapolated for the remaining weighted average useful lives of the intangible assets.
The most significant assumptions used in our cash flow model include timing on awards of future
years.contracts, commercial pricing terms, utilization, discount rate, and the terminal value. 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 weightedprobability-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,are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and our resulting conclusion.
At September 30, 2018, we engaged a third party independent accounting firm who performed a market valuation, utilizing the market approach, on two of our domestic and international conventional rigs’ asset groups, which have aggregate net book values of $9.0 million and $15.2 million, respectively. We concluded that the fair values of these two asset groups exceed the net book values by approximately 64 percent and 141 percent, respectively, and as such, no impairment was recorded. The significant assumptions in the valuation exercise are classified as Level 2 and Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures.
During the fourth quarter of fiscal year 2018, after ceasing operations in Ecuador, within our International Land segment, we entered into a sales negotiation with respect to the six conventional rigs, within a separated international conventional rigs’ asset group, with net book values of $20.8 million, present in the country, pursuant to which the rigs, together with associated equipment and machinery would be sold to a third party to be recycled. Certain components of these rigs with an $8.5 million net book value, that are not subject to the sale agreement, will be transferred to the United States to be utilized on other FlexRigs with high activity and demand. The sales transaction was completed in November 2018. We recorded a non-cash impairment charge of $9.2 million ($7.0 million, net of tax, or $0.06 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018. As a result, the remaining rig within the same asset group, not to be disposed of, was written down resulting in an additional impairment charge of $1.4 million ($1.0 million, net of tax, or $0.01 per diluted share).
Furthermore, during the fourth quarter of fiscal year 2018, within our U.S. Land segment, management committed to a plan to auction several previously decommissioned rigs during fiscal year 2019. As a result, we wrote them down to their estimated fair values. We recorded a non-cash impairment charge of $5.7 million ($4.2 million, net of tax, or $0.04 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018.
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, 20182020 and 2017
2019
Consolidated Results of Operations
All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Except as specifically discussed, the following results of operations pertain only to our continuing operations.
Net Income (Loss)Our net incomeLossWe reported a loss from continuing operations of $496.4 million ($4.62 loss per diluted share) from operating revenues of $1.8 billion for the fiscal year 2018 was $482.7ended September 30, 2020 compared to a loss from continuing operations of $32.5 million ($4.39 earnings0.33 loss per diluted share), compared with from operating revenues of $2.8 billion for the fiscal year ended September 30, 2019. Included in the net loss for the fiscal year ended September 30, 2020 is income of $1.9 million ($0.02 impact per diluted share) from discontinued operations. Including discontinued operations, we recorded a net loss of $128.2$494.5 million ($1.204.60 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, 2020 compared to a net loss of $33.7 million ($0.130.34 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, 2019.
RevenueConsolidated operating revenues were $2.5 billion in fiscal year 2018 and $1.8 billion in fiscal year 2017,2020 and $2.8 billion in fiscal year 2019, including early termination revenue of $17.1$73.4 million and $29.4$11.3 million in each respective fiscal year. Excluding early termination revenue, operating revenue increased $694.8 milliondecreased $1.1 billion in fiscal year 20182020 compared to fiscal year 2017. Oil prices steeply declined from over $106 per barrel2019. The decrease 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 of2020 from fiscal year 2018, oil prices were mostly in the $62 to $77 per barrel price range. Primarily2019 was driven by lower activity and pricing as a result of the impact ofcollapse in oil prices on drillingthat occurred in March 2020, which drove our customers to quickly reduce rig activity by explorationbeginning in the second half of March 2020 and production companies during that time frame,continuing throughout the numberremainder of revenue days in our U.S. Land segment totaled 77,980fiscal year 2020.
Direct Operating Expenses, Excluding Depreciation and Amortization Direct operating expenses in fiscal year 2018,2020 were $1.2 billion, compared to 57,120with $1.8 billion in fiscal year 2017.Asset Impairment Management monitors industry market conditions impacting its long‑lived assets,2019. The decrease in fiscal year 2020 from fiscal year 2019 was primarily attributable to the previously-mentioned lower activity levels.
Depreciation and Amortization Depreciation and amortization expense was $481.9 million in fiscal year 2020 and $562.8 million in fiscal year 2019. The decrease in depreciation and amortization during fiscal year ended September 30, 2020 compared to fiscal year ended September 30, 2019 was primarily attributable to the lower carrying cost of our impaired assets. Depreciation and amortization includes amortization of intangible assets of $7.2 million and goodwill. When required, an impairment analysis$5.8 million in fiscal years 2020 and 2019, respectively, and abandonments of equipment of $4.0 million and $11.4 million in fiscal years 2020 and 2019, respectively.
Research and Development For the fiscal years ended September 30, 2020 and 2019, we incurred $21.6 million and $27.5 million, respectively, of research and development expenses. The decrease in expense was primarily due to reduced spending related to the development of rotary steerable system tools given the December 2019 sale of TerraVici.
Selling, General and Administrative Expense Selling, general and administrative expenses decreased to $167.5 million in the fiscal year ended September 30, 2020 compared to $194.4 million in the fiscal year ended September 30, 2019. The $26.9 million decrease in fiscal year 2020 compared to fiscal year 2019 is performedprimarily due to determine if any impairment exists. During the fourthlower accrued variable compensation expense and a reduction of staffing levels that was implemented in third quarter of fiscal year 2018,2020.
Asset Impairment During the fiscal year ended September 30, 2020, we impaired several assets, including inventory, property, plant 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 recordedgoodwill, which resulted in a non-cash impairment charge of $9.2 million. The remaining rig within the same asset group, not to be disposed of, was written down resulting in an additional impairment charge of $1.4$563.2 million ($1.0437.5 million, net of tax, or $0.01$5.21 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, which is included in Asset Impairment Charge on the Consolidated Statement of Operations forOperations. Comparatively, during the fiscal year ended September 30, 2018. We did not record any2019, mainly driven by the downsizing of our fleet of FlexRig® 4 drilling rigs, we wrote down excess capital spares and drilling support equipment, which had an aggregate net book value of $235.3 million, and as a result, an asset impairment charge of $224.3 million ($195.0 million, net of tax, or $1.78 per diluted share) was recorded in our Consolidated Statements of Operations.
Restructuring Charges Beginning in the third quarter of fiscal year 2017.2020, we implemented cost controls and began evaluating further measures to respond to the combination of weakened commodity prices, uncertainties related to the COVID-19 pandemic, and the resulting market volatility. We commenced a number of restructuring efforts as a result of this evaluation, which included, among other things, a reduction in our capital allocation plans, changes to our organizational structure, and a reduction of staffing levels. For the fiscal year ended September 30, 2020, we incurred $16.0 million in restructuring charges.
Interest and Dividend IncomeInterest and dividend income was $8.0$7.3 million and $5.9$9.5 million in fiscal years 20182020 and 2017,2019, respectively. The higherdecrease in interest and dividend income in fiscal year 20182020 was primarily due to higher earnings on available cash equivalents and short-term investments. Direct Operating Expenses Direct operating expenses in fiscal year 2018 were $1.7 billion, compared with $1.2 billion in fiscal year 2017. The increase in fiscal year 2018 from fiscal year 2017 was primarily attributable to a higher level of activity in fiscal year 2018.
lower interest rates. General and AdministrativeInterest Expense General and administrative expenses Interest expense totaled $200.6$24.5 million in fiscal year 20182020 and $151.0$25.2 million in fiscal year 2017. During fiscal year 2018, we incurred transaction costs of $1.2 million related to our acquisition of MagVAR. Additionally, increased employee general and administrative headcount, primarily as a result of the acquisition of MagVAR and MOTIVE, caused an increase in employee compensation costs, including taxes, benefits and stock-based compensation, compared to fiscal year 2017.
Depreciation and Amortization Depreciation and amortization expense was $583.8 million in fiscal year 2018 and $585.5 million in fiscal year 2017. Depreciation and amortization includes amortization of intangible assets of $5.4 million and $1.1 million in fiscal years 2018 and 2017, respectively, and abandonments of equipment of $27.7 million and $42.6 million in fiscal years 2018 and 2017, respectively. In fiscal year 2018, depreciation expense also includes $9.7 million of accelerated depreciation for components on rigs that are planned for conversion in fiscal year 2019. Depreciation expense, exclusive of abandonments and accelerated depreciation, increased one percent in fiscal year 2018 from fiscal year 2017. As the drilling markets continued to recover during fiscal year 2017, we began abandoning older rig components that were replaced by upgrades to our rig fleet to meet customer demands for additional capabilities. This trend continued in fiscal year 2018.
Interest Interest expense, net of amounts capitalized, totaled $24.3 million in fiscal year 2018 and $19.7 million in fiscal year 2017. Interest expense is primarily attributable to fixed‑rate debt outstanding. Capitalized interest was $0.4 million and $0.3 million in fiscal years 2018 and 2017, respectively. All of the capitalized interest is attributable to our rig upgrade and rig construction programs.
Income TaxesWe had an income tax benefit of $477.2$140.1 million in fiscal year 20182020 compared to an income tax benefit of $56.7$18.7 million in fiscal year 2017.2019. The effective income tax rate was (3,012.3)22.0 percent in fiscal year 20182020 compared to 30.736.5 percent in fiscal year 2017.2019. 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 2020 and 35.0 percent for fiscal year 2017)2019) 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—9—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 20172020 and 20182019 is primarily a result of the impact of exchange rate fluctuations on remaining in country assets anddue to the remeasurement of uncertain tax liabilities. 38
North America SolutionsThe following table presents certain information with respect to our North America Solutions reportable segment:
|
| | | | | | | | | | |
| (in thousands, except operating statistics) | 2020 | | 2019 (1) | | % Change |
| Operating revenues | $ | 1,474,380 |
| | $ | 2,426,191 |
| | (39.2 | )% |
| Direct operating expenses | 942,277 |
| | 1,532,576 |
| | (38.5 | ) |
| Depreciation | 438,039 |
| | 504,466 |
| | (13.2 | ) |
| Research and development | 20,699 |
| | 25,164 |
| | (17.7 | ) |
| Selling, general and administrative expense | 53,714 |
| | 66,179 |
| | (18.8 | ) |
| Asset impairment charge | 406,548 |
| | 216,908 |
| | 87.4 |
|
| Restructuring charges | 7,005 |
| | — |
| | — |
|
| Segment operating income (loss) | $ | (393,902 | ) | | $ | 80,898 |
| | (586.9 | ) |
Operating Statistics (2): | |
| | | | |
| Revenue days | 49,003 |
| | 81,805 |
| | (40.1 | ) |
Average rig revenue per day (3) | $ | 26,589 |
| | $ | 26,167 |
| | 1.6 |
|
Average rig expense per day (3) | 15,730 |
| | 15,243 |
| | 3.2 |
|
Average rig margin per day (3) | $ | 10,859 |
| | $ | 10,924 |
| | (0.6 | ) |
| Number of rigs at the end of period | 262 |
| | 299 |
| | (12.4 | ) |
| Rig utilization | 47 | % | | 67 | % | | (29.9 | ) |
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) | Operations previously reported within the H&P Technologies reportable segment are now managed and presented within the North America Solutions reportable segment. |
| |
| (2) | These operating metrics allow investors to analyze the various components of segment financial results in terms of volume, revenue per unit, cost per unit and margin per unit. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. |
| |
| (3) | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑“out‑of‑pocket” expenses of $242,617$171.5 million and $148,218$285.6 million for fiscal years 20182020 and 2017,2019, respectively. |
Operating Income (Loss)In fiscal year 2018, the U.S. Land The North America Solutions segment had operating income of $150.7 million compared to an operating loss of $94.9$393.9 million for the fiscal year ended September 30, 2020 compared to operating income of $80.9 million for the fiscal year ended September 30, 2019. The decrease was primarily driven by increased asset impairment charges and reduced rig activity in fiscal year 2017.2020. Revenues were $1.5 billion and $2.4 billion in fiscal year 2020 and 2019, respectively. Included in U.S. land revenues for fiscal years 2018 and 2017year 2020 is approximately $17.1 million and $24.5 million, respectively, from early termination revenue of fixed‑term contracts. Fixed‑$68.8 million compared to $6.4 million during fiscal year 2019. Fixed‑term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term (except in limited circumstances including sustained unacceptable performance by us). RevenueExcluding early termination per day revenue of $219$1,404 and $428 per day$78 for fiscal years 20182020 and 2017,2019, respectively, average rig revenue per day fordecreased by $904 to $25,185 primarily due to a portion of our contracted rigs operating in an idle-but-contracted state during the third and fourth quarters of fiscal year 2018 increased by $1,013 to $23,192 from $22,1792020, with lower average daily revenue and average daily expense and lower pricing for rigs working in fiscal year 2017. Our activity increased year-over-year in response to higher commodity prices resulting in a 36.5 percent increase in revenue days when comparing fiscal year 2018the spot market. Compared to fiscal year 2017. 2019, our revenue days declined by 40.1 percent. This decline was initially driven by the collapse in oil prices that occurred in March of 2020, which led our customers to quickly reduce rig activity beginning in the second half of March 2020 and continuing throughout fiscal year 2020. Our level of contracted rigs hit a low of 62 rigs in August of 2020 before modestly recovery to 69 rigs at fiscal year end.
Direct Operating ExpensesDirect Average rig expense per day increased $487 to $1.3 billion in$15,730 during the fiscal year 2018 from $984.2 million in fiscal year 2017. This increase was primarily attributable to increased activity. Additionally, we implemented a wage increase for our field personnel in some regions in April 2018.General and Administrative Expense In fiscal year 2018,general and administrative expense increased 14.7 percentended
September 30, 2020 compared to 2017. This change was primarily driven by an increase in employee headcount, which resulted in an increase in employee compensation, including taxes, benefits and stock-based compensation.Asset Impairment ChargeDuring the fourth quarter of fiscal year 2018, management committed to a plan to auction several previously decommissioned rigs during fiscal year 2019. As a result, we wrote these rigs down to their estimated fair values and recorded a non-cash impairment charge of $5.7 million, which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018.
2019. The increase is due to higher self-insurance expenses and idle rig expenses, partially offset by the previously mentioned effect of idle-but-contracted rigs.
DepreciationDepreciation expense decreased to $438.0 million during the fiscal year ended September 30, 2020 compared to the fiscal year ended September 30, 2019. The decrease in depreciation during fiscal year ended September 30, 2020 compared to fiscal year ended September 30, 2019 was primarily attributable to the lower carrying cost of our impaired assets. Depreciation includes charges for abandoned equipment of $26.3$2.5 million and $42.2$10.6 million infor the fiscal years 2018ended September 30, 2020 and 2017,2019, respectively. In the fiscal year 2018,ended September 30, 2020, depreciation expense also includes $9.7included $1.5 million of accelerated depreciation for components on rigs that are scheduled for conversion in fiscal year 2019. As the drilling markets continued2021 as compared to recover during$4.7 million of accelerated depreciation for fiscal year 2017, we began abandoning older rig components to meet customer demands for additional capabilities. This trend continued inended September 30, 2019.
Asset Impairment ChargeDuring the fiscal year 2018. Excludingended September 30, 2020, we impaired our Domestic non-super-spec asset group, in addition to in-progress drilling equipment and rotational inventory. This resulted in an aggregate non-cash impairment charge of $368.2 million ($284.1 million, net of tax, or $3.41 per diluted share) for the abandonments and accelerated depreciation, depreciation in fiscal year 2018 increased fromended September 30, 2020. During the fiscal year 2017. ended
September 30, 2020, we also recorded a goodwill impairment loss of $38.3 million ($29.6 million, net of tax, or $0.35 per diluted share). Comparatively, during the fiscal year ended September 30, 2019, we recorded an asset impairment charge of $216.9 million ($188.6 million, net of tax, or $1.72 per diluted share), mainly driven by the downsizing of our fleet of FlexRig® 4 drilling rigs. These non-cash impairment charges are included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal years ended September 30, 2020 and 2019. Restructuring Charges For the fiscal year ended September 30, 2020, we incurred $7.0 million in restructuring charges primarily comprised of one-time severance benefits to employees as a result of headcount reductions that occurred during the third fiscal quarter of 2020.
UtilizationRig utilization increaseddecreased to 6147 percent infor the fiscal year 2018 from 45ended September 30, 2020 compared to 67 percent induring the fiscal year 2017. The total number of available rigs at bothended September 30, 20182019. In addition to the previously mentioned reduction in revenue days, we decommissioned two rigs and 35 rigs from our legacy Domestic Conventional asset group and FlexRig® 3 asset group, respectively effective as of April 30, 2020. At September 30, 2017 was 350. At September 30, 2018, 2322020
, 69 out of 350262 existing rigs in the U.S. LandNorth America Solutions segment were generating revenue.contracted. Of the 23269 contracted rigs, generating revenue, 13654 were under fixed‑termfixed-term contracts and 9615 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.market. 39
The following table presents certain information with respect to our Offshore Gulf of Mexico reportable segment:
|
| | | | | | | | | | |
| (in thousands, except operating statistics) | 2020 | | 2019 | | % Change |
| Operating revenues | $ | 143,149 |
| | $ | 147,635 |
| | (3.0 | )% |
| Direct operating expenses | 119,371 |
| | 114,306 |
| | 4.4 |
|
| Depreciation | 11,681 |
| | 10,010 |
| | 16.7 |
|
| Selling, general and administrative expense | 3,365 |
| | 3,725 |
| | (9.7 | ) |
| Restructuring charges | 1,254 |
| | — |
| | — |
|
| Segment operating income | $ | 7,478 |
| | $ | 19,594 |
| | (61.8 | ) |
Operating Statistics (1): | | | | | |
| Revenue days | 1,922 |
| | 2,163 |
| | (11.1 | ) |
Average rig revenue per day (2) | $ | 45,145 |
| | $ | 37,478 |
| | 20.5 |
|
Average rig expense per day (2) | 37,410 |
| | 28,663 |
| | 30.5 |
|
Average rig margin per day (2) | $ | 7,735 |
| | $ | 8,815 |
| | (12.3 | ) |
| Number of rigs at the end of period | 8 |
| | 8 |
| | — |
|
| Rig utilization | 66 | % | | 74 | % | | (10.8 | ) |
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) | These operating metrics allow investors to analyze the various components of segment financial results in terms of volume, revenue per unit, cost per unit and margin per unit. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. |
| |
| (2) | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑“out‑of‑pocket” expenses of $20,279$30.4 million and $21,578$26.4 million for fiscal years 20182020 and 2017,2019, respectively. The operating statistics only include rigs owned by usthat we own and exclude offshore platform management and contract labor service contractsrevenues of $26.0 million and $40.1 million, offshore platform management and contract labor service expenses of $17.0 million and $25.9 million, and currency revaluation expense.expense of $30.1 thousand and $1.0 thousand for fiscal years 2020 and 2019, respectively. |
Operating Income InDuring the fiscal year 2018,ended September 30, 2020, the Offshore Gulf of Mexico segment had operating income of $26.1$7.5 million compared to operating income of $24.2$19.6 million infor the fiscal year 2017.ended September 30, 2019. This decrease is primarily attributable to lower contribution from two rigs that demobilized back to shore during the first quarter of fiscal year 2020. One of the two rigs began mobilizing to a new platform during March 2020 and commenced drilling operations during the third quarter of fiscal year 2020. Additionally, we incurred $4.2 million of bad debt expense during fiscal year 2020.
RevenueAverage rig revenue per day increased 20.5 percent to $45,145 in fiscal year 20182020 compared to fiscal year 20172019. This was primarily due to several rigs movingone of our customers shifting its activity from a customer-owned rig managed by H&P to higher pricing from previous standby or other special dayrates. During April 2018, a previously idle rig commenced work on a customer’s platform.owned by H&P.
Direct Operating ExpensesAverage rig expense per day increased to $26,009 per day in fiscal year 2018 from $23,172 per day in fiscal year 2017. This increase was primarily attributable to rig start-up expenses and unfavorable adjustments to self-insurance expenses related to workers’ compensation.Depreciation Depreciation expense decreased 11.7 percent in fiscal year 2018 compared to fiscal year 2017. This change was primarily driven by two rigs becoming fully depreciated$37,410 during fiscal year 2018.
Utilization During2020 from $28,663 during fiscal year 2019, primarily due to factors mentioned above.
Restructuring Charges For the secondfiscal year ended September 30, 2020, we incurred $1.3 million in restructuring charges primarily comprised of one-time severance benefits to employees as a result of headcount reductions that occurred during the third fiscal quarter of fiscal year 2017, we sold one2020.
Utilization As of September 30, 2020, five of our offshore rigs. At September 30, 2018,eight available platform rigs were under contract, compared to six of our eight platform rigs were contracted compared to five of the eight available platform rigs atas of September 30, 2017.2019.
International Land Operations SegmentSolutions
| | | | | | | | | |
| | 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 | |
|
| | | | | | | | | | |
| (in thousands, except operating statistics) | 2020 | | 2019 | | % Change |
| Operating revenues | $ | 144,185 |
| | $ | 211,731 |
| | (31.9 | )% |
| Direct operating expenses | 124,791 |
| | 157,856 |
| | (20.9 | ) |
| Depreciation | 17,531 |
| | 35,466 |
| | (50.6 | ) |
| Selling, general and administrative expense | 4,565 |
| | 5,624 |
| | (18.8 | ) |
| Asset impairment charge | 156,686 |
| | 7,419 |
| | 2,012.0 |
|
| Restructuring charges | 2,980 |
| | — |
| | — |
|
| Segment operating income (loss) | $ | (162,368 | ) | | $ | 5,366 |
| | (3,125.9 | ) |
Operating Statistics (1): | | | | | |
| Revenue days | 4,605 |
| | 6,426 |
| | (28.3 | ) |
Average rig revenue per day (2) | $ | 29,116 |
| | $ | 31,269 |
| | (6.9 | ) |
Average rig expense per day (2) | 23,066 |
| | 21,626 |
| | 6.7 |
|
Average rig margin per day (2) | $ | 6,050 |
| | $ | 9,643 |
| | (37.3 | ) |
| Number of rigs at the end of period | 32 |
| | 31 |
| | 3.2 |
|
| Rig utilization | 40 | % | | 55 | % | | (27.3 | ) |
| |
| (1) | These operating metrics allow investors to analyze the various components of segment financial results in terms of volume, revenue per unit, cost per unit and margin per unit. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. |
| |
| (2) | Operating statistics for per day revenue, expense and margin do not include reimbursements of “out‑of‑“out‑of‑pocket” expenses of $11,828$10.1 million and $10,074$10.8 million for fiscal years 20182020 and 2017,2019, respectively. Also excluded are the effects of currency revaluation incomeexpense of $8.5 million and expense.$8.1 million for fiscal years 2020 and 2019, respectively. |
Operating Loss Income (Loss)The International LandSolutions segment had an operating loss of $0.7$162.4 million for fiscal year 20182020 compared to an operating lossincome of $7.2$5.4 million for fiscal year 2017.
Revenue Our activity has increased2019. The decrease was primarily in response to higher commodity prices.driven by asset impairment charges during fiscal year 2020.
Revenue We experienced a 35.228.3 percent increasedecrease in revenue days when comparing fiscal year 20182020 to fiscal year 2017.2019. The average number of active rigs was 18.212.6 during fiscal year 20182020 compared to 13.617.6 during fiscal year 2017.2019. Average rig revenue per day decreased by 6.9 percent primarily due to a shifting rig mix.
Direct Operating ExpensesAlthough direct operating expenses increased in fiscal year 2018 to $177.9 million from $163.5 million in fiscal year 2017, the average Average rig expense per day decreased by $5,550, an 18.7 percent decreaseincreased to $23,066 during fiscal year 2020 as compared to $21,626 during fiscal year 2019. The increase was driven by lower activity coupled with fixed minimum levels of country overhead.
Depreciation Depreciation expense decreased to $17.5 million during the fiscal year 2017 average rig expense. Included in direct operating expenses are foreign currency transaction losses of $4.0 million and $6.0 million for fiscal years 2018 and 2017, respectively. The losses are primarily due to an ongoing devaluation of the Argentine peso beginning in December 2015.Depreciation Depreciation expense decreased 12.7 percent in fiscal year 2018ended
September 30, 2020 compared to fiscal year 2017. This decrease was due to several rig components in Argentina that became fully depreciated during fiscal year 2018. Asset Impairment ChargeDuring the fourth quarter of fiscal year 2018, after ceasing operations in Ecuador, we entered into a sales negotiation with respect to six conventional rigs, with net book values of $20.8 million, present in the country, pursuant to which the rigs, together with associated equipment and machinery, would be sold to a third party to be recycled. Certain components of these rigs with an $8.5 million net book value, that are not subject to the sale agreement, will be transferred to the United States to be utilized on other FlexRigs with high activity and demand. The sales transaction was completed in November 2018. We recorded a non-cash impairment charge of $9.2 million ($7.0 million, net of tax, or $0.06 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018 related2019. The decrease in depreciation during fiscal year ended September 30, 2020 compared to these rigs. As a result,fiscal year ended September 30, 2019 was primarily attributable to the remaining rig withinlower carrying cost of our impaired assets.
Asset Impairment ChargeDuring the samefiscal year ended September 30, 2020, we impaired our International Conventional, FlexRig® 3, and FlexRig® 4 asset group, notgroups, in addition to be disposed of, was written down resultingrotational inventory. This resulted in an additionalaggregate non-cash 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 from 36 percent in fiscal year 2017 to 49 percent in fiscal year 2018. The increase was driven by the increase in rig activity as discussed above.
Other Operations
Results of our other operations, excluding corporate selling, general and administrative costs and corporate depreciation, are as follows:
| | | | | | | | | |
| | 2018 | | 2017 | | % Change |
| | (in thousands, except operating statistics) |
Operating revenues | | $ | 38,217 | | $ | 15,983 | | 139.1 | % |
Direct operating expenses | | | 44,390 | | | 18,552 | | 139.3 | |
Selling, general and administrative expense | | | 15,801 | | | 1,756 | | 799.8 | |
Depreciation and amortization | | | 8,332 | | | 5,124 | | 62.6 | |
Asset impairment charge | | | 5,637 | | | — | | 100.0 | |
Operating loss | | $ | (35,943) | | $ | (9,449) | | 280.4 | |
Operating Loss Other operations in fiscal year 2018 had an operating loss of $35.9 million compared to an operating loss of $9.4 million in fiscal year 2017. The change was primarily driven by the acquisition of MagVAR in December 2017 and twelve full months of operations of MOTIVE,, which was acquired in June 2017. Refer to Note 3—Business Combinations of the Consolidated Financial Statements for additional disclosures.
Asset Impairment Charge During the fourth quarter of fiscal year 2018, we recorded goodwill and intangible assets impairment losses of $5.6 million related to the TerraVici technology reporting unit where $4.7 million goodwill was allocated. This impairment loss is included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018.
Results of Operation for2020. Comparatively, during the Fiscal Years Endedfiscal year ended September 30, 2017 and 2016
Consolidated Results of Operations
All per share amounts included in2019, mainly driven by 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 impairmentdownsizing of our marketable equity security position in Atwood Oceanics, Inc. (“Atwood”). Net loss in fiscal year 2016 also includes an after‑tax lossfleet of $12.0 million ($0.11 loss per share) from the settlement of litigationFlexRig® 4 drilling rigs, we wrote down capital spares 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 2017drilling support equipment 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 of $7.4 million, in the U.S. Land segmentour Consolidated Statements of $6.3 million to reduceOperations for 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 fromended September 30, percent in2019.
Restructuring Charges For the fiscal year 2016. The total number of rigs atended September 30, 2017 was 3502020, we incurred $3.0 million in restructuring charges primarily comprised of one-time severance benefits to employees as a result of headcount reductions that occurred during the third fiscal quarter of 2020.
Utilization Our utilization decreased during fiscal year 2020 compared to 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. 2019. At September 30, 2017, 1972020, five out of 35032 existing rigs in the U.S. LandInternational Solutions segment were generating revenue.contracted. Of the 197five contracted rigs, generating revenue, 100two were under fixed-term contracts and 97three 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 as compared to the fiscal year 2016 average rig expense. Included in direct operating expenses are foreign currency transaction losses of $6.0 million and $9.8 million for fiscal years 2017 and 2016, respectively. The fiscal year 2016 losses were primarily due to a devaluation of the Argentine peso in December 2015.
Depreciation Depreciation decreased slightly by 6.1 percent in fiscal year 2017 compared to fiscal year 2016 due to some assets becoming fully depreciated during the year.
Other Operations
Results of our other operations, excluding corporate selling, general and administrative costs, corporate restructuring, 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 | |
|
| | | | | | | | | | |
| (in thousands) | 2020 | | 2019 | | % Change |
| Operating revenues | $ | 49,114 |
| | $ | 12,933 |
| | 279.8 | % |
| Direct operating expenses | 41,027 |
| | 5,382 |
| | 662.3 |
|
| Depreciation and amortization | 1,241 |
| | 1,523 |
| | (18.5 | ) |
| Research and development | 946 |
| | 2,303 |
| | (58.9 | ) |
| Selling, general and administrative expense | 1,237 |
| | 350 |
| | 253.4 |
|
| Restructuring charges | 260 |
| | — |
| | — |
|
| Operating income | $ | 4,403 |
| | $ | 3,375 |
| | 30.5 |
|
Operating Loss Other operations inIncome On October 1, 2019, we elected to utilize the Captive to insure the deductibles for our workers’ compensation, general liability and automobile liability claims programs. Direct operating costs include accruals for estimated losses of approximately $16.4 million allocated to the Captive during the fiscal year 2017 had an operating lossended September 30, 2020. Intercompany premium revenues recorded by the Captive during the fiscal year ended September 30, 2020 amounted to $36.9 million, which were eliminated upon consolidation.
Results of $9.4 millionOperations for the Fiscal Years Ended September 30, 2019 and 2018
A discussion of our results of operations for the fiscal year ended September 30, 2019 compared to an operating loss of $7.5 million inthe fiscal year 2016. The change was primarily drivenended September 30, 2018 is included in Part II, Item 7— "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2019, filed with the SEC on November 15, 2019, and is incorporated by 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
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
portfoliomarketable securities. Likewise, if we are generating excess cash flows, 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. TheOur marketable securities are recorded at fair value.We may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity as necessary, fund our additional purchases, exchange or redeem
Senior Notes,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 outbreak and the oil price collapse in 2020 have had significant adverse consequences for general economic, financial and business conditions, as well as for our business and financial position and the business and financial position of our customers, suppliers and vendors and may, among other things, impact our ability to generate cash flows from operations, access the capital markets on acceptable terms or at all and affect our future need or ability to borrow under the 2018 Credit Facility. In addition to our potential sources of funding, the effects of such global events may impact our liquidity or need to alter our allocation or sources of capital, implement additional cost reduction measures and further change our financial strategy. Although the COVID-19 outbreak and the oil price collapse could have a broad range of effects on our sources and uses of liquidity, the ultimate effect thereon, if any, will depend on future developments, which cannot be predicted at this time.
Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling rigs under contract, the dayrates we receive under those contracts, the efficiency with which we operate our drilling units, the timing of collections on outstanding accounts receivable, the timing of payments to our vendors for operating costs, and capital
expenditures.expenditures, all of which was impacted by the COVID-19 outbreak and the oil price collapse in 2020. As our revenues increase, net working capital is typically a use of capital, while conversely, as our revenues decrease, net working capital is typically a source of capital. To date, general inflationary trends have not had a material effect on our operating margins.
As of September 30, 2018,2020, we had $284.4$487.9 million of cash and cash equivalents on hand and $41.5$89.3 million of short-term investments. Our cash flows for the fiscal years ended September 30, 2018, 20172020, 2019 and 20162018 are presented below:
| | | | | | | | | |
| | Year Ended |
| | September 30, |
(in thousands) | | 2018 | | 2017 | | 2016 |
| | | | | As adjusted (Note 2) |
Net cash provided (used) by: | | | | | | | | | |
Operating activities | | $ | 544,531 | | $ | 361,631 | | $ | 754,531 |
Investing activities | | | (472,362) | | | (444,988) | | | (234,219) |
Financing activities | | | (309,189) | | | (300,829) | | | (344,135) |
Increase (decrease) in cash and cash equivalents | | $ | (237,020) | | $ | (384,186) | | $ | 176,177 |
|
| | | | | | | | | | | |
| | Year Ended September 30, |
| (in thousands) | 2020 | | 2019 | | 2018 |
| Net cash provided (used) by: | | | | | |
| Operating activities | $ | 538,881 |
| | $ | 855,751 |
| | $ | 557,852 |
|
| Investing activities | (87,885 | ) | | (422,636 | ) | | (472,362 | ) |
| Financing activities | (297,220 | ) | | (376,329 | ) | | (319,814 | ) |
| Net increase (decrease) in cash and cash equivalents and restricted cash | $ | 153,776 |
| | $ | 56,786 |
| | $ | (234,324 | ) |
For the purpose of understanding the impact on our Cash Flow from Operations, net working capital
is calculated as current assets, excluding cash and short-term investments,
increased $87.6 million to $412.6less current liabilities, excluding dividends payable, short–term debt and the current portion of long–term debt. Net working capital was $194.2 million as of September 30,
2018 from $325.02020 compared to $381.7 million as of September 30,
2017 due primarily to an increase2019. Included in accounts receivable
as of September 30, 2020 were $5.2 million of early termination fees and
inventories$42.4 million of
materials and supplies, offsetincome tax receivables. Cash flows provided by
an increase in accrued liabilities. Net cash provided from operating activities was
$544.5$538.9 million in fiscal year
20182020 compared to
$361.6$855.8 million
in fiscal year
2017.2019. The
$182.9 million increasedecrease in cash provided by operating activities is primarily
due to an increasedriven by lower operating activity and a favorable variance in
net income due to increased activity during the
fiscal year. In fiscal year 2016, net cash provided from operating activities was $754.5 million. The $392.9 million decrease in cashuse of working capital. Cash flows provided by operating activities
betweenin fiscal
years 2017 and 2016year 2018 was $557.9 million. The $297.9 million increase compared to fiscal year 2019 was primarily due to a
larger net loss reporteddecrease in
fiscal year 2017.working capital.
Capital Expenditures Our investing activities are primarily related to capital expenditures for our fleet. Our capital expenditures were $140.8 million, $458.4 million and $466.6 million in fiscal years 2020, 2019 and 2018, $397.6 millionrespectively. The year-over-year decrease in fiscal year 2017capital expenditures is driven by a decrease in super-spec upgrades and $257.2 million in fiscal year 2016.lower maintenance capital expenditure levels as a result of lower activity. Our fiscal year 20192021 capital spending is currently estimated to be between $650$85 and $105 million and $680 million.. This estimate includes normal capital maintenance requirements, capitalinformation technology spending related to reactivating idle rigs, tubulars and othera limited number of upgrades primarily related to improvingaugmenting the capabilities of our existing rig fleet. Acquisition of BusinessDuring fiscal years 2018 and 2017, weWe paid $47.9$16.2 million and $70.4$47.9 million, respectively, net of cash acquired, during the 2019 and 2018 fiscal year, respectively, for the acquisition of drilling technology companies.
Sale of AssetsOur proceeds from asset sales totaled $78.4 million, $50.8 million and $44.4 million in fiscal year 2020, 2019 and 2018, $23.4 million inrespectively. The current year increase is primarily driven by the sale of a portion of our real estate investment portfolio. 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 Subsidiary In December 2019, we closed on the sale of a wholly-owned subsidiary of HPIDC, TerraVici. As a result of the sale, 100% of TerraVici's outstanding capital stock was transferred to the purchaser in exchange for approximately $15.1 million, resulting in fiscal year 2016. Income from asset salesa total gain on the sale of TerraVici of approximately $15.0 million.
Marketable SecuritiesIn September 2019, we sold our remaining 1.6 million shares 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 salesValaris, previously known as Ensco Rowan plc, for total proceeds of old or damaged rig equipment and drill pipe used in the ordinary courseapproximately $12.0 million. As of business included in operating activity within the statement of cash flow.Stock Portfolio HeldWe manage a portfolio ofSeptember 30, 2020, our marketable securities consistingconsist primarily of common shares of Ensco plc (“Ensco”) andin Schlumberger, Ltd. that, at the close of fiscal year 2018,2020, had a fair value of $82.5$7.3 million. The value of the portfolio isour securities are subject to fluctuation in the market and may vary considerably over time. The portfolio isOur marketable securities are recorded at fair value on our balance sheet. During the fourth quarter of fiscal year 2016, we determined that the decline
Our equity investment in
fair value below our cost basis in Atwood Oceanics, Inc. (“Atwood”) was other than temporary. As a result, we recorded a non‑cash charge totaling $26.0 million.In May 2017, Ensco announced that it entered into a definitive merger agreement under which Ensco would acquire Atwood in an all-stock transaction. The transaction closed on October 6, 2017. Under the terms of the merger agreement, we received 1.60 shares of Ensco for each share of our Atwood common stock. The securities in our portfolio are subject to a wide variety of market‑related risks that could substantially reduce or increase the fair value of the holdings. In general, the portfolio is recorded at fair value on the balance sheet with changes in unrealized after‑tax value reflected in the equity section of the balance sheet.
Our stock portfolioSchlumberger Ltd. held as of September 30, 20182020 is presented below:
| | | | | | | | |
| | 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 |
|
| | | | | | | | |
| (in thousands, except for share amounts) | Number of Shares | | Cost Basis | | Market Value |
| Schlumberger, Ltd. | 467,500 |
| | 3,713 |
| | 7,274 |
|
Financing Activities
The increase
Repurchase of $8.4 million in net cash used by financing activities inShares During fiscal year 2018 from2020, we repurchased 1.5 million shares for $28.5 million compared to one million shares for $42.8 million during 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 2016.2019.
DividendsWe paid dividends of $2.82, $2.80,$2.38, $2.84, and $2.78$2.82 per share during fiscal years 2018, 20172020, 2019 and 2016,2018, respectively. Total dividends paid were $308.4$260.3 million, $305.5$313.4 million and $300.2$308.4 million in fiscal years 2020, 2019 and 2018, 2017 and 2016, respectively. Adjusting for stock splits accordingly,On June 3, 2020, we have increased the effective annualreduced our quarterly cash dividend to $0.25 per share every fiscal yearand on September 9, 2020, declared a cash dividend in that amount for the past 46 years.shareholders of record on November 13, 2020, payable on December 1, 2020. 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. 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“2018 Credit Facility”) with a maturity date of Julythat is set to mature on November 13, 2021.2024. The 20162018 Credit Facility hadhas $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 the Base Rate. 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, 2018,2020, 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 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. At September 30, 2020, we were in compliance with all debt covenants, and we anticipate that we will continue to be in compliance during the next quarter of fiscal year 2021. As of September 30, 2018,2020, 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 three2020, we had two 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,and $2.1 million, respectively.
As of September 30, 2020, 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, $4.3 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, 2020. Subsequent to September 30, 2020, $2.6 million in financial guarantees have expired.
The applicable agreements for all unsecured debt contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30,
Senior Notes
Exchange Offer, Consent Solicitation and Redemption
On December 20, 2018, we weresettled an offer to exchange (the “Exchange Offer”) any and all outstanding 4.65 percent unsecured senior notes due 2025 of HPIDC (the "HPIDC 2025 Notes") for (i) up to $500.0 million aggregate principal amount of new 4.65 percent unsecured senior notes due 2025 of the Company (the “Company 2025 Notes”), with registration rights, and (ii) cash, pursuant to which we issued approximately $487.1 million in complianceaggregate principal amount of Company 2025 Notes. Interest on the Company 2025 Notes is payable semi-annually on March 15 and September 15 of each year, commencing March 15, 2019. The debt issuance costs are being amortized straight-line over the stated life of the obligation, which approximates the effective interest method.
Following the consummation of the Exchange Offer, HPIDC had outstanding approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes. On December 20, 2018, HPIDC, the Company and Wells Fargo Bank, National Association, as trustee, entered into a supplemental indenture to the indenture governing the HPIDC 2025 Notes to adopt certain proposed amendments pursuant to a consent solicitation conducted concurrently with all debt covenants,the Exchange Offer.
On September 27, 2019, we redeemed the remaining approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes for approximately $14.6 million, including accrued interest and
we anticipate that we will continue to be in compliance fora prepayment premium. Simultaneously with the
next fiscal year.Repurchaseredemption of the HPIDC 2025 Notes, HPIDC was released as a guarantor under the Company 2025 Notes and Retirementthe 2018 Credit Facility. As a result of such release, H&P is the only obligor under the Company 2025 Notes and the 2018 Credit Facility.
Repurchase of Common Shares
We did not have any active stock repurchase program in fiscal years 2018, 2017, or 2016.
We have an evergreen authorization
tofrom the Board for the purchase
of up to four million
common shares
perin any calendar year. During the fiscal
year.year ended September 30, 2020, we purchased 1.5 million common shares at an aggregate cost of $28.5 million, which are held as treasury shares. We purchased 1.0 million common shares at an aggregate cost of $42.8 million, which are held as treasury shares, during the fiscal year ended September 30, 2019. We had no purchases of common shares during the fiscal year ended September 30, 2018.
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
20192021 are expected to be funded through current cash and cash to be provided from operating activities. However, there can be no assurance that we will continue to generate cash flows at current levels.
On June 3, 2020, we reduced our quarterly cash dividend to $0.25 per share. If needed, we may decide to obtain additional funding from our $750.0 million 2018 Credit Facility. Our indebtedness under our unsecured senior notes totaled $487.1 million at September 30, 2020 and matures on March 19, 2025.
As of September 30, 2020, we had a $650.7 million deferred tax liability on our Consolidated Balance Sheets, primarily related to temporary differences between the financial and income tax basis of property, plant and equipment. Our increased levels of capital expenditures over the last several years have been subject to accelerated depreciation methods (including bonus depreciation) available under the Internal Revenue Code of 1986, as amended, enabling us to defer a portion of cash tax payments to future years. Future levels of capital expenditures and results of operations will determine the timing and amount of future cash tax payments. We expect to be able to meet any such obligations utilizing cash and investments on hand, as well as cash generated from ongoing operations.
The
long‑long‑term debt to total capitalization ratio was 10.112.8 percent at September 30, 20182020 compared to 10.610.8 percent at September 30, 2017.2019. For additional information regarding debt agreements, refer to Note 8—Debt to our Consolidated Financial Statements.
Off-balance Sheet Arrangements
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K. For information regarding our drilling contract backlog, see Item 1— “Business — Contract Backlog”Backlog”. Our contractual obligations as of September 30, 20182020 are summarized in the table below in thousands:below:
| | | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments due by year |
| (in thousands) | Total | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | Thereafter |
| Long-term debt | $ | 487,148 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 487,148 |
| | $ | — |
|
Interest (1) | 101,934 |
| | 22,652 |
| | 22,652 |
| | 22,652 |
| | 22,652 |
| | 11,326 |
| | — |
|
Operating leases (2) | 38,166 |
| | 11,680 |
| | 8,133 |
| | 7,466 |
| | 7,018 |
| | 3,231 |
| | 638 |
|
Purchase obligations (3) | 2,692 |
| | 2,692 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total contractual obligations | $ | 629,940 |
| | $ | 37,024 |
| | $ | 30,785 |
| | $ | 30,118 |
| | $ | 29,670 |
| | $ | 501,705 |
| | $ | 638 |
|
| |
| (1) | | Interest on fixed‑fixed‑rate debt was estimated based on principal maturities. See Note 7--Debt8—Debt to our Consolidated Financial Statements. |
| |
| (2) | See Note 6—Leases to our Consolidated Financial Statements. |
| |
| (3) | See Note 15—17—Commitments and Contingencies to our Consolidated Financial Statements. |
The above table doesnot include obligations for our pension plan or amounts recorded for uncertain tax positions.In fiscal years 20182020 and 2017,2019, we did not make any contributions to the pension plan. Contributions may be made in fiscal year 20192021 to fund unexpected distributions in lieu of liquidating pension assets. Future contributions beyond fiscal year 20192021 are difficult to estimate due to multiple variables involved. At September 30,
2018,2020, we had
$17.1$16.3 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in Note
8—9—Income Taxes to our Consolidated Financial Statements.
Critical Accounting Policies and Estimates
Accounting policies that we consider significant are summarized in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties to our Consolidated Financial Statements included in Part II, Item 8 – Financial— "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‑on‑going basis. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies and estimates used in our financial statements. Property, Plant and Equipment
Property, plant and equipment, including renewals and betterments, are capitalized at cost, while maintenance and repairs are expensed as incurred. The interest expense applicable to the construction of qualifying assets is capitalized as a component of the cost of such assets. We account for the depreciation of property, plant and equipment using the
straight‑straight‑line method over the estimated useful lives of the assets considering the estimated salvage value of the property, plant and equipment. Both the estimated useful lives and salvage values require the use of management estimates. Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation or result in abandonments. For the fiscal years presented in this report,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 the difference between the fair value of the asset and its carrying value.At September 30, 2018, we performed impairment testing on our International FlexRig4 asset group, which has an aggregate net book value of $63.0 million. We concluded that the net book value of the drilling rig’s asset group is recoverable through estimated undiscounted future cash flows with a surplus of approximately 23 percent. The most significant assumptions used in our undiscounted cash flow model include: timing on awards of future drilling contracts, oil prices, operating dayrates, operating costs, rig- reactivation costs, drilling rig utilization, revenue efficiency, estimated remaining economic useful life and net proceeds received upon future sale/disposition. The assumptions are consistent with the Company’s internal budgets and forecasts for future years. These significant assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. Although we believe the assumptions used in our analysis are reasonable and appropriate and the asset group weighted average of expected future undiscounted net cash flows exceeds the net book value of the asset group as of the fiscal year 2018 year-end impairment evaluation, different assumptions and estimates could materially impact the analysis and our resulting conclusion.
At September 30, 2018, we engaged a third party independent accounting firm who performed a market valuation, utilizing the market approach, on two of our domestic and international conventional rigs’ asset groups, which have an aggregate net book values of $9.0 million and $15.2 million, respectively. We concluded that the fair values of these two asset groups exceed the net book values by approximately 64 percent and 141 percent, respectively and as such, no impairment was recorded. The significant assumptions in the valuation exercise are classified as Level 2 and Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures.
During fiscal years 2018 and 2016, we recognized $23.1 million and $6.3 million, respectively of asset impairment charges.
Self‑
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 finances 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 losses on an annual basis.
We insure
working land rigs and related equipment at values that approximate the current replacement costs on the inception date of the policies. However, we self-insure large deductibles under these policies. We also carry insurance with varying deductibles and coverage limits with respect to
stacked rigs, offshore platform rigs, and “named wind storm” risk in the Gulf of Mexico. We
self‑self‑insure a number of other risks, including loss of earnings and business interruption, and most cyber risks.Revenue Recognition
Contract drilling
Drilling services and solutions revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized
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.
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.
ITEMItem 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, 2018,2020, a hypothetical decrease in value of 10 percent would result in an insignificant decrease in value of our monetary assets and liabilities denominated in Argentine pesos by approximately $4,595.$2.2 million.
Argentina’s economy is currently considered highly inflationary, which is defined as cumulative inflation rates exceeding 100 percent in the most recent
three‑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.
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, 2018,2020, and our
outstanding debt consisted of $500$487.1 million (face amount) in a senior unsecured note,notes, which hashave a fixed rate of 4.65 percent. At September 30, 2018, the average interest rate risk on our fixed-rate debt of $500 million was estimated to be 4.65 percent after 2023. Comparatively, we estimated our interest rate risk at September 30, 2017 to be 4.65 percent after 2022. The fair value of the fixed-rate debt was estimated to be $509.3$534.5 million and $529.0$526.4 million for fiscal years 20182020 and 2017,2019, respectively.
On September 30, 2018,2020, we had a portfolio ofmarketable equity securities with a total fair value of $82.5$7.3 million. The total fair value of the portfolio ofour marketable securities was $70.2$16.3 million at September 30, 2017.2019. A hypothetical 10 percent decrease in the market pricesprice for allour marketable equity securities in our portfolio as of September 30, 20182020 would decrease the fair value of our available‑for‑sale securities by $8.3$0.7 million. We make no specific plans to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market‑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, 2018,12, 2020, the total fair value of our
marketable securities
decreasedincreased to approximately
$68.5$8.1 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.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
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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; |
| |
| (ii) | | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and the Board of Directors; and |
| |
| (iii) | | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018.2020. 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, 2018.2020.
Ernst & Young LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018,2020, as stated in their report which appears herein.
| | |
| | |
| | |
| Helmerich & Payne, Inc. | | |
| | |
by | | |
| | |
/s/ John W. Lindsay | | /s/ Mark W. Smith |
John W. Lindsay Director, President and Chief Executive Officer | | Mark W. Smith |
Director, President and
| | Senior Vice President and |
Chief Executive Officer
| | Chief Financial Officer |
| | |
November 16, 2018 20, 2020 | | November 16, 2018 20, 2020 |
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,
20182020 and
2017, and2019, the related consolidated statements of operations, comprehensive income (loss), shareholders' equity and cash flows for each of the three years in the period ended September 30,
2018,2020, and the related notes (collectively referred to as the “consolidated financial statements”).
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2018,2020, in conformity with U.S. generally accepted accounting principles.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of September 30,
2018,2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November
16, 2018,20, 2020 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.
| |
| | |
| | Self-Insurance Accruals |
Description of the Matter | | The Company's self-insurance liability for workers’ compensation and other casualty claims was $73.8 million at September 30, 2020. As described in Note 2 to the consolidated financial statements, this liability is based on a third-party actuarial analysis, which includes an estimate for incurred but not reported claims. The actuarial analysis considers a variety of factors, including third-party adjusters’ estimates, historic experience, and statistical methods commonly used within the insurance industry. Auditing the Company's reserve for self-insured risks for worker’s compensation and other casualty claims is complex and required us to use our actuarial specialists due to the significant measurement uncertainty associated with the estimate, management’s application of significant judgment, and the use of various actuarial methods. |
|
| | |
How We Addressed the Matter in Our Audit | | We evaluated the design and tested the operating effectiveness of the Company’s controls over the workers’ compensation and other casualty claims accrual process. For example, we tested controls over management’s determination of the appropriateness of the significant assumptions used in the calculation and the completeness and accuracy of the data underlying the reserve. To evaluate the self-insurance liability for worker’s compensation and other casualty claims, we performed audit procedures that included, among others, testing the completeness and accuracy of the underlying claims data provided to management’s actuary and obtaining legal confirmation letters to evaluate the reserves recorded on significant litigated matters. Additionally, we involved our actuarial specialists to assist in our evaluation of the methodologies applied by management’s actuary in establishing the actuarially determined reserve. We compared the Company’s assumptions to ranges of assumptions independently developed by our actuarial specialists. |
| | Impairment of Long-Lived Assets |
Description of the Matter | | As more fully described in Note 5 to the consolidated financial statements, the Company recognized a $441.4 million impairment charge in 2020 due to projected low utilization of the domestic non-super spec and all international asset groups. Auditing the Company's impairment analysis involved a high degree of subjectivity as the determination of undiscounted cash flows was based on assumptions about future market and economic conditions. Significant assumptions used in the Company’s undiscounted cash flow estimate included drilling rig utilization and net proceeds received upon future sale/disposition. |
How We Addressed the Matter in Our Audit | | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's process to estimate the undiscounted cash flows of the asset groups that were tested for recoverability. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions underlying the undiscounted cash flows. Our testing of the Company’s undiscounted cash flows included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. For example, we compared the projected drilling rig utilization assumption to current and forecasted industry and market information and any ongoing bid and contracting activity and compared the estimated net proceeds received upon future sale/disposition to industry ranges, market quotes and the Company’s historical experience. We also compared the Company’s historical experience and market activity to peer averages. Furthermore, we searched for and evaluated information that corroborates or contradicts the Company’s assumptions, performed retrospective reviews of projected cash flows to historical actuals, and performed a sensitivity analysis to evaluate the change in the projected cash flows that would result from changes in the underlying assumptions. |
| | Valuation of Goodwill and Finite-lived Intangibles |
| Description of the Matter | | As more fully described in Note 7 to the consolidated financial statements, during 2020 the Company performed goodwill and finite-lived intangible impairment analyses, resulting in a $38.3 million goodwill impairment charge. Auditing the Company’s impairment analyses was complex and highly judgmental due to the significant estimation required to determine the estimated future cash flows. In particular, the fair value estimate was sensitive to significant assumptions, such as changes in the utilization, discount rate, and terminal value, which are affected by expectations about future market and economic conditions. |
| How We Addressed the Matter in Our Audit | | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s goodwill and finite-lived intangibles impairment review process, including controls over management’s review of the significant assumptions described above. For example, we evaluated controls over the Company’s forecasting process used to develop the estimated future cash flows. We also tested controls over management’s review of the data used in their valuation models and the significant assumptions such as the estimation of utilization, discount rate and terminal value. To test the estimated cash flows of the applicable reporting unit and finite-lived intangibles, we performed audit procedures that included, among others, assessing methodologies and testing the significant assumptions discussed above and the underlying data used by the Company in its analyses. We compared the projected cash flows to available industry and market forecast information. We involved our valuation specialists to assist in testing the discount rate. We assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the reporting unit and finite-lived intangibles that would result from changes in the assumptions. For finite-lived intangibles, we also assessed whether the assumptions used were consistent with those used in the goodwill impairment review process. |
|
| | |
| | |
| /s/Ernst & Young LLP | |
We have served as the Company’s auditor since 1994. | | |
Tulsa, Oklahoma | | |
November 16, 2018 20, 2020 | | |
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,
2018,2020, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Helmerich & Payne, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30,
2018,2020, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets
of the Company as of September 30,
20182020 and
2017, and2019, the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity and cash flows for each of the three years in the period ended September 30,
2018,2020, and the related notes and our report dated November
16, 201820, 2020 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.
| |
| | |
| | |
| /s/ Ernst & Young LLP | |
| | |
Tulsa, Oklahoma | | |
November 16, 2018 20, 2020 | | |
Consolidated Balance Sheets
| | | | | | |
| | 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 |
|
| | | | | | | |
| | September 30, |
| (in thousands except share data and per share amounts) | 2020 | | 2019 |
| Assets | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 487,884 |
| | $ | 347,943 |
|
| Short-term investments | 89,335 |
| | 52,960 |
|
| Accounts receivable, net of allowance of $1,820 and $9,927, respectively | 192,623 |
| | 495,602 |
|
| Inventories of materials and supplies, net | 104,180 |
| | 149,653 |
|
| Prepaid expenses and other | 89,305 |
| | 68,928 |
|
| Total current assets | 963,327 |
| | 1,115,086 |
|
| | | | |
| Investments | 31,585 |
| | 31,991 |
|
| Property, plant and equipment, net | 3,646,341 |
| | 4,502,084 |
|
| Other Noncurrent Assets: | | | |
| Goodwill | 45,653 |
| | 82,786 |
|
| Intangible assets, net | 81,027 |
| | 86,716 |
|
| Operating lease right-of-use asset | 44,583 |
| | — |
|
| Other assets | 17,105 |
| | 20,852 |
|
| Total other noncurrent assets | 188,368 |
| | 190,354 |
|
| | | | |
| Total assets | $ | 4,829,621 |
| | $ | 5,839,515 |
|
| | | | |
| Liabilities and Shareholders’ Equity | | | |
| Current Liabilities: | | | |
| Accounts payable | $ | 36,468 |
| | $ | 45,383 |
|
| Dividends payable | 27,226 |
| | 77,763 |
|
| Accrued liabilities | 155,442 |
| | 287,092 |
|
| Total current liabilities | 219,136 |
| | 410,238 |
|
| | | | |
| Noncurrent Liabilities: | | | |
| Long-term debt, net | 480,727 |
| | 479,356 |
|
| Deferred income taxes | 650,675 |
| | 806,611 |
|
| Other | 147,180 |
| | 115,746 |
|
| Noncurrent liabilities - discontinued operations | 13,389 |
| | 15,341 |
|
| Total noncurrent liabilities | 1,291,971 |
| | 1,417,054 |
|
| Commitments and Contingencies (Note 17) |
| |
|
| Shareholders' Equity: | | | |
| Common stock, $.10 par value, 160,000,000 shares authorized, 112,151,563 and 112,080,262 shares issued as of September 30, 2020 and 2019, respectively, and 107,488,242 and 108,437,904 shares outstanding as of September 30, 2020 and 2019, respectively | 11,215 |
| | 11,208 |
|
| Preferred stock, no par value, 1,000,000 shares authorized, no shares issued | 0 |
| | 0 |
|
| Additional paid-in capital | 521,628 |
| | 510,305 |
|
| Retained earnings | 3,010,012 |
| | 3,714,307 |
|
| Accumulated other comprehensive loss | (26,188 | ) | | (28,635 | ) |
| Treasury stock, at cost, 4,663,321 shares and 3,642,358 shares as of September 30, 2020 and 2019, respectively | (198,153 | ) | | (194,962 | ) |
| Total shareholders’ equity | 3,318,514 |
| | 4,012,223 |
|
| Total liabilities and shareholders' equity | $ | 4,829,621 |
| | $ | 5,839,515 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Operations
| | | | | | | | | |
| | 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 |
|
| | | | | | | | | | | |
| | Year Ended September 30, |
| (in thousands, except per share amounts) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | |
| Drilling services | $ | 1,761,714 |
| | $ | 2,785,557 |
| | $ | 2,474,458 |
|
| Other | 12,213 |
| | 12,933 |
| | 12,810 |
|
| | 1,773,927 |
| | 2,798,490 |
| | 2,487,268 |
|
| Operating costs and expenses | | | | | |
| Drilling services operating expenses, excluding depreciation and amortization | 1,184,788 |
| | 1,803,204 |
| | 1,647,557 |
|
| Other operating expenses | 5,777 |
| | 5,382 |
| | 5,053 |
|
| Depreciation and amortization | 481,885 |
| | 562,803 |
| | 583,802 |
|
| Research and development | 21,645 |
| | 27,467 |
| | 18,167 |
|
| Selling, general and administrative | 167,513 |
| | 194,416 |
| | 199,257 |
|
| Asset impairment charge | 563,234 |
| | 224,327 |
| | 23,128 |
|
| Restructuring charges | 16,047 |
| | 0 |
| | 0 |
|
| Gain on sale of assets | (46,775 | ) | | (39,691 | ) | | (22,660 | ) |
| | 2,394,114 |
| | 2,777,908 |
| | 2,454,304 |
|
| Operating income (loss) from continuing operations | (620,187 | ) | | 20,582 |
| | 32,964 |
|
| Other income (expense) | | | | | |
| Interest and dividend income | 7,304 |
| | 9,468 |
| | 8,017 |
|
| Interest expense | (24,474 | ) | | (25,188 | ) | | (24,265 | ) |
| Gain (loss) on investment securities | (8,720 | ) | | (54,488 | ) | | 1 |
|
| Gain on sale of subsidiary | 14,963 |
| | 0 |
| | 0 |
|
| Other | (5,384 | ) | | (1,596 | ) | | (876 | ) |
| | (16,311 | ) | | (71,804 | ) | | (17,123 | ) |
| Income (loss) from continuing operations before income taxes | (636,498 | ) | | (51,222 | ) | | 15,841 |
|
| Income tax benefit | (140,106 | ) | | (18,712 | ) | | (477,169 | ) |
| Income (loss) from continuing operations | (496,392 | ) | | (32,510 | ) | | 493,010 |
|
| Income from discontinued operations before income taxes | 30,580 |
| | 32,848 |
| | 23,389 |
|
| Income tax provision | 28,685 |
| | 33,994 |
| | 33,727 |
|
| Income (loss) from discontinued operations | 1,895 |
| | (1,146 | ) | | (10,338 | ) |
| Net income (loss) | $ | (494,497 | ) | | $ | (33,656 | ) | | $ | 482,672 |
|
| Basic earnings (loss) per common share: | | | | | |
| Income (loss) from continuing operations | $ | (4.62 | ) | | $ | (0.33 | ) | | $ | 4.49 |
|
| Income (loss) from discontinued operations | $ | 0.02 |
| | (0.01 | ) | | (0.10 | ) |
| Net income (loss) | $ | (4.60 | ) | | $ | (0.34 | ) | | $ | 4.39 |
|
| Diluted earnings (loss) per common share: |
| |
| | |
| Income (loss) from continuing operations | $ | (4.62 | ) | | $ | (0.33 | ) | | $ | 4.47 |
|
| Income (loss) from discontinued operations | $ | 0.02 |
| | (0.01 | ) | | (0.10 | ) |
| Net income (loss) | $ | (4.60 | ) | | $ | (0.34 | ) | | $ | 4.37 |
|
| Weighted average shares outstanding: |
| |
| | |
| Basic | 108,009 |
| | 109,216 |
| | 108,851 |
|
| Diluted | 108,009 |
| | 109,216 |
| | 109,387 |
|
The accompanying notes are an integral part of these consolidated financial statements.
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) |
|
| | | | | | | | | | | |
| | Year ended September 30, |
| (in thousands) | 2020 | | 2019 | | 2018 |
| Net income (loss) | $ | (494,497 | ) | | $ | (33,656 | ) | | $ | 482,672 |
|
| Other comprehensive income (loss), net of income taxes: | | | | | |
| Unrealized appreciation on securities, net of income taxes of $3.3 million at September 30, 2018 | 0 |
| | 0 |
| | 9,001 |
|
| Minimum pension liability adjustments, net of income taxes of $0.8 million at September 30, 2020, $(3.5) million at September 30, 2019 and $1.9 million at September 30, 2018 | 2,447 |
| | (11,875 | ) | | 5,249 |
|
| Other comprehensive income (loss) | 2,447 |
| | (11,875 | ) | | 14,250 |
|
| Comprehensive income (loss) | $ | (492,050 | ) | | $ | (45,531 | ) | | $ | 496,922 |
|
The accompanying notes are an integral part of these consolidated financial statements.
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.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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, 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 |
| | 0 |
| | (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 | — |
| | — |
| | 872 |
| | (555 | ) | | — |
| | — |
| | — |
| | 317 |
|
| Balance at September 30, 2018 | 112,009 |
| | 11,201 |
| | 500,393 |
| | 4,027,779 |
| | 16,550 |
| | 3,015 |
| | (173,188 | ) | | 4,382,735 |
|
| Comprehensive loss: | | | | | | | | | | | | | | | |
| Net loss | — |
| | — |
| | — |
| | (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 (Note 10) | — |
| | — |
| | — |
| | 29,071 |
| | (29,071 | ) | | — |
| | — |
| | 0 |
|
| Reclassification of stranded tax effect for adoption of ASU No. 2018-02 | — |
| | — |
| | — |
| | 4,239 |
| | (4,239 | ) | | — |
| | — |
| | 0 |
|
| 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 |
|
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.
Consolidated Statements of Cash Flows
|
| | | | | | | | | | | |
| | Year Ended September 30, |
| (in thousands) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | (494,497 | ) | | $ | (33,656 | ) | | $ | 482,672 |
|
| Adjustment for (income) loss from discontinued operations | (1,895 | ) | | 1,146 |
| | 10,338 |
|
| Income (loss) from continuing operations | (496,392 | ) | | (32,510 | ) | | 493,010 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 481,885 |
| | 562,803 |
| | 583,802 |
|
| Asset impairment charges | 563,234 |
| | 224,327 |
| | 23,128 |
|
| Amortization of debt discount and debt issuance costs | 1,817 |
| | 1,732 |
| | 1,067 |
|
| Provision for bad debt | 2,203 |
| | 2,321 |
| | 2,193 |
|
| Stock-based compensation | 36,329 |
| | 34,292 |
| | 31,687 |
|
| Loss (gain) on investment securities | 8,720 |
| | 54,488 |
| | (1 | ) |
| Gain on sale of assets | (46,775 | ) | | (39,691 | ) | | (22,660 | ) |
| Gain on sale of subsidiary | (14,963 | ) | | 0 |
| | 0 |
|
| Deferred income tax benefit | (157,555 | ) | | (44,554 | ) | | (486,758 | ) |
| Other | (200 | ) | | (3,295 | ) | | 7,623 |
|
| Change in assets and liabilities: | | | | | |
| Accounts receivable | 300,807 |
| | 70,323 |
| | (85,202 | ) |
| Inventories of materials and supplies | 7,197 |
| | 1,821 |
| | (22,427 | ) |
| Prepaid expenses and other | (5,506 | ) | | (176 | ) | | (3,827 | ) |
| Other noncurrent assets | 2,820 |
| | (10,430 | ) | | 5,568 |
|
| Accounts payable | (9,414 | ) | | (9,147 | ) | | (4,461 | ) |
| Accrued liabilities | (138,414 | ) | | 40,887 |
| | 43,798 |
|
| Deferred income tax liability | 908 |
| | 371 |
| | 2,268 |
|
| Other noncurrent liabilities | 2,227 |
| | 2,251 |
| | (10,787 | ) |
| Net cash provided by operating activities from continuing operations | 538,928 |
| | 855,813 |
| | 558,021 |
|
| Net cash used in operating activities from discontinued operations | (47 | ) | | (62 | ) | | (169 | ) |
| Net cash provided by operating activities | 538,881 |
| | 855,751 |
| | 557,852 |
|
| Cash flows from investing activities: | | | | | |
| Capital expenditures | (140,795 | ) | | (458,402 | ) | | (466,584 | ) |
| Purchase of short-term investments | (134,641 | ) | | (97,652 | ) | | (71,049 | ) |
| Payment for acquisition of business, net of cash acquired | 0 |
| | (16,163 | ) | | (47,886 | ) |
| Proceeds from sale of short-term investments | 94,646 |
| | 86,765 |
| | 68,776 |
|
| Proceeds from sale of subsidiary | 15,056 |
| | 0 |
| | 0 |
|
| Proceeds from sale of marketable securities | 0 |
| | 11,999 |
| | 0 |
|
| Proceeds from asset sales | 78,399 |
| | 50,817 |
| | 44,381 |
|
| Other | (550 | ) | | 0 |
| | 0 |
|
| Net cash used in investing activities | (87,885 | ) | | (422,636 | ) | | (472,362 | ) |
| Cash flows from financing activities: | | | | | |
| Dividends paid | (260,335 | ) | | (313,421 | ) | | (308,430 | ) |
| Debt issuance costs | 0 |
| | (3,912 | ) | | 0 |
|
| Proceeds from stock option exercises | 4,100 |
| | 3,053 |
| | 6,355 |
|
| Payments for employee taxes on net settlement of equity awards | (3,784 | ) | | (6,418 | ) | | (7,114 | ) |
| Payment of contingent consideration from acquisition of business | (8,250 | ) | | 0 |
| | (10,625 | ) |
| Payments for early extinguishment of long-term debt | 0 |
| | (12,852 | ) | | 0 |
|
| Share repurchases | (28,505 | ) | | (42,779 | ) | | 0 |
|
| Other | (446 | ) | | 0 |
| | 0 |
|
| Net cash used in financing activities | (297,220 | ) | | (376,329 | ) | | (319,814 | ) |
| Net increase (decrease) in cash and cash equivalents and restricted cash | 153,776 |
| | 56,786 |
| | (234,324 | ) |
| Cash and cash equivalents and restricted cash, beginning of period | 382,971 |
| | 326,185 |
| | 560,509 |
|
| Cash and cash equivalents and restricted cash, end of period | $ | 536,747 |
| | $ | 382,971 |
| | $ | 326,185 |
|
| Supplemental disclosure of cash flow information: | | | | | |
| Cash paid during the period: | | | | | |
| Interest paid | $ | 22,928 |
| | $ | 26,739 |
| | $ | 20,502 |
|
| Income tax paid (refund), net | 46,700 |
| | 16,218 |
| | (38,400 | ) |
| Payments for operating leases | 18,646 |
| | — |
| | — |
|
| Changes in accounts payable and accrued liabilities related to purchases of property, plant and equipment | 3,123 |
| | 17,771 |
| | (2,245 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
HELMERICH & PAYNE, INC.
Notes to Consolidated Financial Statements
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
During the third quarter of fiscal year 2020, we restructured our operations (see Note 19—Restructuring Charges) to accommodate scale during an industry downturn and to re-organize our operations to align to new marketing and management strategies. This is consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. Operations previously reported within the former U.S. Land and H&P Technologies operating and reportable segments are now managed and presented within the North America Solutions reportable segment. As a result, beginning with the third quarter of fiscal year 2020, our drilling business is composed of threeservices operations were 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. All segment disclosures have been recast for these segment changes. 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 18—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, New Mexico, North Dakota, 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 limited commercial real estate properties. Our real estate investments, which are located exclusively within Tulsa, Oklahoma, include a shopping center multi-tenant industrial warehouse properties, and undeveloped real estate.
Dispositions
In December 2019, we closed on the sale of a wholly-owned subsidiary of Helmerich & Payne International Drilling Co. ("HPIDC"), TerraVici Drilling Solutions, Inc. ("TerraVici"). As a result of the sale, 100% of TerraVici's outstanding capital stock was transferred to the purchaser in exchange for approximately $15.1 million, resulting in a total gain on the sale of TerraVici of approximately $15.0 million. Prior to the sale, TerraVici was a component of the North America Solutions operating segment. This transaction does not represent a strategic shift in our operations and will not have a significant effect on our operations and financial results going forward.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, RISKS AND UNCERTAINTIES The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
We classified our former Venezuelan operation as a discontinued operation in the third quarter of fiscal year 2010, as more fully described in Note 4—Discontinued Operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates only to our continuing operations.
Principles of Consolidation
The consolidated financial statements include the accounts of Helmerich & Payne, Inc. and its domestic and foreign subsidiaries. Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary. Specifically, income and expenses of a subsidiary acquired or disposed of during the fiscal year are included in the consolidated statement of
profit or lossoperations and
other comprehensive income
(loss) from the date the Company gains control until the date when the Company ceases to control the subsidiary. All significant intercompany accounts and transactions have been eliminated in consolidation.
COVID-19 and OPEC+ Production Impacts
The outbreak of a novel strain of coronavirus (“COVID-19”) and its development into a pandemic have resulted in significant global economic disruption, including North America and many of the other geographic areas where we operate, or where our customers are located, or suppliers or vendors operate. Actions taken to prevent the spread of COVID-19 by governmental authorities around the world, including imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of such facilities and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions, have significantly reduced global economic activity, thereby resulting in lower demand for crude oil. In particular, the travel restrictions in certain countries where we operate, including the closure of their borders to travel into the country, have resulted in an inability to effectively staff or rotate personnel at, and thereby operate, certain of our rigs and could lead to an inability to fulfill our contractual obligations under contracts with customers. Governmental authorities have also implemented multi-step policies with the goal of re-opening various sectors of the economy. However, certain jurisdictions began re-opening only to return to restrictions in the face of increases in new COVID-19 cases, while other jurisdictions are continuing to re-open or have nearly completed the re-opening process despite increases in COVID-19 cases. The COVID-19 outbreak may significantly worsen during the upcoming months, which may cause governmental authorities to reconsider restrictions on business and social activities. In the event governmental authorities increase restrictions, the re-opening of the economy may be further curtailed. We have experienced, and expect to continue to experience, some resulting in disruptions to our business operations, as these restrictions have significantly impacted, and may continue to impact, many sectors of the economy. In addition, the perceived risk of infection and health risk associated with COVID-19, and the illness of many individuals across the globe, has and will continue to alter behaviors of consumers, and policies of companies around the world, resulting in many of the same effects intended by such governmental authorities to stop the spread of COVID-19, such as self-imposed or voluntary social distancing and quarantining and remote work policies. We are complying with local governmental jurisdiction policies and procedures where our operations reside. In some cases, policies and procedures are more stringent in our foreign operations than in our North America operations and this has resulted in a complete suspension, for a certain period of time, of all drilling operations in at least one foreign jurisdiction. In addition, a customer in one foreign jurisdiction has claimed force majeure resulting in zero chargeable revenues during the suspension period.
In early March 2020, the increase in crude oil supply resulting from production escalations from the Organization of the Petroleum Exporting Countries and other oil producing nations (“OPEC+”) combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Consequently, we have seen a significant decrease in customer 2020 capital budgets and a corresponding dramatic decline in the demand for land rigs. In April 2020, OPEC+ finalized an agreement to cut oil production by 9.7 million barrels per day during May and June 2020. On June 6, 2020, OPEC+ agreed to extend such production cuts until the end of July 2020. On July 15, 2020, OPEC+ agreed to ease the production cuts from 9.7 million barrels per day to 7.7 million barrels per day from August to December 2020. Despite the production cuts, prices in the oil and gas market have remained depressed, as the oversupply and lack of demand in the market persist. Oil and natural gas prices are expected to continue to be volatile as a result of the near-term production instability and the ongoing COVID-19 outbreak and as changes in oil and natural gas inventories, industry demand and global and national economic performance are reported.
These events have had, and could continue to have, an adverse impact on numerous aspects of our business, financial condition and results of operations. The ultimate extent of the impact of COVID-19 and prolonged excess oil supply on our business, financial condition and results of operations will depend largely on future developments, including the duration and spread of the COVID-19 outbreak within the United States and the parts of the world in which we operate and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the development and availability of effective treatments and vaccines, all of which are highly uncertain and cannot be predicted with certainty at this time.
From a financial perspective, we believe the Company is operationally and financially well positioned to continue operating even through a more protracted disruption caused by COVID-19, oil oversupply and low oil prices. At September 30, 2020, the Company had cash and cash equivalents and short-term investments of $577.2 million. The 2018 Credit Facility (as defined within Note 8—Debt) has $750.0 million in aggregate availability with a maximum of $75.0 million available for use as letters of credit. As of September 30, 2020, there were 0 borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. We currently do not anticipate the need to draw on the 2018 Credit Facility. Furthermore, the Company 2025 Notes (as defined within Note 8—Debt) do not mature until March 19, 2025.
Our functional currency, together with all our foreign subsidiaries, is the U.S. dollar. Monetary assets and liabilities denominated in currencies other than the U.S. dollar are translated at exchange rates in effect at the end of the period, and the resulting gains and losses are recorded on our statement of operations. Aggregate foreign currency losses of
$4.0$8.8 million,
$7.1$8.2 million and
$9.3$4.0 million in fiscal years
2018, 20172020, 2019 and
2016,2018, 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$48.9 million and
$39.1$35.0 million at September 30,
20182020 and
2017,2019, respectively. Of the total at September 30,
20182020 and
2017, $11.32019, $3.6 million and
$9.4$3.0 million, respectively, is related to the acquisition of drilling technology companies described in Note 3—Business Combinations, $2.0 million as of both
fiscal year ends is from the initial capitalization of the captive insurance company, and
$28.5$43.1 million and
$27.7$30.0 million, respectively, represents an additional amount management has elected to restrict for the purpose of potential insurance claims in our wholly-owned captive insurance company. The restricted amounts are primarily invested in short-term money market securities.
See Note 2 for changes to the presentation of restricted cash effective October 1, 2018.The restricted cash and cash equivalents are reflected in the Consolidated Balance Sheets as follows:
|
| | | | | | | | | | | |
| | September 30, |
| (in thousands) | 2020 | | 2019 | | 2018 |
| Cash | $ | 487,884 |
| | $ | 347,943 |
| | $ | 284,355 |
|
| Restricted Cash | | | | | |
| Prepaid expenses and other | 45,577 |
| | 31,291 |
| | 39,830 |
|
| Other assets | 3,286 |
| | 3,737 |
| | 2,000 |
|
| Total cash, cash equivalents, and restricted cash | $ | 536,747 |
| | $ | 382,971 |
| | $ | 326,185 |
|
Accounts Receivable
Accounts receivable represents valid claims against our customers for our services rendered, net of allowances for doubtful accounts. We perform credit evaluations of customers and do not typically require collateral in support for trade receivables. We provide an allowance for doubtful accounts, when necessary, to cover estimated credit losses. Outstanding customer receivables are reviewed regularly for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet as follows:date. Refer to Note 16—Supplemental Balance Sheet Information.
| | | | | | |
| | September 30, |
| | 2018 | | 2017 |
| | (in thousands) |
Prepaid expenses and other | | $ | 39,830 | | $ | 32,439 |
Other assets | | $ | 2,000 | | $ | 6,695 |
Inventories of Materials and Supplies
Inventories are primarily replacement parts and supplies held for consumption in our drilling operations. Inventories are valued at the lower of cost or net realizable value. Cost is determined on a weighted average basis and includes the cost of materials, shipping, duties
labor and
manufacturing overhead.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$36.5 million and $9.2$11.5 million for fiscal years 20182020 and 2017,2019, respectively.
We maintain investments in equity securities of certain publicly traded companies.
The cost ofWe recognize our marketable 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.
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 0 capitalized interest forduring fiscal years 2018, 20172020 and 2016 was2019 and $0.4 million $0.3 million and $2.8 million, respectively.of capitalized interest during fiscal year 2018.
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, mobilizationMobilization payments received, 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
2020, 2019 and 2018
2017 and 2016 were
$274.7$212.0 million,
$179.9$322.8 million and
$125.9$274.7 million, respectively. For contracts that are terminated by customers prior to the expirations of their fixed terms, contractual provisions customarily require early termination amounts to be paid to us. Revenues from early terminated contracts are recognized when all contractual requirements have been met. Early termination revenue for fiscal years
2018, 20172020, 2019 and
20162018 was approximately
$73.4 million, $11.3 million and $17.1 million,
$29.4 million and $219.0 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.
During the fiscal year ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including six industrial sites. See Note 5—Property, Plant and Equipment for additional details. Our rent revenues are as follows:
| | | | | | | | | | |
| | Year Ended September 30, | | | | | | | |
| | 2018 | | 2017 | | 2016 | Year Ended September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 | | 2018 |
Minimum rents | | $ | 9,950 | | $ | 9,735 | | $ | 9,196 | $ | 9,245 |
| | $ | 10,168 |
| | $ | 9,950 |
|
Overage and percentage rents | | $ | 1,040 | | $ | 936 | | $ | 1,211 | 656 |
| | 932 |
| | 1,040 |
|
At September 30, 2018,2020, minimum future rental income to be received on noncancelable operating leases was as follows:follows (in thousands):
| | | | | | | |
Fiscal Year | | Amount | Amount |
| | (in thousands) | |
2019 | | $ | 7,709 | |
2020 | | | 6,314 | |
2021 | | | 4,473 | $ | 5,512 |
|
2022 | | | 2,488 | 4,553 |
|
2023 | | | 1,725 | 3,564 |
|
| 2024 | | 2,975 |
|
| 2025 | | 2,350 |
|
Thereafter | | | 4,868 | 5,358 |
|
Total | | $ | 27,577 | $ | 24,312 |
|
Leasehold improvement allowances are capitalized and amortized over the lease term.
At September 30, 20182020 and 2017,2019, the cost and accumulated depreciation for real estate properties were as follows:
| | | | | | | |
| | September 30, | | | | | |
| | 2018 | | 2017 | September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 |
Real estate properties | | $ | 69,133 | | $ | 66,005 | $ | 43,389 |
| | $ | 72,507 |
|
Accumulated depreciation | | | (42,272) | | | (42,169) | (27,588 | ) | | (43,570 | ) |
| | $ | 26,861 | | $ | 23,836 | $ | 15,801 |
| | $ | 28,937 |
|
Current income tax expense is the amount of income taxes expected to be payable for the current fiscal year. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities.
We
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—9—Income Taxes. Amounts for uncertain tax positions are adjusted in periods when new information becomes available or when positions are effectively settled. We recognize accrued interest related to unrecognized tax benefits in interest expense and penalties in other expense in the Consolidated Statements of Operations.Earnings per Common Share
Basic earnings per share is computed utilizing the two-class method and is calculated based on the weighted-average number of common shares outstanding during the periods presented. Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options, 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.
The fair value of each option isgranted prior to fiscal year 2019 was estimated on the date of grant based on the Black-Scholes options-pricing model utilizing assumptions for a risk freerisk-free interest rate, volatility, dividend yield and
expected remaining term of the awards. The assumptions used in calculating the fair value of stock-based payment awards representrepresented management’s best estimates, but these estimates involve inherent uncertainties and the application of managementmanagement's judgment.
The grant date fair value of performance share units is determined through the use of the Monte Carlo simulation method. The Monte Carlo simulation method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined peer group of companies’ (the "Peer Group") stock, risk free rate of return, dividend yields and cross-correlations between the Company and our Peer Group.
Stock-based compensation is recognized on a straight-line basis over the requisite service periods of the stock awards, which is generally the vesting period. Compensation expense
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 12—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 expense is recognized(net of any incentives received from the lessor) were charged to the income statement on a straight-line basis over the lifeperiod of the lease. Leasehold improvementslease (“levelized lease cost”).
Beginning October 1, 2019, leases are capitalizedrecognized as a right-of-use asset and amortizeda corresponding liability within accrued liabilities and other non-current liabilities at the date at which the leased asset is available for use by the Company. Each lease payment is allocated between the liability and finance cost. The finance cost is recognized over the lease term. We doperiod to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis for finance type leases and as the difference between the levelized lease cost and the finance cost for operating leases.
Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:
Fixed payments (including in-substance fixed payments), less any lease incentives receivable
Variable lease payments that are based on an index or a rate
Amounts expected to be payable by the lessee under residual value guarantees
The exercise price of a purchase option if the lessee is reasonably certain to exercise that option, and
Payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option.
The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the lessee’s incremental borrowing rate is used, which is the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions.
Right-of-use assets are measured at cost and are comprised of the following:
The amount of the initial measurement of lease liability
Any lease payments made at or before the commencement date less any lease incentives received
Any initial direct costs, and
Asset retirement obligations related to that lease, as applicable.
Payments associated with short-term leases and leases of low-value assets are recognized on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less. Low-value assets are comprised of IT-equipment and office furniture.
In determining the lease term, management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not
haveexercise 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
capitalevent or a significant change in circumstances occurs and is within the control of the lessee. Refer to Note 6—Leases for additional information regarding our leases.
Recently Issued Accounting Updates
Changes to U.S. GAAP are established by the Financial Accounting Standards Board (“FASB”) in the form of Accounting
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
| | |
| Standard | Description | Date of
Adoption | Effect on the Financial Statements or Other Significant Matters |
Recently Adopted Accounting Pronouncements |
ASU No. 2016-09, Compensation – Stock Compensation2016-02, Leases (Topic 718): Improvements842) and related ASUs issued subsequent | ASU No. 2016-02 requires organizations that lease assets — referred to Employee Share-Based Payment Accounting | The standard requires that all excess tax benefitsas “lessees” — to recognize on the balance sheet the assets and deficiencies previously recorded as additional paid-in capital be prospectively recorded in income tax expense. The adoptionliabilities for the rights and obligations created by those leases with lease terms of this ASU could cause volatility in the effective tax rate on a quarter by quarter basis due primarilymore than 12 months. Lessor accounting remains substantially similar to fluctuations in the Company's stock price and the timingcurrent U.S. GAAP. In addition, disclosures of stock option exercises and vesting of restricted share grants. The standard requires excess tax benefitsleasing activities are to be presented asexpanded to include qualitative along with specific quantitative information. ASU No. 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-02 mandates a modified retrospective transition method of adoption with an 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 withholdingsoption to be presented as a financing activity on the statement of cash flows.
use certain practical expedients. | October 1, 2017 2019 | We adopted this ASU during the first quarter of fiscal year 2018. We elected2020, as required. Refer to present changesNote 6—Leases for additional information.
|
| ASU No. 2018-15, Intangibles - Goodwill and Other - Internal Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract | This ASU aims to reduce complexity in the statementaccounting for costs of cash flows onimplementing a retrospective basis as allowed bycloud computing service arrangement. ASU No. 2018-15 aligns the standardrequirements for capitalizing implementation costs incurred in ordera hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to maintain comparability between fiscal years. As such, prior period cash flows from operationsdevelop or obtain internal-use software (and hosting arrangements that include an internal-use software license). This update is effective for annual and interim periods beginning after December 15, 2019. The amendments in this update should be applied either retrospectively or prospectively to all implementation costs incurred after the fiscal years ended September 30, 2017 and 2016 have been adjusted to reflect an increasedate 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 adoption. Early adoption is permitted. | 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
2019 | 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
| Weearly adopted this ASU during the first quarter of fiscal year 2018. There was no2020 on a prospective basis. The prospective impact onis not material to our consolidated financial statements.
|
ASU No. 2017-04, Intangibles—Goodwillstatements 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.
disclosures.
|
Standards that are not yet adopted as of September 30, 2018 2020 |
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/(loss)income(loss), and (4) beneficial interests in securitized financial assets. This update is effective for annual and interim periods beginning after December 15, 2019. | October 1, 2020 | The guidance will be applied using the modified retrospective method with a cumulative effect adjustment to our beginning retained earnings balance. This update will apply primarily to receivables arising from revenue transactions. We have analyzed our historical credit losses and considered current economic conditions in developing our expected credit loss rate. We are currently finalizing our processes, internal controls and disclosures that are required upon adoption. We do not believe the implementation of this guidance will have a material impact on our consolidated financial statements and disclosures. |
|
| | | |
| Standard | Description | Date of Adoption | Effect on the Financial Statements or Other Significant Matters |
| ASU No. 2019-12, Financial Instruments – Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes | This ASU simplifies the accounting for income taxes by removing certain exceptions related to Topic 740. The ASU also improves consistent application of and simplifies GAAP for other areas of Topic 740 by clarifying and amending existing guidance. This update is effective for annual and interim periods beginning after December 15, 2020. Early adoption of the amendment is permitted, including adoption in any interim period for public entities for periods for which financial statements have not yet been issued. An entity that elects to early adopt the amendments in an interim period should reflect any adjustments as of the beginning of the annual period that includes that interim period. Additionally, an entity that elects early adoption must adopt all the amendments in the same period. Upon adoption, the amendments addressed in this ASU will be applied either prospectively, retrospectively or on a modified retrospective basis through a cumulative-effect adjustment to retained earnings. | October 1, 2021 | We are currently evaluating the impact that the new guidance may have on our consolidated financial statements and disclosures. |
ASU No. 2016-02, Leases2018-14, Compensation – Retirement Benefits – Defined Benefit Plans—General (Topic 842) 715-20): Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans | This ASU 2016-02 will require organizations that lease assets — referredamends ASC 715 to as “lessees” —add, remove, and clarify disclosure requirements related to recognize on the balance sheet the assetsdefined benefit, pension 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 2016-02other postretirement plans. This update is effective for fiscal years beginningannual and interim periods ending after December 15, 2018, including interim2020. Upon adoption, the guidance will be applied on a retrospective basis to all periods within those fiscal years. ASU 2016-02 mandates a modified retrospective transition method with an option to use certain practical expedients. presented. | October 1, 2019 2021 | We are currently evaluating the potential impact of adopting thisthe new guidance may have 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. |
Concentration of Credit Risk
Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of temporary cash investments, short-term investments and trade receivables. The industry concentration has the potential to impact our overall exposure to market and credit risks, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base.
We had revenues from individual customers, related towithin our U.S. LandNorth America Solutions segment, that constituted 10 percent or more of our total revenues as follows:
| | | | | | | | | | |
(In thousands) | 2018 | | 2017 | | 2016 | |
| | (in thousands) | | 2018 |
EOG Resources, Inc. | $ | 258,194 | | $ | 163,582 | | $ | 124,262 | | $ | 258,194 |
|
In addition, we have certainfiscal years 2020 and 2019, no individual customers that make up a significant portionconstituted 10 percent or more of our Accounts Receivable at September 30, 2018, as indicated in the table below:total revenues.
| | |
| 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 cash reserves plus an estimate of loss development and incurred but not reported claims. The estimate is based upon historical trends. Insurance recoveries related to such liability are recorded when considered probable.
We self-insure a significant portion of expected losses relating to workers’ compensation, general liability and automobile liability. Generally, deductibles range from $1 million to $5$10 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates are recorded for incurred outstanding liabilities for workers’ compensation, general liability claims and claims that are incurred but not reported. Estimates are based on adjusters’ estimates, 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.
On October 1, 2019, we elected to utilize the Captive to insure the deductibles for our workers’ compensation, general liability and automobile liability insurance programs. Casualty claims occurring prior to October 1, 2019 will remain recorded within each of the operating segments and future adjustments to these claims will continue to be reflected within the operating segments. Reserves for legacy claims occurring prior to October 1, 2019, will remain as liabilities in our operating segments until they have been resolved. Changes in those reserves will be reflected in segment earnings as they occur. We will continue to utilize the Captive to finance the risk of loss to equipment and rig property assets. The Company and the Captive maintain excess property and casualty reinsurance programs with third-party insurers in an effort to limit the financial impact of significant events covered under these programs. Our operating subsidiaries are paying premiums to the Captive, typically on a monthly basis, for the estimated losses based on an external actuarial analysis. These premiums are currently held in a restricted account, resulting in a transfer of risk from our operating subsidiaries to the Captive. The actuarial estimated underwriting expenses for the fiscal year ended September 30, 2020 were approximately $16.4 million and were recorded within drilling services operating expenses in our Consolidated Statement of Operations. Intercompany premium revenues and expenses during the fiscal year ended September 30, 2020 amounted to $36.9 million, which were eliminated upon consolidation. These intercompany insurance premiums are reflected as segment operating expenses within the North America Solutions, Offshore Gulf of Mexico, and International 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 Captive insurer issued a stop-loss program that will reimburse the Company's health plan for claims that exceed $50,000. This program will also be reviewed at the end of each policy year by an outside actuary. One hundred percent of the stop-loss premium is being set aside by the Captive as reserves. The stop-loss program does not have a material impact on a consolidated basis.
International Solutions Drilling
OperationsRisks
International LandSolutions drilling operations may significantly contribute to our revenues and net operating income. There can be no assurance that we will be able to successfully conduct such operations, and a failure to do so may have an adverse effect on our financial position, results of operations, and cash flows. Also, the success of our international 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.
Many of the countries in which we operate have implemented measures in response to the COVID-19 pandemic. These measures, including imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of such facilities and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions, have significantly reduced global economic activity, thereby, resulting in lower demand for crude oil. In particular, the travel restrictions in certain countries where we operate, including the closure of their borders to travel into the country, have resulted in an inability to effectively staff or rotate personnel at, and thereby operate, certain of our rigs and could lead to an inability to fulfill our contractual obligations under contracts with customers.
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
US dollars.U.S. dollars, including controls that were implemented in September 2019. In September 2020, Argentina implemented additional currency controls in an effort to preserve Argentina's U.S. dollar reserves. As a result of these currency controls, our ability to remit funds from our Argentine subsidiary to its U.S. parent has been limited. In the past, the Argentine government has also instituted price controls on crude oil, diesel and gasoline prices and instituted an exchange rate freeze in connection with those prices. These
price controls
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 during fiscal year 2020 and it remains uncertain for how long they will be in effect. Further, there are additional concerns regarding Argentina's debt burden, notwithstanding Argentina's recent restructuring deal with international bondholders in August 2020, as Argentina
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.
Although we attempt to minimize the potential impact of such risks by operating in more than one geographical area, during the fiscal year ended September 30, 2020, approximately 8.3 percent of our operating revenues were generated from international locations in our drilling services business compared to 7.6 percent during the fiscal year ended September 30, 2019. During the fiscal year ended September 30, 2020, approximately 61.6 percent of operating revenues from international locations were from operations in South America compared to 91.6 percent during the fiscal year ended September 30, 2019. Substantially all of the South American operating revenues were from Argentina and Colombia. The future occurrence of one or more international events arising from the types of risks described above could have a material adverse impact on our business, financial condition and results of operations.
NOTE 3 BUSINESS COMBINATIONS
Fiscal Year
20182019 Acquisitions
On December 8, 2017,August 21, 2019, we completed an acquisition (“MagVAR Acquisition”) of an unaffiliated company, Magnetic Variation Services, LLC (“MagVAR”DrillScan Energy SAS and its subsidiaries ("DrillScan®"), which is now a wholly-owned subsidiary of the Company. The operationsCompany, for MagVAR are included with our other non-reportable business segments. At the effective time of the MagVAR Acquisition, MagVAR shareholders received aggregate cashtotal consideration of $47.9approximately $32.7 million, netwhich includes $17.7 million of customary closing adjustments, and certain management members received restricted stock awards covering 213,904 shares of Helmerich & Payne, Inc. common stock.contingent consideration. 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 milliontotal assets acquired, and liabilities assumed, as of the cash considerationacquisition date, were $36.3 million and $3.6 million, respectively, including goodwill of $14.9 million. Of the total assets acquired, $19.1 million was placed in escrow,allocated to be released toidentifiable intangible assets. DrillScan® is a leading provider of proprietary drilling engineering software, well engineering services and training for the sellers twelve months after the acquisition closing date.oil and gas industry. The amount placed in escrow is classified as restricted cash and isoperations of DrillScan® are included in prepaid expenses and other in the Consolidated Balance Sheet at September 30, 2018. Transaction costs related to the MagVAR Acquisition incurred during the fiscal year ended September 30, 2018 were approximately $1.2 million and are recorded in the Consolidated Statements of Operations within general and administrative expense. We recorded revenue of $11.6 million and a net loss of $3.0 million related to MagVAR during the fiscal year ended September 30, 2018.Through comprehensive 3D geomagnetic reference modeling, MagVAR provides measurement while drilling (“MWD”) survey corrections by identifying and quantifying MWD tool measurement errors in real-time, greatly improving
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.
Solutions reportable segment. The MagVAR Acquisitionacquisition of DrillScan® was accounted for as a business combination in accordance with FASB ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. In accordance with GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. During the second quarter of fiscal year 2020, as a result of new information identified related to the acquisition of DrillScan®, the acquisition date fair value of the contingent consideration and goodwill increased by approximately $1.2 million. This acquisition's measurement period closed during the quarter ended June 30, 2020 and, as a result, the purchase price accounting was finalized.
On November 1, 2018, we completed an acquisition of an unaffiliated company, Angus Jamieson Consulting (“AJC”), which is now a wholly-owned subsidiary of the Company, for total consideration of approximately $3.4 million. AJC is a software-based training and consultancy company based in Inverness, Scotland and is widely recognized as an industry leader in wellbore positioning. The operations of AJC are included in the North America Solutions reportable segment. The acquisition of AJC has been accounted for as a business combination in accordance with FASB ASC 805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at their acquisition date fair values. The
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 excessallocation of the purchase price over the total net identifiable assets has been recorded as goodwill. Factors comprisingincluded goodwill include the synergies expected from the expanded service capabilities as well as the value of the assembled workforce. The goodwill is reported within our other non-reportable business segments and was allocated to our MagVAR reporting unit. The goodwill is not subject to amortization, but is evaluated at least annually for impairment in the fourth quarter of each fiscal year, or more frequently if impairment indicators are present. The intangible assets and goodwill are amortized straight-line over 15 years for income tax purposes.
The following unaudited pro forma combined financial information is provided for the fiscal year ended September 30, 2018 and 2017, as though the MagVAR Acquisition had been completed as of October 1, 2016. These pro forma combined results of operations have been prepared by adjusting our historical results to include the historical results of MagVAR and reflect pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including application of an appropriate income tax to MagVAR’s pre-tax loss. Additionally, pro forma earnings for the fiscal year ended September 30, 2018 were adjusted to exclude $0.5 million of after-tax transaction costs. The unaudited pro forma combined financial information is provided for illustrative purposes only and is not necessarily indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this pro forma financial information.
| | | | | | |
| | 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
$3.1 million. 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 million during the fiscal year ended September 30, 2018 and 2017, respectively, was recorded in expenses applicable to other revenues in the Consolidated Statement of Operations. The developed technology is an intangible asset that will be amortized on a straight-line basis over an estimated 15-year life. The developed technology intangible asset was valued using an income approach, considering the estimated discounted future cash flows expected to be realized over the life of the asset, which is considered a Level 3 measurement under the fair value hierarchy. Goodwill represents the residual of the purchase price paid and consists largely of the synergies and economies of scale expected from the drilling technology providing more efficient drilling and directional drilling services, the first mover advantage obtained through the acquisition and expected future developments resulting from the assembled workforce. The goodwill is reported within our other non-reportable business segments and was allocated to our MOTIVE reporting unit. The goodwill is not subject to amortization but will be evaluated at least annually for impairment in the fourth quarter of each fiscal year or more frequently if impairment indicators are present. The developed technology and goodwill are not deductible for income tax purposes. An associated deferred tax liability has been recorded in regards to the developed technology.
NOTE 4 DISCONTINUED OPERATIONS Current and noncurrent liabilities
from discontinued operations consist of municipal and income taxes payable and social obligations due within the country
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, 20182020 was primarily due to the remeasurement of uncertain tax liabilities as a result of the devaluation of the Venezuela Bolivar. Early in 2018, the Venezuelan government announced that it changed the existing dual-rate foreign currency exchange system by eliminating its heavily subsidized foreign exchange rate, which was 10 Bolivars per 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 five5 zeros from the old currency. The DICOM floating rate was approximately 436,677, 21,028, and 62 Bolivars per U.S.United States dollar at September 30, 2018.2020, 2019 and 2018, respectively. The DICOM floating rate might not reflect the barter market exchange rates.
NOTE 5 PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment as of September 30, 20182020 and 20172019 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) | | Estimated Useful Lives | | September 30, 2020 | | September 30, 2019 |
| Drilling services equipment | | 4 - 15 years | | $ | 7,313,234 |
| | 7,881,323 |
|
| Tubulars | | 4 years | | 615,281 |
| | 618,310 |
|
Real estate properties | | 10 - 45 years | | | 68,888 | | | 66,005 | 10 - 45 years | | 43,389 |
| | 72,507 |
|
Other | | 2 - 23 years | | | 471,310 | | | 450,031 | 2 - 23 years | | 464,704 |
| | 471,803 |
|
Construction in progress | | | | | 163,968 | | | 169,326 | |
Construction in progress (1) | | | 49,592 |
| | 117,761 |
|
| | | | | 9,146,247 | | | 8,882,934 | | 8,486,200 |
| | 9,161,704 |
|
Accumulated depreciation | | | | | (4,288,865) | | | (3,881,883) | | (4,839,859 | ) | | (4,659,620 | ) |
Property, plant and equipment, net | | | | $ | 4,857,382 | | $ | 5,001,051 | | $ | 3,646,341 |
| | $ | 4,502,084 |
|
| |
| (1) | Included in construction in progress are costs for projects in progress to upgrade or refurbish certain rigs in our existing fleet. Additionally, we include other capital maintenance purchase-orders that are open/in process. As these various projects are completed, the costs are then classified to their appropriate useful life category. |
Impairments
- Fiscal Year 2020
Consistent with our policy, we evaluate our drilling rigs and related equipment for impairment whenever events or changes in circumstances indicate the carrying value of these assets may exceed the estimated undiscounted future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessment on the future marketability of specific rigs’ asset group. 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,
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.
As of March 31, 2020, the Company also recorded an additional non-cash impairment charge related to in-progress drilling equipment and rotational inventory of $44.9 million and $38.6 million, respectively, which had aggregate book values of $68.4 million and $38.6 million, respectively, in the Consolidated Statement of Operations for the fiscal year ended September 30, 2020. Of the $83.5 million total impairment charge recorded for in-progress drilling equipment and rotational inventory, $75.8 million and $7.7 million was recorded in the North America Solutions and International Solutions segments, respectively.
Impairment - Fiscal Year 2019
During the third quarter of fiscal year 2019, the Company's management performed a detailed assessment, considering a number of approaches, to maximize the utilization and enhance the margins of the domestic and international FlexRig® 4 asset groups. In June 2019, this assessment concluded that marketing a smaller fleet of these two asset groups would provide the best economic outcome. As such, the decision was made to downsize the number of domestic and international FlexRig® 4 drilling rigs, to be marketed to our customers, from 71 rigs to 20 domestic rigs and from 10 rigs to 8 international rigs and utilize the major interchangeable components of the decommissioned drilling rigs within these asset groups as capital spares for all of our remaining rig fleet. This reduced the aggregate net book values of the FlexRig® 4 asset groups as of June 30, 2019 from $317.8 million to $107.5 million for domestic rigs and from $55.7 million to $47.8 million for international rigs. Following the downsizing process, we performed a detailed study to optimize the quantities of capital spares and drilling support equipment required to support the future operations of our rig fleet going forward. These decisions and analysis resulted in a write down of excess capital spares and drilling support equipment, which had an aggregate net book value of $235.3 million, to their estimated proceeds to ultimately be received on sale or disposal based on our historical experience with sales and disposals of similar assets, resulting in an impairment of $224.3 million, which was recorded in our Consolidated Statement of Operations for the fiscal year ended September 30, 2019. Of the $224.3 million total impairment charge recorded, $216.9 million and $7.4 million was recorded in our North America Solutions and International Solutions segments, respectively. The significant assumptions in the valuation are classified as Level 2 inputs by ASC Topic 820, Fair Value Measurement and Disclosures.
Due to the downsizing of our domestic and international FlexRig® 4 asset groups, at June 30, 2019, we performed impairment testing on these two asset groups. We concluded that the net book values of the asset groups are recoverable through estimated undiscounted cash flows with a surplus. The most significant assumptions used in our undiscounted cash flow model include timing on awards of future drilling contracts, operating dayrates, operating costs, rig reactivation costs, drilling rig utilization, estimated remaining useful life, and net proceeds received upon future sale/disposition. The assumptions are consistent with the Company's internal forecasts for future years. Although we believe the assumptions used in our analysis are reasonable and appropriate and the probability-weighted average of expected future undiscounted net cash flows exceed the net book value for each of the domestic and international FlexRig® 4 asset groups as of June 30, 2019, different assumptions and estimates could materially impact the analysis and our resulting conclusion.
Impairments - Fiscal Year 2018
During the fourth quarter of fiscal year 2018, after ceasing operations in Ecuador, we entered into a sales negotiation with respect to the six conventional rigs, within a separate international conventional rigs’ asset group, with net book values of $20.8 million, present in the country, pursuant to which the rigs, together with associated equipment and machinery, would bewere sold to a third party to be recycled. Certain components of these rigs, with an $8.5 million net book
value, that arewere not subject to the sale agreement will bewere transferred to the United States to be utilized on other FlexRigsFlexRig® drilling rigs with high activity and demand. The sales transaction was completed in November 2018. We recorded a non-cash impairment charge within our International LandSolutions segment of $9.2 million, ($7.0 million, net of tax, or $0.06 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018. As a result, the remaining rig within the same asset group, not to be disposed of, was written down resulting in an additional impairment charge of $1.4 million ($1.0 million, net of tax, or $0.01 per diluted share).million. The assets were recorded at fair value based on the sales agreement and as such are classified as Level 2 within the fair value hierarchy.
Furthermore, during the fourth quarter of fiscal year 2018, within our
U.S. LandNorth America Solutions segment, management committed to a plan to auction several previously decommissioned rigs during fiscal year 2019. As a result, we wrote them down to their estimated fair values. We recorded a non-cash impairment charge of $5.7 million,
($4.2 million, net of tax, or $0.04 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018. The assets were recorded at fair value based on the auction price and as such are classified as Level 2 of the fair value hierarchy.
During
Decommissioning
While the crude oil market imbalance is a global phenomenon, it has more acutely impacted the U.S. market as a result of storage limitations during the last two quarters of fiscal year 2016,2020. The abruptness of and the overall size of the decrease in demand for refined products, such as gasoline and diesel, has created an abundance of supply for such products which has caused the inventory levels of crude oil and its related refined products to become greatly elevated, reaching the high end of storage capabilities. This has greatly reduced the need, or in some cases, entirely eliminated the ability of refineries to use crude oil as a feedstock. As such, exploration and production ("E&P") companies, our customers, may have limited opportunities to offload their production and even then, the selling price could be at very low, uneconomical prices. Consequently, some E&P companies have chosen to shut-in and stop production, not complete additional wells drilled and/or not drill any more wells until the market imbalance corrects and it is economical to resume production and drilling wells.
During the fiscal year ended September 30, 2020, we recorded andecommissioned 2 rigs and 35 rigs from our legacy Domestic Conventional asset impairment charge in the U.S. Land segmentgroup and FlexRig® 3 asset group, respectively. The decommissioned rigs were impaired as 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. March 31, 2020.
Depreciation in the Consolidated Statements of Operations of
$583.8$474.7 million,
$585.5$556.9 million and
$598.6$578.4 million includes abandonments of
$27.7$4.0 million,
$42.6$11.4 million and
$39.3$27.7 million for fiscal years
2020, 2019 and 2018,
2017 and 2016, respectively.
During 2018, we have shortened the estimated useful lives of certain components of rigs planned for conversion, with a total net book value of $3.7 million, resulting in an increase in depreciation expense during 2018 of approximately $9.7 million. This will also increase the depreciation expense for the next three months by approximately $0.9 million and will decrease the depreciation expense for fiscal years 2019, 2020, 2021, 2022, and 2023 by $2.3 million, $2.3 million, $2.2 million, $1.3 million, and $0.4 million, respectively, and thereafter by $1.0 million.We had a gain on salessale of assets of $22.7$46.8 million, $39.7 million and $20.6$22.7 million in fiscal years 20182020, 2019 and 2017,2018, respectively. These gains were primarily related to customer reimbursement for the replacement value of drill pipe damaged or lost in drilling operations. Additionally, during the fiscal year ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including 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, which is included within Gain on Sale of Assets on our Consolidated Statement of Operations.
NOTE 6 LEASES
ASC 842 Adoption
On October 1, 2019, we adopted ASC 842, retrospectively through a cumulative-effect adjustment without restating comparative periods for the 2019 and 2018 fiscal years as permitted under the specific transitional provisions in ASC 842. The reclassifications and the adjustments arising from the new leasing rules are therefore recognized in the opening balance sheet on October 1, 2019.
Upon the adoption of ASC 842, we recognized lease liabilities in relation to leases that had previously been classified as operating leases under the principles of ASC 840. These liabilities were measured at the present value of the remaining lease payments, discounted using the lessee’s incremental borrowing rate as of October 1, 2019, as most of our contracts do not provide an implicit rate. The weighted average lessee’s incremental borrowing rate applied to the operating lease liabilities on October 1, 2019 was approximately 2.9%.
The change in accounting policy affected the following items in the balance sheet on October 1, 2019: |
| | | | | | | | | | | |
| (in thousands) | September 30, 2019 | | Adjustments | | October 1, 2019 |
| Other Noncurrent Assets: | | | | | |
| Operating lease right-of-use asset | $ | — |
| | $ | 56,071 |
| | $ | 56,071 |
|
| Current Liabilities: | | | | | |
| Accrued Liabilities | — |
| | 16,277 |
| | 16,277 |
|
| Noncurrent Liabilities: | | | | | |
| Other | — |
| | 39,794 |
| | 39,794 |
|
As of September 30, 2020, segment assets and liabilities have all increased from September 30, 2019 as a result of the change in accounting policy. All reportable segments were affected by the change in policy.
In applying ASC 842 for the first time, we have used the following practical expedients permitted by the topic:
The use of a single discount rate to a portfolio of leases with reasonably similar characteristics,
Not to reassess whether a contract is, or contains a lease at the date of initial application; instead, for contracts entered into before the transition date, we relied on our assessment in which we applied ASC 840 prior to the adoption date,
The option to not reassess initial direct cost for existing leases, and
The use of hindsight in determining the lease term where the contract contains options to extend or terminate the lease.
We have made the accounting policy election to not recognize a right-of-use asset and corresponding liability for leases with a term of 12 months or less and leases of low-value. Additionally, ASC 842 provides lessors with a practical expedient, by class of underlying asset, to not separate lease and non-lease components and account for the combined component under ASC 606 when the non-lease component is the predominant element of the combined component. The lessor practical expedient is limited to circumstances in which the lease, if accounted for separately, would be classified as an operating lease under ASC 842.
With respect to our drilling service contracts that commenced or were amended during the fiscal year ended September 30, 2020, we concluded that our drilling contracts contain a lease component and that the non-lease component is the predominant element of the combined component of such contracts. As such, we elected to apply the practical expedient to not separate the lease and non-lease components and account for the combined component under ASC 606. Therefore, we do not expect any change in our revenue recognition patterns or disclosures as a result of our adoption of ASC 842.
|
| | | | | | | |
| (in thousands) | October 1, 2019 | | September 30, 2020 |
Operating lease commitments, including probable extensions (1) | $ | 62,218 |
| | $ | 48,695 |
|
| | | | |
| Discounted using the lessee's incremental borrowing rate at the date of initial application | $ | 57,323 |
| | $ | 46,706 |
|
| (Less): short-term leases recognized on a straight-line basis as expense | (1,252 | ) | | (1,456 | ) |
| Lease liability recognized | $ | 56,071 |
| | $ | 45,250 |
|
| | | | |
| Of which: | | | |
| Current lease liabilities | $ | 16,277 |
| | $ | 11,364 |
|
| Non-current lease liabilities | 39,794 |
| | 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) | October 1, 2019 | | September 30, 2020 |
| Properties | $ | 52,188 |
| | $ | 42,448 |
|
| Equipment | 3,652 |
| | 1,394 |
|
| Other | 231 |
| | 741 |
|
| Total right-of-use assets | $ | 56,071 |
| | $ | 44,583 |
|
The right-of-use assets were measured at the amount equal to the lease liability, adjusted for the amount of any prepaid or accrued lease payments recognized on the balance sheet at September 30, 2019.
Lease Costs
The following table presents certain information related to the lease costs for our operating leases: |
| | | |
| (in thousands) | Year Ended
September 30, 2020 |
| Operating lease cost | $ | 16,953 |
|
| Short-term lease cost | 1,693 |
|
| Total lease cost | $ | 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, 2020. |
| | |
| September 30, 2020 |
| Weighted average remaining lease term | 4.9 |
|
| Weighted average discount rate | 2.7 | % |
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, 2020 (in thousands) are as follows: |
| | | |
| Fiscal Year | Amount |
| 2021 | $ | 11,680 |
|
| 2022 | 8,133 |
|
| 2023 | 7,466 |
|
| 2024 | 7,018 |
|
| 2025 | 3,231 |
|
| Thereafter | 638 |
|
Total (1) | $ | 38,166 |
|
| |
| (1) | Our future minimal rental payments exclude optional extensions that have not been exercised but are probable to be exercised in the future, those probable extensions are included in the operating lease liability balance. |
Total rent expense was $18.6 million, $15.5 million and $13.7 million for the fiscal years ended September 30, 2020, 2019 and 2018, respectively. The future minimum lease payments for our Tulsa corporate office and our Tulsa industrial facility represent a material portion of the amounts shown in the table above. The lease agreement for our Tulsa corporate office commenced on May 30, 2003 and has subsequently been amended, most recently on March 12, 2018. The agreement will expire on January 31, 2025; however, we have two five-year renewal options, which were not recognized as part of our right-of-use assets and lease liabilities. The lease agreement for our Tulsa industrial facility, where we perform maintenance and assembly of FlexRig® components commenced on December 21, 2018 and will expire on June 30, 2025; however, we have two two-year renewal options which were recognized as part of our right-of-use assets and lease liabilities.
NOTE 67 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 |
Table |
| | | |
| September 30, 2017 | $ | 51,705 |
|
| Additions | 17,791 |
|
| Impairment | (4,719 | ) |
| September 30, 2018 | 64,777 |
|
| Additions | 18,009 |
|
| September 30, 2019 | 82,786 |
|
| Additions | 1,200 |
|
| Impairment | (38,333 | ) |
| September 30, 2020 | $ | 45,653 |
|
During the second quarter of Contents
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.
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, 2020 | | September 30, 2019 |
(in thousands) | | Amount | | Amortization | | Net | | Amount | | Amortization | | Net | Weighted Average Estimated Useful Lives | | Gross Carrying Amount | | Accumulated Amortization | | Net | | Gross Carrying Amount | | Accumulated Amortization | | Net |
Finite-lived intangible asset: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Developed technology | | $ | 70,000 | | $ | 5,589 | | $ | 64,411 | | $ | 51,000 | | $ | 1,134 | | $ | 49,866 | 15 years | | $ | 89,096 |
| | $ | 16,222 |
| | $ | 72,874 |
| | $ | 89,096 |
| | $ | 10,256 |
| | $ | 78,840 |
|
| Intellectual property | | 13 years | | 1,500 |
| | 103 |
| | 1,397 |
| | 0 |
| | 0 |
| | 0 |
|
Trade name | | | 5,700 | | | 237 | | | 5,463 | | | — | | | — | | | — | 20 years | | 5,865 |
| | 842 |
| | 5,023 |
| | 5,865 |
| | 522 |
| | 5,343 |
|
Customer relationships | | | 4,000 | | | 667 | | | 3,333 | | | — | | | — | | | — | 5 years | | 4,000 |
| | 2,267 |
| | 1,733 |
| | 4,000 |
| | 1,467 |
| | 2,533 |
|
| | $ | 79,700 | | $ | 6,493 | | $ | 73,207 | | $ | 51,000 | | $ | 1,134 | | $ | 49,866 | | $ | 100,461 |
| | $ | 19,434 |
| | $ | 81,027 |
| | $ | 98,961 |
| | $ | 12,245 |
| | $ | 86,716 |
|
| | | | | | | | | | | | | | | | | | | |
Indefinite-lived intangible asset: | | | | | | | | | | | | | | | | | | | |
Trademark | | $ | — | | $ | — | | $ | — | | $ | 919 | | $ | — | | $ | 919 | |
| | | | | | | | | | | | | | | | | | | |
Amortization expense in the Consolidated Statements of Operations was $5.4$7.2 million, $5.8 million and $1.1$5.4 million for fiscal years 20182020, 2019 and 2017,2018, respectively, and is estimated to be $5.8$7.2 million for each of the next fourtwo succeeding fiscal years, and approximately $5.1$6.5 million for fiscal year 2023.Impairments
and approximately $6.4 million
for fiscal years 2024 and 2025. Impairment - Fiscal Year 2020
Consistent with our policy, we test goodwill annually for impairment in the fourth quarter of our fiscal year, or more frequently if there are indicators that goodwill might be impaired.
Due to the market conditions described in Note 5—Property, Plant and Equipment, during the second quarter of fiscal year 2020, we concluded that goodwill and intangible assets might be impaired and tested the H&P Technologies reporting unit, where the goodwill balance is allocated and the intangible assets are recorded, for recoverability. This resulted in a goodwill only non-cash impairment charge of $38.3 million recorded in the Consolidated Statement of Operations during the fiscal year ended September 30, 2020.
The recoverable amount of the H&P Technologies reporting unit was determined based on a fair value calculation which uses cash flow projections based on the Company's financial projections presented to the Board covering a five-year period, and a discount rate of 14 percent. Cash flows beyond that five-year period were extrapolated using the fifth-year data with no implied growth factor. The reporting unit level is defined as an operating segment or one level below an operating segment.
The recoverable amount of the intangible assets tested for impairment within the H&P Technologies reporting unit is determined based on undiscounted cash flow projections using the Company's financial projections presented to the Board covering a five-year period and extrapolated for the remaining weighted average useful lives of the intangible assets.
The most significant assumptions used in our cash flow model include timing of awarded future contracts, commercial pricing terms, utilization, discount rate, and the terminal value. These assumptions are classified as Level 3 inputs by ASC Topic 820 Fair Value Measurement and Disclosures as they are based upon unobservable inputs and primarily rely on management assumptions and forecasts. Although we believe the assumptions used in our analysis and the probability-weighted average of expected future cash flows are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and our resulting conclusion.
Impairment - Fiscal Year 2018
During the fourth quarter of fiscal year 2018, and as part of our annual goodwill impairment test, we performed a detailed assessment of the TerraVici reporting unit, where $4.7 million of goodwill was allocated. We determined that the estimated fair value of this reporting unit was less than its carrying amount and we recorded goodwill impairment losses of $4.7 million ($3.5 million, net of tax, or $0.03 per diluted share).$4.7 million. In addition, we recorded an intangible assets impairment loss of $0.9 million ($0.7 million net of tax, or $0.01 per diluted share).million. These impairment losses are included in Asset Impairment Charge on the Consolidated Statements of Operations for the fiscal year ended September 30, 2018.Our goodwill impairment analysis performed on our remaining technology reporting units in the fourth quarter of fiscal yearsyear 2018 and 2017 did not result in an impairment charges.
charge.
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 | | | September 30, 2020 | | September 30, 2019 |
| | Face | | Debt Issuance | | Book | | Face | | Debt Issuance | | Book | |
| | Amount | | Cost | | Value | | Amount | | Cost | | Value | |
| | (in thousands) | |
Unsecured senior notes issued March 19, 2015: | | | | | | | | | | | | | | | | | | | |
| (in thousands) | | Face Amount | | Unamortized Discount and Debt Issuance Cost | | Book Value | | Face Amount | | Unamortized Discount and Debt Issuance Cost | | Book Value |
| Unsecured senior notes: | | | | | | | | | | | | |
Due March 19, 2025 | | $ | 500,000 | | $ | (6,032) | | $ | 493,968 | | $ | 500,000 | | $ | (7,098) | | $ | 492,902 | $ | 487,148 |
| | $ | (6,421 | ) | | $ | 480,727 |
| | $ | 487,148 |
| | $ | (7,792 | ) | | $ | 479,356 |
|
| | | 500,000 | | | (6,032) | | | 493,968 | | | 500,000 | | | (7,098) | | | 492,902 | 487,148 |
| | (6,421 | ) | | 480,727 |
| | 487,148 |
| | (7,792 | ) | | 479,356 |
|
Less long-term debt due within one year | | | — | | | — | | | — | | | — | | | — | | | — | 0 |
| | 0 |
| | 0 |
| | 0 |
| | 0 |
| | 0 |
|
Long-term debt | | $ | 500,000 | | $ | (6,032) | | $ | 493,968 | | $ | 500,000 | | $ | (7,098) | | $ | 492,902 | $ | 487,148 |
| | $ | (6,421 | ) | | $ | 480,727 |
| | $ | 487,148 |
| | $ | (7,792 | ) | | $ | 479,356 |
|
Senior Notes
HPIDC 2025 Notes
On March 19, 2015, weour subsidiary, HPIDC issued $500$500.0 million of 4.65 percent 10-year unsecured senior notes.notes due 2025 of HPIDC (the "HPIDC 2025 Notes"), which were redeemed in full on September 27, 2019 as described under "––Exchange Offer, Consent Solicitation and Redemption." Interest ison the HPIDC 2025 Notes was payable semi-annually on March 15 and September 15. The debt discount iswas being amortized to interest expense using the effective interest method. The debt issuance costs were being amortized straight-line over the stated life of the obligation, which approximated the effective interest method.
Exchange Offer, Consent Solicitation and Redemption
On December 20, 2018, we settled an offer to exchange (the “Exchange Offer”) any and all outstanding HPIDC 2025 Notes for (i) up to $500.0 million aggregate principal amount of new 4.65 percent unsecured senior notes due 2025 of the Company (the “Company 2025 Notes”), with registration rights, and (ii) cash, pursuant to which we issued approximately $487.1 million in aggregate principal amount of Company 2025 Notes. Interest on the Company 2025 Notes is payable semi-annually on March 15 and September 15 of each year, commencing March 15, 2019. The debt issuance costs are
being amortized straight-line over the stated life of the obligation, which approximates the effective interest method.
Following the consummation of the Exchange Offer, HPIDC had outstanding approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes. On JulyDecember 20, 2018, HPIDC, the Company and Wells Fargo Bank, National Association, as trustee, entered into a supplemental indenture to the indenture governing the HPIDC 2025 Notes to adopt certain proposed amendments pursuant to a consent solicitation conducted concurrently with the Exchange Offer.
On September 27, 2019, we redeemed the remaining approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes for approximately $14.6 million, including accrued interest and a prepayment premium. Simultaneously with the redemption of the HPIDC 2025 Notes, HPIDC was released as a guarantor under the Company 2025 Notes and the 2018 Credit Facility. As a result of such release, H&P is the only obligor under the Company 2025 Notes and the 2018 Credit Facility.
Credit Facilities
On November 13, 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“2018 Credit Facility”) with a maturity date of Julythat is set to mature on November 13, 2021.2024. The 20162018 Credit Facility hadhas $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 the Base Rate. 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, 2018,2020, 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 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 had no borrowings against the line, but2020, there were three0 borrowings or 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 three2020, we had 2 separate outstanding letters of credit
by $1.3with banks, in the amounts of $24.8 million
which increased availability under the facility to $262.0and $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,
2018,2020, 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, $4.3 million of financial guarantees were outstanding as
needed, for international land operations. As of September 30,
2018, we do not2020. Subsequent to September 30, 2020, $2.6 million in financial guarantees have
any outstanding obligations against this facility. expired.
The applicable agreements for all unsecured debt contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30,
2018,2020, we were in compliance with all debt covenants.
At September 30, 2018,2020, aggregate maturities of long-term debt are as follows (in thousands):
| | | | | | | |
Year ending September 30, | | | | |
|
2019 | | $ | — | |
2020 | | | — | |
2021 | | | — | $ | 0 |
|
2022 | | | — | 0 |
|
2023 | | | — | 0 |
|
| 2024 | | 0 |
|
| 2025 | | 487,148 |
|
Thereafter | | | 500,000 | 0 |
|
| | $ | 500,000 | $ | 487,148 |
|
NOTE 89 INCOME TAXESImpact of Tax Reform
On December 22, 2017, the President of the United States signed into law the Tax Reform Act. Among a number of substantial changes to the current U.S. federal income tax rules, the Tax Reform Act decreases the marginal U.S. corporate income tax rate from 35 percent to 21 percent, provides for bonus depreciation that will allow for full expensing of qualified property in the year placed in service, limits the deductibility of certain expenditures, and significantly changes the U.S. taxation of certain foreign operations. By operation of law, we will apply a blended U.S. statutory federal income tax rate of 24.5 percent for fiscal year 2018. As a result of the Tax Reform Act, we were required to revalue deferred tax assets and liabilities from 35 percent to 21 percent. This revaluation has resulted in recognition of a tax benefit of approximately $502.1 million, which is included as a component of income tax expense in continuing operations on the Consolidated Statements of Operations.
On December 22, 2017, Staff Accounting Bulletin No. 118 ("SAB 118") was issued to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Reform Act. In accordance with SAB 118, we recorded our best estimate of the impact of the Tax Reform Act in our fiscal year end income tax provision in accordance with our understanding of the Tax Reform Act and guidance available as of the date of this filing. Although we believe we have substantially completed our accounting for certain income tax effects of the Tax Reform Act, to the extent that the Internal Revenue Service or U.S. Treasury issues additional guidance during the SAB 118 measurement period, the Company will promptly evaluate whether any additional adjustments are required.
Income Tax ProvisionBenefit and Rate
The components of the provision (benefit)benefit for income taxes are as follows:
| | | | | | | | | | |
| | Year Ended September 30, | | | | | | | |
| | 2018 | | 2017 | | 2016 | Year Ended September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 | | 2018 |
Current: | | | | | | | | | | | | | | |
Federal | | $ | 757 | | $ | (36,260) | | $ | (86,010) | $ | 15,431 |
| | $ | 21,745 |
| | $ | 757 |
|
Foreign | | | 6,492 | | | 4,108 | | | 9,987 | 1,495 |
| | 732 |
| | 6,492 |
|
State | | | 2,340 | | | (472) | | | (3,742) | 523 |
| | 3,365 |
| | 2,340 |
|
| | | 9,589 | | | (32,624) | | | (79,765) | 17,449 |
| | 25,842 |
| | 9,589 |
|
Deferred: | | | | | | | | | | | | | | |
Federal | | | (508,256) | | | (14,953) | | | 58,136 | (127,096 | ) | | (35,809 | ) | | (508,256 | ) |
Foreign | | | 7,415 | | | (7,827) | | | 408 | (12,390 | ) | | 2,804 |
| | 7,415 |
|
State | | | 14,083 | | | (1,331) | | | 1,544 | (18,069 | ) | | (11,549 | ) | | 14,083 |
|
| | | (486,758) | | | (24,111) | | | 60,088 | (157,555 | ) | | (44,554 | ) | | (486,758 | ) |
Total benefit | | $ | (477,169) | | $ | (56,735) | | $ | (19,677) | $ | (140,106 | ) | | $ | (18,712 | ) | | $ | (477,169 | ) |
The amounts of domestic and foreign income (loss) before income taxes are as follows:
| | | | | | | | | | |
| | Year Ended September 30, | | | | | | | |
| | 2018 | | 2017 | | 2016 | Year Ended September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 | | 2018 |
Domestic | | $ | 27,436 | | $ | (173,157) | | $ | (49,636) | $ | (458,364 | ) | | $ | (45,118 | ) | | $ | 27,436 |
|
Foreign | | | (11,595) | | | (11,441) | | | (23,031) | (178,134 | ) | | (6,104 | ) | | (11,595 | ) |
| | $ | 15,841 | | $ | (184,598) | | $ | (72,667) | $ | (636,498 | ) | | $ | (51,222 | ) | | $ | 15,841 |
|
Effective income tax rates as compared to the U.S. Federal income tax rate are as follows:
| | | | | | | | | | | | | | |
| | Year Ended September 30, | | Year Ended September 30, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
U.S. Federal income tax rate | | 24.5 | % | 35.0 | % | 35.0 | % | 21.0 | % | | 21.0 | % | | 24.5 | % |
Effect of foreign taxes | | 87.8 | | 1.8 | | (13.8) | | (0.2 | ) | | (0.6 | ) | | 87.8 |
|
State income taxes, net of federal tax benefit | | 68.8 | | 0.6 | | 3.2 | | 2.8 |
| | 17.2 |
| | 68.8 |
|
U.S. domestic production activities | | — | | (2.1) | | (10.4) | | |
Remeasurement of deferred tax related to Tax Reform Act | | (3,169.4) | | — | | — | | |
| Remeasurement of deferred tax related to Tax Cuts and Jobs Act | | 0 |
| | 0 |
| | (3,169.4 | ) |
Other impact of foreign operations | | (43.4) | | (2.9) | | 14.7 | | (0.5 | ) | | 0.9 |
| | (43.4 | ) |
Non-deductible meals and entertainment (1) | | 8.2 | | — | | — | | (0.2 | ) | | (2.5 | ) | | 8.2 |
|
Equity compensation (1) | | (5.3) | | — | | — | | (0.3 | ) | | 2.7 |
| | (5.3 | ) |
Officer's compensation (1) | | 1.7 | | — | | — | | |
| Excess officer's compensation | | (0.2 | ) | | (1.9 | ) | | 1.7 |
|
Contingent consideration adjustment (1) | | 10.7 | | — | | — | | 0 |
| | 4.5 |
| | 10.7 |
|
Other (1) | | 4.1 | | (1.7) | | (1.6) | | (0.4 | ) | | (4.8 | ) | | 4.1 |
|
Effective income tax rate | | (3,012.3) | % | 30.7 | % | 27.1 | % | 22.0 | % | | 36.5 | % | | (3,012.3 | )% |
| (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, | | | | | |
| | 2018 | | 2017 | September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 |
Deferred tax liabilities: | | | | | | | | | |
Property, plant and equipment | | $ | 904,734 | | $ | 1,386,512 | $ | 685,389 |
| | $ | 867,909 |
|
Available-for-sale securities | | | 10,464 | | | 24,940 | |
| Marketable securities | | 1,957 |
| | 0 |
|
Other | | | 12,787 | | | 21,609 | 26,138 |
| | 15,681 |
|
Total deferred tax liabilities | | | 927,985 | | | 1,433,061 | 713,484 |
| | 883,590 |
|
Deferred tax assets: | | | | | | | | | |
| Marketable securities | | 0 |
| | 771 |
|
Pension reserves | | | 3,477 | | | 7,614 | 7,369 |
| | 7,324 |
|
Self-insurance reserves | | | 13,100 | | | 19,461 | 10,360 |
| | 14,294 |
|
Net operating loss, foreign tax credit, and other federal tax credit carryforwards | | | 55,889 | | | 62,478 | 33,747 |
| | 41,126 |
|
Financial accruals | | | 45,708 | | | 62,971 | 32,481 |
| | 54,511 |
|
Other | | | 4,888 | | | 6,003 | 15,632 |
| | 2,531 |
|
Total deferred tax assets | | | 123,062 | | | 158,527 | 99,589 |
| | 120,557 |
|
Valuation allowance | | | (48,213) | | | (58,155) | (36,780 | ) | | (43,578 | ) |
Net deferred tax assets | | | 74,849 | | | 100,372 | 62,809 |
| | 76,979 |
|
Net deferred tax liabilities | | $ | 853,136 | | $ | 1,332,689 | $ | 650,675 |
| | $ | 806,611 |
|
The change in our net deferred tax assets and liabilities is impacted by foreign currency remeasurement.
As of September 30,
2018,2020, we had federal, state and foreign tax net operating loss carryforwards of
$50.8$7.3 million,
$31.2$25.7 million and
$83.7$39.9 million, respectively, and foreign tax credit carryforwards of approximately
$24.9$23.9 million (of which
$20.1$19.1 million is reflected as a deferred tax asset in our Consolidated Financial Statements prior to consideration of our valuation allowance) which will expire in fiscal years
20192021 through
2038.2040. The valuation allowance is primarily attributable to foreign
and certain state net operating loss carryforwards of
$22.8$11.3 million,
and $0.5 million, respectively, and foreign tax credit carryforwards of
$20.1$19.1 million, equity compensation of
$2.3$4.9 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,
20182020, and
2017,2019, we had accrued interest and penalties of
$2.2$2.8 million and
$2.8$2.1 million, respectively.
A reconciliation of the change in our gross unrecognized tax benefits for the fiscal years ended September 30, 20182020 and 20172019 is as follows:
| | | | | | | |
| | September 30, | | | | | |
| | 2018 | | 2017 | |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 |
Unrecognized tax benefits at October 1, | | $ | 4,773 | | $ | 9,551 | $ | 15,759 |
| | $ | 14,905 |
|
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) | (2,338 | ) | | (28 | ) |
Gross increases - current period effect of tax positions | | | 10,537 | | | 300 | 20 |
| | 1,067 |
|
Expiration of statute of limitations for assessments | | | (128) | | | (4,907) | (1 | ) | | (185 | ) |
Unrecognized tax benefits at September 30, | | $ | 14,905 | | $ | 4,773 | $ | 13,440 |
| | $ | 15,759 |
|
As of September 30,
20182020, and
2017,2019, our liability for unrecognized tax benefits includes
$14.3$13.0 million and
$3.7$15.3 million, respectively, of unrecognized tax benefits related to discontinued operations that, if recognized, would not affect the effective tax rate. The remaining unrecognized tax benefits would affect the effective tax rate if recognized. The liabilities for unrecognized tax benefits and related interest and penalties are included in other noncurrent liabilities in our Consolidated Balance Sheets.
For the next 12 months, we cannot predict with certainty whether we will achieve ultimate resolution of any uncertain tax position associated with our U.S. and international
land operations that could result in increases or decreases of our unrecognized tax benefits. However, we do not expect the increases or decreases to have a material effect on our results of operations or financial position.
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 20142016 through 2017,2019, with exception of certain state jurisdictions currently under audit. The tax years remaining open to examination by foreign jurisdictions include 2003 through 2017.2019.
NOTE 910 SHAREHOLDERS’ EQUITY The Company has
an evergreen authorization from the Board
of Directors for the repurchase of up to
four million4000000 common shares in any calendar year. The repurchases may be made using our cash and cash equivalents or other available sources.
During the fiscal year ended September 30, 2020, we purchased 1.5 million common shares at an aggregate cost of $28.5 million, which are held as treasury shares. We purchased 1.0 million common shares at an aggregate cost of $42.8 million, which are held as treasury shares, during the fiscal year ended September 30, 2019. We had
no0 purchases of common shares during the fiscal
yearsyear ended September 30,
2018, 2017 and 2016.2018.
As of September 30, 2020, we declared $209.8 million in cash dividends. A cash dividend of $0.25 per share was declared on September 9, 2020 for shareholders of record on November 13, 2020, payable on December 1, 2020. As a result, we recorded a Dividend Payable of $27.2 million on our Consolidated Balance Sheets as of September 30, 2020.
Accumulated Other Comprehensive Income (Loss)
Components of accumulated other comprehensive income (loss) were as follows:
| | | | | | | | | | |
| | September 30, | | | | | | | |
| | 2018 | | 2017 | | 2016 | September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 | | 2018 |
Pre-tax amounts: | | | | | | | | | | | | | | |
Unrealized appreciation on securities | | $ | 44,023 | | $ | 31,700 | | $ | 33,051 | |
Unrealized appreciation on securities (1) | | $ | 0 |
| | $ | 0 |
| | $ | 44,023 |
|
Unrealized actuarial loss | | | (21,693) | | | (28,873) | | | (34,112) | (33,923 | ) | | (37,084 | ) | | (21,693 | ) |
| | $ | 22,330 | | $ | 2,827 | | $ | (1,061) | $ | (33,923 | ) | | $ | (37,084 | ) | | $ | 22,330 |
|
After-tax amounts: | | | | | | | | | | | | | | |
Unrealized appreciation on securities | | $ | 29,071 | | $ | 20,070 | | $ | 20,899 | |
Unrealized appreciation on securities (1) | | $ | 0 |
| | $ | 0 |
| | $ | 29,071 |
|
Unrealized actuarial loss | | | (12,521) | | | (17,770) | | | (21,103) | (26,188 | ) | | (28,635 | ) | | (12,521 | ) |
| | $ | 16,550 | | $ | 2,300 | | $ | (204) | $ | (26,188 | ) | | $ | (28,635 | ) | | $ | 16,550 |
|
| |
| (1) | We adopted ASU No. 2016-01 on October 1, 2018. The standard requires that changes in the fair value of our equity investments must be recognized in net income. |
The following is a summary of the changes in accumulated other comprehensive
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, 2019 | $ | (28,635 | ) |
| Activity during the period | |
| Amounts reclassified from accumulated other comprehensive loss | 2,447 |
|
| Net current-period other comprehensive loss | 2,447 |
|
| Balance at September 30, 2020 | $ | (26,188 | ) |
NOTE 11 REVENUE FROM CONTRACTS WITH CUSTOMERS
Drilling Services Revenue
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, 2020, 2019 and 2018, 2017early termination revenue associated with term contracts was approximately $73.4 million, $11.3 million and 2016:$17.1 million, respectively. During the fiscal years ended September 30, 2020, 2019 and 2018, notification fee revenue related to well-to-well contracts was approximately $2.9 million, $1.2 million and $0.2 million, respectively.
| | | | | | | | | | | |
| | 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.
Demobilization fees expected to be received upon contract completion are estimated at contract inception and recognized on a straight-line basis over the contract term. The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced or no payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Any change in the expected amount of demobilization revenue is accounted for with the net cumulative impact of the change in estimate recognized in the period during which the revenue estimate is revised.
Contract Costs
Mobilization costs include certain direct costs incurred for mobilization of contracted rigs. These costs relate directly to a contract, enhance resources that will be used in satisfying the future performance obligations and are expected to be recovered. These costs are capitalized when incurred and recorded as current or noncurrent contract fulfillment cost assets (depending on the length of the initial contract term), and are amortized on a systematic basis consistent with the pattern of the transfer of the goods or services to which the asset relates which typically includes the initial term of the related drilling contract or a period longer than the initial contract term if management anticipates a customer will renew or extend a contract, which we expect to benefit from the cost of mobilizing the rig. Abnormal mobilization costs are fulfillment costs that are incurred from excessive resources, wasted or spoiled materials, and unproductive labor costs that are not otherwise anticipated in the contract price and are expensed as incurred. As of September 30, 2020, and 2019, we had capitalized fulfillment costs of $6.2 million and $13.9 million, respectively.
If capital 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, 2020 was approximately $670.1 million, of which $446.7 million is expected to be recognized during fiscal year 2021, and approximately $223.4 million in fiscal year 2022 and thereafter. These amounts do not include anticipated contract renewals. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. Our contracts are subject to cancellation or modification at the election of the customer; however, due to the level of capital deployed by our customers on underlying projects, we have not been materially adversely affected by contract cancellations or modifications in the past. However, the impact of the COVID-19 pandemic is inherently uncertain, and, as a result, the Company is unable to reasonably estimate the duration and ultimate impacts of the pandemic, including the effect it may have on our contractual obligations with our customers.
Contract Assets and Liabilities
Amounts owed from our customers under our revenue contracts are typically billed on a monthly basis as the service is being provided and are due within 30 days of billing. Such amounts are classified as accounts receivable on our Consolidated Balance Sheets. Under certain of our contracts, we recognize revenues in excess of billings, referred to as contract assets, within prepaid expenses and other current assets within our Consolidated Balance Sheets.
Under certain of our contracts, we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized, referred to as deferred revenue or contract liabilities, within accrued liabilities and other noncurrent liabilities in our Consolidated Balance Sheets. Contract balances are presented at the net amount at a contract level.
The following table summarizes the balances of our contract assets and liabilities at the dates indicated:
|
| | | | | | | |
| (in thousands) | September 30, 2020 | | September 30, 2019 |
| Contract assets | $ | 2,367 |
| | $ | 2,151 |
|
|
| | | |
| (in thousands) | September 30, 2020 |
| Contract liabilities balance at October 1, 2018 | $ | 38,472 |
|
| Payment received/accrued and deferred | 30,863 |
|
| Revenue recognized during the period | (45,981 | ) |
| Contract liabilities balance at September 30, 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 |
|
NOTE 1012 STOCK-BASED COMPENSATION On March 2, 2016,3, 2020, the Helmerich & Payne, Inc. 2020 Omnibus Incentive Plan (the “2020 Plan”) was approved by our stockholders. The 2020 Plan replaces our stockholder-approved Helmerich & Payne, Inc. 2016 Omnibus Incentive Plan (the “2016 Plan”"2016 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. 2005 Long-Term Incentive Plan, and the Helmerich & Payne, Inc. 2010 Long-Term Incentive Plan (collectivelyand the “2010 Plan”)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 0 stock options granted during the fiscal years ended September 30, 2020 and 2019. We have also eliminated stock options as an element of our non-employee director compensation program. The Board has determined to award stock-based compensation to non-employee directors solely in the form of restricted stock. During the fiscal year ended September 30, 2018, there were 693,873 non-qualified stock options and 411,9772020, 727,009 shares of restricted stock awards and 258,857 performance share units were granted under the 2016 Plan. An additional 213,904Plan and 54,118 shares of restricted stock grantsawards were awarded outside ofgranted under the 20162020 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 in fiscal years 2018, 20172020, 2019 and 20162018 is as follows:
| | | | | | | | | | |
| | September 30, | | | | | | | |
| | 2018 | | 2017 | | 2016 | September 30, |
| | (in thousands) | |
Compensation expense | | | | | | | | | | |
| (in thousands) | | 2020 | | 2019 | | 2018 |
| Stock-based compensation expense | | | | | | |
Stock options | | $ | 7,913 | | $ | 7,439 | | $ | 8,290 | $ | 1,753 |
| | $ | 3,721 |
| | $ | 7,913 |
|
Restricted stock | | | 23,774 | | | 18,744 | | | 16,093 | 30,605 |
| | 26,149 |
| | 23,774 |
|
| Performance share units | | 7,454 |
| | 4,422 |
| | 0 |
|
| Stock-based compensation benefit included in restructuring charges | | (3,483 | ) | | 0 |
| | 0 |
|
| | $ | 31,687 | | $ | 26,183 | | $ | 24,383 | $ | 36,329 |
| | $ | 34,292 |
| | $ | 31,687 |
|
Of the total stock-based compensation expense, $9.1 million was recorded in drilling services operating expense, $0.8 million was recorded in research and development expense, $29.9 million in selling, general and administrative expense and $(3.5) million was recorded in restructuring charges during the year ended September 30, 2020 on our Consolidated Statements of Operations.
Vesting requirements for stock options are determined by the Human Resources Committee of
our Board of Directors.the Board. Options currently outstanding began vesting one year after the grant date with 25 percent of the options vesting for
four4 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.
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)
| |
| 2018 |
Risk-free interest rate (1) | 2.2 | % |
Expected stock volatility (2) | 36.1 | % |
Dividend yield (3) | 4.7 | % |
Expected term (in years) (4) | 6.0 |
|
| |
| (1) | The risk-free interest rate is based on U.S. Treasury securities for the expected term of the option. |
| |
| (2) | | Expected volatilities are based on the daily closing price of our stock based upon historical experience over a period which approximates the expected term of the option. |
| |
| (3) | | The dividend yield is based on our current dividend yield. |
| |
| (4) | | The expected term of the options granted represents the period of time that they are expectexpected 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.year 2018.
The following summary reflects the stock option activity for our common stock and related information for fiscal years 2018, 20172020, 2019 and 2016 (shares in thousands):2018:
| | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | | | | | | | | | | | |
| | | | Weighted-Average | | | | Weighted-Average | | | | Weighted-Average | 2020 | | 2019 | | 2018 |
| | Shares | | Exercise Price | | Shares | | Exercise Price | | Shares | | Exercise Price | |
| (shares in thousands) | | Shares | | Weighted-Average Exercise Price | | Shares | | Weighted-Average Exercise Price | | Shares | | Weighted-Average Exercise Price |
Outstanding at October 1, | | 3,278 | | $ | 56.41 | | 3,312 | | $ | 51.74 | | 2,776 | | $ | 48.51 | 3,238 |
| | $ | 60.86 |
| | 3,499 |
| | $ | 58.62 |
| | 3,278 |
| | $ | 56.41 |
|
Granted | | 694 | | | 59.03 | | 396 | | | 76.61 | | 876 | | | 58.25 | 0 |
| | 0 |
| | 0 |
| | 0 |
| | 694 |
| | 59.03 |
|
Exercised | | (375) | | | 36.88 | | (415) | | | 38.04 | | (220) | | | 31.52 | (201 | ) | | 38.02 |
| | (217 | ) | | 24.46 |
| | (375 | ) | | 36.88 |
|
Forfeited/Expired | | (98) | | | 70.77 | | (15) | | | 68.32 | | (120) | | | 61.80 | (174 | ) | | 61.76 |
| | (44 | ) | | 62.14 |
| | (98 | ) | | 70.77 |
|
Outstanding on September 30, | | 3,499 | | $ | 58.62 | | 3,278 | | $ | 56.41 | | 3,312 | | $ | 51.74 | 2,863 |
| | $ | 62.41 |
| | 3,238 |
| | $ | 60.86 |
| | 3,499 |
| | $ | 58.62 |
|
Exercisable on September 30, | | 2,193 | | $ | 56.31 | | 2,167 | | $ | 50.87 | | 2,225 | | $ | 46.66 | 2,516 |
| | $ | 62.38 |
| | 2,482 |
| | $ | 60.38 |
| | 2,193 |
| | $ | 56.31 |
|
Shares available to grant | | 5,140 | | | | | 5,624 | | | | | 6,600 | | | | |
The following table summarizes information about stock options at September 30, 20182020 (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 | | | |
|
| | | | | | | | | | | | | | | |
| | Outstanding Stock Options | | Exercisable Stock Options |
| Range of Exercise Prices | Shares | | Weighted-Average Remaining Life | | Weighted-Average Exercise Price | | Shares | | Weighted-Average Exercise Price |
| $40.00 to $55.00 | 472 |
| | 1.82 | | $ | 51.86 |
| | 462 |
| | $ | 51.83 |
|
| $55.00 to $70.00 | 1,918 |
| | 5.07 | | 60.56 |
| | 1,641 |
| | 60.82 |
|
| $70.00 to $85.00 | 473 |
| | 4.92 | | 80.47 |
| | 412 |
| | 80.43 |
|
| | 2,863 |
| | | | | | 2,515 |
| | |
At September 30,
2018,2020, the weighted-average remaining life of exercisable stock options was
4.364.16 years and the aggregate intrinsic value was
$30.9 million0 with a weighted-average exercise price of
$56.31$62.38 per share.
The number of options vested or expected to vest at September 30,
20182020 was
1,306,087347,093 with an aggregate intrinsic value of
$10.6 million0 and a weighted-average exercise price of
$62.49$62.63 per share.
As of September 30,
2018,2020, the unrecognized compensation cost related to the stock options was
$7.3$1.2 million. That cost is expected to be recognized over a weighted-average period of
2.31.22 years.
The total intrinsic value of options exercised during fiscal years
2020, 2019 and 2018
2017was $0.3 million, $7.9 million 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
2020, 2019 and 2018
2017was $6.0 million, $8.0 million and
2016 was $8.8 million,
$6.7 million and $9.6 million, respectively.
Restricted stock awards consist of our common stock and are time-vested over
three to sixfour 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,
2018,2020, there was
$34.4$31.4 million of total unrecognized compensation cost related to unvested restricted stock awards. That cost is expected to be recognized over a weighted-average period of 2.4 years.
A summary of the status of our restricted stock awards as of September 30, 2018,2020, and of changes in restricted stock outstanding during the fiscal years ended September 30, 2018, 20172020, 2019 and 2016,2018, is as follows (shares in thousands):follows:
| | | | | | | | | | | | | | | |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| (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, | 1,085 |
| | $ | 61.28 |
| | 1,001 |
| | $ | 63.74 |
| | 659 |
| | $ | 70.76 |
|
Granted (1) | 781 |
| | 39.99 |
| | 475 |
| | 58.45 |
| | 626 |
| | 59.53 |
|
Vested (2) | (501 | ) | | 59.46 |
| | (371 | ) | | 64.32 |
| | (258 | ) | | 70.60 |
|
| Forfeited | (85 | ) | | 48.98 |
| | (20 | ) | | 60.85 |
| | (26 | ) | | 66.73 |
|
| Non-vested restricted stock outstanding at September 30, | 1,280 |
| | $ | 49.81 |
| | 1,085 |
| | $ | 61.28 |
| | 1,001 |
| | $ | 63.74 |
|
| |
| (1) | The number of restricted stock awards granted includes phantom shares that confer the benefits of owning company stock without the actual ownership or transfer of any shares. There were 20,616 phantom shares granted during fiscal year 2020. |
| |
| (2) | The number of restricted stock awards vested includes shares that we withheld on behalf of our employees to satisfy the statutory tax withholding requirements. |
Performance Share Units
We have made awards to certain employees that are subject to market-based performance conditions ("performance share units"). Subject to the terms and conditions set forth in the applicable performance share unit award agreements and the 2016 Plan, grants of performance share units are subject to a vesting period of three years (the “Vesting Period”) that is dependent on the achievement of certain performance goals. Such performance share unit awards consist of 2 separate components. Performance share units that comprise the first component are subject to a three-year performance cycle. Performance share units that comprise the second component are further divided into 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 share units is generally dependent on (i) the achievement of the Company’s total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Group”) over the applicable performance cycle, and (ii) the continued employment of the recipient of the performance share unit award throughout the Vesting Period.
At the end of the Vesting Period, recipients receive dividend equivalents, if any, with respect to the number of vested performance share units. The vesting of units ranges from 0 to 200 percent of the units granted depending on the Company’s TSR relative to the TSR of the Peer Group on the vesting date.
The grant date fair value of performance share units was determined through use of the Monte Carlo simulation method. The Monte Carlo simulation method requires the use of highly subjective assumptions. Our key assumptions in the method include the price and the expected volatility of our stock and our self-determined Peer Group companies' stock, risk free rate of return and cross-correlations between the Company and our Peer Group companies. The valuation model assumes dividends are immediately reinvested. As of September 30, 2020, there was $6.6 million of unrecognized compensation cost related to unvested performance share units. That cost is expected to be recognized over a weighted-average period of 1.9 years.
A summary of the status of our performance share units as of September 30, 2020 and changes in non-vested performance share units outstanding during the fiscal year ended September 30, 2020 is presented below:
|
| | | | | | | | | | | | | |
| | 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 |
| Non-vested performance share units outstanding at September 30, 2019 | 145 |
| | $ | 62.66 |
| | 0 |
| | $ | 0 |
|
| Granted | 259 |
| | 43.40 |
| | 145 |
| | 62.66 |
|
| Forfeited | (67 | ) | | 46.35 |
| | 0 |
| | 0 |
|
| Non-vested performance share units outstanding at September 30, 2020 | 337 |
| | $ | 51.09 |
| | 145 |
| | $ | 62.66 |
|
The weighted-average fair value calculations for performance share units granted within the fiscal period are based on the following weighted-average assumptions set forth in the table below.
|
| | | | | |
| | 2020 | | 2019 |
Risk-free interest rate (1) | 1.6 | % | | 2.7 | % |
Expected stock volatility (2) | 34.8 | % | | 35.9 | % |
| Expected term (in years) | 3.2 |
| | 3.0 |
|
| |
| (1) | The risk-free interest rate is based on U.S. Treasury securities for the expected term of the performance share units. |
| |
| (2) | Expected volatilities are based on the daily closing price of our stock based upon historical experience over a period which approximates the expected term of the performance share units. |
NOTE 1113 EARNINGS (LOSSES) PER COMMON SHARE ASC 260, Earnings per Share, requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividends or dividend equivalents as a separate class of securities in calculating earnings per share. We have granted and expect to continue to grant to employees restricted stock grants that contain non-forfeitable rights to dividends. Such grants are considered participating securities under ASC 260. As such, we are required to include these grants in the calculation of our basic earnings per share and calculate basic earnings per share using the two-class method. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.
Basic earnings per share is computed utilizing the two-class method and is calculated based on the weighted-average number of common shares outstanding during the periods presented.
Diluted earnings per share is computed using the weighted-average number of common and common equivalent shares outstanding during the periods utilizing the two-class method for stock options, nonvested restricted stock and performance share units.
Under the two-class method of calculating earnings per share, dividends paid and a portion of undistributed net income, but not losses, are allocated to unvested restricted stock grants that receive dividends, which are considered participating securities.
The following table sets forth the computation of basic and diluted earnings per share:
| | | | | | | | | | |
| | September 30, | | | | | | | |
| | 2018 | | 2017 | | 2016 | September 30, |
| | (in thousands) | |
| | | | | | | | | | |
| (in thousands, except per share amounts) | | 2020 | | 2019 | | 2018 |
Numerator: | | | | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | 493,010 | | $ | (127,863) | | $ | (52,990) | $ | (496,392 | ) | | $ | (32,510 | ) | | $ | 493,010 |
|
Loss from discontinued operations | | | (10,338) | | | (349) | | | (3,838) | |
| Income (loss) from discontinued operations | | 1,895 |
| | (1,146 | ) | | (10,338 | ) |
Net income (loss) | | | 482,672 | | | (128,212) | | | (56,828) | (494,497 | ) | | (33,656 | ) | | 482,672 |
|
Adjustment for basic earnings per share | | | | | | | | | | | | | | |
Earnings allocated to unvested shareholders | | | (4,346) | | | (1,811) | | | (1,858) | (2,647 | ) | | (3,102 | ) | | (4,346 | ) |
Numerator for basic earnings per share: | | | | | | | | | | |
| Numerator for basic earnings (loss) per share: | | | | | | |
From continuing operations | | | 488,664 | | | (129,674) | | | (54,848) | (499,039 | ) | | (35,612 | ) | | 488,664 |
|
From discontinued operations | | | (10,338) | | | (349) | | | (3,838) | 1,895 |
| | (1,146 | ) | | (10,338 | ) |
| | | 478,326 | | | (130,023) | | | (58,686) | (497,144 | ) | | (36,758 | ) | | 478,326 |
|
Adjustment for diluted earnings per share: | | | | | | | | | | |
| Adjustment for diluted earnings (loss) per share: | | | | | | |
Effect of reallocating undistributed earnings of unvested shareholders | | | 7 | | | — | | | — | 0 |
| | 0 |
| | 7 |
|
Numerator for diluted earnings per share: | | | | | | | | | | |
| Numerator for diluted earnings (loss) per share: | | | | | | |
From continuing operations | | | 488,671 | | | (129,674) | | | (54,848) | (499,039 | ) | | (35,612 | ) | | 488,671 |
|
From discontinued operations | | | (10,338) | | | (349) | | | (3,838) | 1,895 |
| | (1,146 | ) | | (10,338 | ) |
| | $ | 478,333 | | $ | (130,023) | | $ | (58,686) | $ | (497,144 | ) | | $ | (36,758 | ) | | $ | 478,340 |
|
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: | | | | | | | | | | |
| Denominator for basic earnings (loss) per share - weighted-average shares | | 108,009 |
| | 109,216 |
| | 108,851 |
|
| Effect of dilutive shares from stock options, restricted stock and performance share units | | 0 |
| | 0 |
| | 536 |
|
| Denominator for diluted earnings (loss) per share - adjusted weighted-average shares | | 108,009 |
| | 109,216 |
| | 109,387 |
|
| Basic earnings (loss) per common share: | | | | | | |
Income (loss) from continuing operations | | $ | 4.49 | | $ | (1.20) | | $ | (0.50) | $ | (4.62 | ) | | $ | (0.33 | ) | | $ | 4.49 |
|
Loss from discontinued operations | | | (0.10) | | | — | | | (0.04) | |
| Income (loss) from discontinued operations | | 0.02 |
| | (0.01 | ) | | (0.10 | ) |
Net income (loss) | | $ | 4.39 | | $ | (1.20) | | $ | (0.54) | $ | (4.60 | ) | | $ | (0.34 | ) | | $ | 4.39 |
|
Diluted earnings per common share: | | | | | | | | | | |
| Diluted earnings (loss) per common share: | | | | | | |
Income (loss) from continuing operations | | $ | 4.47 | | $ | (1.20) | | $ | (0.50) | $ | (4.62 | ) | | $ | (0.33 | ) | | $ | 4.47 |
|
Loss from discontinued operations | | | (0.10) | | | — | | | (0.04) | |
| Income (loss) from discontinued operations | | 0.02 |
| | (0.01 | ) | | (0.10 | ) |
Net income (loss) | | $ | 4.37 | | $ | (1.20) | | $ | (0.54) | $ | (4.60 | ) | | $ | (0.34 | ) | | $ | 4.37 |
|
We had a net loss for fiscal years 20172020 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 | |
| (in thousands, except per share amounts) | | 2020 | | 2019 | | 2018 |
| Potentially dilutive shares excluded as anti-dilutive | | 4,004 |
| | 3,031 |
| | 1,559 |
|
Weighted-average price per share | | $ | 68.28 | | $ | 74.38 | | $ | 63.73 | $ | 60.72 |
| | $ | 63.33 |
| | $ | 68.28 |
|
NOTE 1214 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 similar techniques that use significant unobservable inputs.
|
Level 2 — Observable inputs, other than quoted prices included in Level 1, such as quoted prices for similar assets or liabilities in active markets; quoted prices for similar assets and liabilities in markets that are not active; or other inputs that are observable or can be corroborated by observable market data.Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes pricing models, discounted cash flow methodologies and similar techniques that use significant unobservable inputs.
The assets held in a Non-Qualified Supplemental Savings Plan are carried at fair value and totaled
$16.2$19.8 million and
$13.9$15.7 million at September 30,
20182020 and
2017,2019, respectively. The assets are comprised of mutual funds that are measured using Level 1 inputs.
Short-term investments include securities classified as trading securities. Both realized and unrealized gains and losses on trading securities are included in other income (expense) in the Consolidated Statements of Operations. The securities are recorded at fair value.
Our non-financial assets, such as intangible assets, goodwill and property, plant and equipment, are recorded at fair value when acquired in a business combination or when an impairment charge is recognized. If measured at fair value in the Consolidated Balance Sheets, these would generally be classified within Level 2 or 3 of the fair value hierarchy.
Refer to Note 3—Business Combinations, Note 5—Property, Plant and Equipment and Note 6—Goodwill and Intangible Assets for details on these fair value measurements.The majority of cash equivalents are invested in highly-liquid money-market mutual funds invested primarily in direct or indirect obligations of the U.S.
Government.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,
20182020 and
2017.2019.The following table summarizes our assets and liabilities measured at fair value presented in our Consolidated Balance Sheet as of September 30, 2018:
Sheet: | | | | | | | | | | | | | |
| | Fair Value | | (Level 1) | | (Level 2) | | (Level 3) | | | | | | | | | |
| | (in thousands) | September 30, 2020 |
| (in thousands) | | Fair Value | | Level 1 | | Level 2 | | Level 3 |
Recurring fair value measurements: | | | | | | | | | | | | | | | | | | | |
Short-term investments: | | | | | | | | | | | | | | | | | | | |
Certificates of deposit | | $ | 1,500 | | $ | — | | $ | 1,500 | | $ | — | $ | 1,370 |
| | $ | 0 |
| | $ | 1,370 |
| | $ | 0 |
|
Corporate and municipal debt securities | | | 17,518 | | | — | | | 17,518 | | | — | $ | 78,156 |
| | $ | 0 |
| | $ | 78,156 |
| | $ | 0 |
|
U.S. government and federal agency securities | | | 22,443 | | | 22,443 | | | — | | | — | $ | 7,817 |
| | $ | 7,817 |
| | $ | 0 |
| | $ | 0 |
|
| Other | | 1,992 |
| | 1,992 |
| | 0 |
| | 0 |
|
Total short-term investments | | | 41,461 | | | 22,443 | | | 19,018 | | | — | 89,335 |
| | 9,809 |
| | 79,526 |
| | 0 |
|
Cash and cash equivalents | | | 284,355 | | | 284,355 | | | — | | | — | 487,884 |
| | 487,884 |
| | 0 |
| | 0 |
|
Investments | | | 82,496 | | | 82,496 | | | — | | | — | 11,766 |
| | 7,274 |
| | 3,992 |
| | 500 |
|
Other current assets | | | 39,830 | | | 39,830 | | | — | | | — | 45,577 |
| | 45,577 |
| | 0 |
| | 0 |
|
Other assets | | | 2,000 | | | 2,000 | | | — | | | — | 3,286 |
| | 3,286 |
| | 0 |
| | 0 |
|
Total assets measured at fair value | | $ | 450,142 | | $ | 431,124 | | $ | 19,018 | | $ | — | $ | 637,848 |
| | $ | 553,830 |
| | $ | 83,518 |
| | $ | 500 |
|
| | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | |
Contingent earnout liability | | $ | 11,160 | | $ | — | | $ | — | | $ | 11,160 | $ | 9,123 |
| | $ | 0 |
| | $ | 0 |
| | $ | 9,123 |
|
At September 30,
2018,2020, our financial instruments measured at fair value utilizing Level 1 inputs include cash equivalents, U.S. Agency issued debt securities, equity securities with active markets, and money market funds that are classified as restricted assets. The current portion of restricted amounts are included in prepaid expenses and other, and the noncurrent portion is included in other assets. For these items, quoted current market prices are readily available.
At September 30,
2018,2020, assets measured at fair value using Level 2 inputs include certificates of deposit, municipal bonds and corporate bonds measured using broker quotations that utilize observable market inputs.
Our financial instruments measured using Level 3
unobservable inputs
primarily consist of potential earnout payments
primarily associated with
the acquisition of MOTIVEour business acquisitions 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.2019.
The following table presents a reconciliation of changes in the fair value of our financial assets and liabilities classified as Level 3 fair value measurements in the fair value hierarchy for the indicated periods:fiscal years 2020 and 2019:
| | | | | | |
| | 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 |
|
| | | | | | | |
| (in thousands) | 2020 | | 2019 |
| Net liabilities at beginning of period | $ | 18,373 |
| | $ | 11,160 |
|
| Additions | 1,500 |
| | 18,373 |
|
| Total gains or losses: | | | |
| Included in earnings | (2,500 | ) | | (11,160 | ) |
Settlements (1) | (8,250 | ) | | 0 |
|
| Net liabilities at end of period | $ | 9,123 |
| | $ | 18,373 |
|
| |
| (1) | | Settlements represent earnout payments that have been earned or paid during the period. |
The following table provides quantitative information (in thousands) about our Level 3 unobservable inputs related to our financial liabilities at September 30, 2020:
|
| | | | | | | | | | | | | |
| Fair Value | | Valuation Technique | | Unobservable Input | | Unobservable Input | | Range | | Weighted Average (1) |
| $1,000 | | Monte Carlo simulation | | Discount rate | | 1.6 | % | | | | |
| | | | | Revenue Volatility | | 46.2 | % | | | | |
| | | | | Risk free rate | | 1.2 | % | | | | |
| $8,123 | | Probability Analysis | | Discount rate | | 1.0 | % | | | | |
| | | | | Payment amounts | | | | $5,250 - $7,000 | | $ | 6,400 |
|
| | | | | Probabilities | | | | 40% - 60% | | 53 | % |
| |
| (1) | The weighted average of the payment amounts and the probabilities (Level 3 unobservable inputs), associated with the contingent consideration valued using probability analysis, were weighted by the relative undiscounted fair value of payment amounts and of probability payment amounts, respectively. |
The above significant unobservable inputs are subject to change based on changes in economic and market conditions.The use of significant unobservable inputs creates uncertainty in the measurement of fair value as of the reporting date. The significant unobservable inputs used in the fair value measurement of the contingent consideration using Monte Carlo simulation are (i) discount rate, (ii) revenue volatility and (iii) risk-free rate. Significant increases or decreases in the discount rate and risk-free rate in isolation would result in a significantly lower or higher fair value measurement. Significant changes in revenue volatility in isolation would result in a significantly lower or higher fair value measurement. The significant unobservable inputs used in the fair value measurement of the contingent consideration using probability analysis are (i) discount rate, (ii) payment amounts and (iii) probabilities. Significant increases or decreases in the discount rate in isolation would result in a significantly lower or higher fair value measurement. Significant increases or decreases in the payment amounts or probabilities in isolation would result in a significantly higher or lower fair value measurement. It is not possible for us to predict the effect of future economic or market conditions on our estimated fair values.
The following information presents the supplemental fair value information about long-term fixed-rate debt at September 30, 20182020 and September 30, 2017.2019:
| | | | | | | |
| | September 30, | | | | | |
| | 2018 | | 2017 | September 30, |
| | (in millions) | |
| (in millions) | | 2020 | | 2019 |
Carrying value of long-term fixed-rate debt | | $ | 494.0 | | $ | 492.9 | $ | 480.7 |
| | $ | 479.4 |
|
Fair value of long-term fixed-rate debt | | $ | 509.3 | | $ | 529.0 | $ | 534.5 |
| | $ | 526.4 |
|
The fair value for the
$500$534.5 million fixed-rate debt was based on broker quotes at September 30,
2018.2020. 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
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,investments, reflected on our Consolidated Balance Sheets as Investments, is primarily based on Level 1 inputs. The following isAs a summaryresult of available-for-sale securities, which excludes assets heldthe change in the fair value of our investments, we recorded a Non-Qualified Supplemental Savings Plan:
loss of $8.7 million for the fiscal year ended September 30, 2020. In September 2019, we sold our remaining 1.6 million shares in Valaris, previously known as Ensco Rowan plc, for total proceeds of approximately $12.0 million. | | | | | | | | | | | | |
| | | | | 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 1315 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, 20172020 and a statement of the funded status as of September 30, 20182020 and 2017:2019:
| | | | | | | |
| | 2018 | | 2017 | | | | | |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 |
Accumulated Benefit Obligation | | $ | 106,205 | | $ | 109,976 | $ | 116,146 |
| | $ | 119,845 |
|
Changes in projected benefit obligations | | | | | | | | | |
Projected benefit obligation at beginning of year | | $ | 109,976 | | $ | 109,731 | $ | 119,845 |
| | $ | 106,205 |
|
Interest cost | | | 4,077 | | | 4,053 | 3,598 |
| | 4,389 |
|
Actuarial (gain) loss | | | (2,143) | | | 3,633 | 4,310 |
| | 16,914 |
|
Benefits paid | | | (5,705) | | | (7,441) | (11,607 | ) | | (7,663 | ) |
Projected benefit obligation at end of year | | $ | 106,205 | | $ | 109,976 | $ | 116,146 |
| | $ | 119,845 |
|
Change in plan assets | | | | | | | | | |
Fair value of plan assets at beginning of year | | $ | 92,816 | | $ | 90,748 | $ | 91,142 |
| | $ | 94,897 |
|
Actual return on plan assets | | | 7,754 | | | 9,470 | 6,535 |
| | 3,865 |
|
Employer contribution | | | 32 | | | 39 | 33 |
| | 43 |
|
Benefits paid | | | (5,705) | | | (7,441) | (11,607 | ) | | (7,663 | ) |
Fair value of plan assets at end of year | | $ | 94,897 | | $ | 92,816 | $ | 86,103 |
| | $ | 91,142 |
|
Funded status of the plan at end of year | | $ | (11,308) | | $ | (17,160) | $ | (30,043 | ) | | $ | (28,703 | ) |
The amounts recognized in the Consolidated Balance Sheets at September 30, 20182020 and 20172019 are as follows (in thousands):
| | | | | | | | | | | | |
Accrued liabilities | | $ | (58) | | $ | (45) | $ | (18 | ) | | $ | (50 | ) |
Noncurrent liabilities-other | | | (11,250) | | | (17,115) | (30,025 | ) | | (28,653 | ) |
Net amount recognized | | $ | (11,308) | | $ | (17,160) | $ | (30,043 | ) | | $ | (28,703 | ) |
The amounts recognized in Accumulated Other Comprehensive Income (Loss) at September 30,
20182020 and
2017,2019, and not yet reflected in net periodic benefit cost, are as follows (in thousands):
| | | | | | |
Net actuarial loss | | $ | (21,693) | | $ | (28,873) |
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$2.4 million.
The weighted average assumptions used for the pension calculations were as follows:
| | | | | | | | | | | | | | |
| | September 30, | September 30, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
Discount rate for net periodic benefit costs | | 3.79 | % | 3.64 | % | 4.27 | % | 3.16 | % | | 4.27 | % | | 3.79 | % |
Discount rate for year-end obligations | | 4.27 | % | 3.79 | % | 3.64 | % | 2.66 | % | | 3.16 | % | | 4.27 | % |
Expected return on plan assets | | 6.06 | % | 6.17 | % | 5.89 | % | 4.65 | % | | 5.60 | % | | 6.06 | % |
The mortality table issued by the Society of Actuaries in October
20182019 was used for the September 30,
20182020 pension calculation.
The new mortality information reflects improved life expectancies and projected mortality improvements.We did not make any contributions to the Pension Plan in fiscal year
2018.2020. In fiscal year
2019,2021, we do not expect minimum contributions required by law to be needed. However, we may make contributions in fiscal year
20192021 if needed to fund unexpected distributions in lieu of liquidating pension assets.
Components of the net periodic pension expense (benefit) were as follows:
| | | | | | | | | | |
| | Year Ended September 30, | | | | | | | |
| | 2018 | | 2017 | | 2016 | Year Ended September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 | | 2018 |
Interest cost | | $ | 4,077 | | $ | 4,053 | | $ | 4,266 | $ | 3,598 |
| | $ | 4,389 |
| | $ | 4,077 |
|
Expected return on plan assets | | | (5,555) | | | (5,130) | | | (5,616) | (4,784 | ) | | (5,523 | ) | | (5,555 | ) |
Recognized net actuarial loss | | | 1,926 | | | 2,891 | | | 2,083 | 2,718 |
| | 1,229 |
| | 1,926 |
|
Settlement | | | 913 | | | 1,640 | | | 4,964 | 3,001 |
| | 1,953 |
| | 913 |
|
Net pension expense | | $ | 1,361 | | $ | 3,454 | | $ | 5,697 | $ | 4,533 |
| | $ | 2,048 |
| | $ | 1,361 |
|
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 | |
| 2021 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 – 2030 | | Total |
$ | 18,075 | | $ | 7,433 | | $ | 5,684 | | $ | 6,351 | | $ | 6,665 | | $ | 31,813 | | $ | 76,021 | 5,931 |
| | $ | 6,910 |
| | $ | 6,980 |
| | $ | 7,023 |
| | $ | 7,141 |
| | $ | 33,599 |
| | $ | 67,584 |
|
Included in the Pension Plan is an unfunded supplemental executive retirement plan.
Investment Strategy and Asset Allocation
Our investment policy and strategies are established with a long-term view in mind. The investment strategy is intended to help pay the cost of the Pension Plan while providing adequate security to meet the benefits promised under the Pension Plan. We maintain a diversified asset mix to minimize the risk of a material loss to the portfolio value that might occur from devaluation of any single investment. In determining the appropriate asset mix, our financial strength and ability to fund potential shortfalls are considered. Pension Plan assets are invested in portfolios of diversified public-market equity securities and fixed income securities. The Pension Plan does not directly hold securities of the Company.
The expected long-term rate of return on Pension Plan assets is based on historical and projected rates of return for current and planned asset classes in the Pension Plan’s investment portfolio after analyzing historical experience and future expectations of the return and volatility of various asset classes.
The target allocation for 20192021 and the asset allocation for the Pension Plan at the end of fiscal years 20182020 and 2017,2019, by asset category, follows:
| | | | | | | | |
| | | | Percentage | | |
| | | | of Plan | | |
| | Target | | Assets at | | | | | | | |
| | Allocation | | September 30, | | Target Allocation | | September 30, |
Asset Category | | 2019 | | 2018 | | 2017 | | 2021 | | 2020 | | 2019 |
U.S. equities | | 45 | % | 52 | % | 50 | % | 45 | % | | 42 | % | | 47 | % |
International equities | | 20 | | 15 | | 16 | | 20 |
| | 22 |
| | 16 |
|
Fixed income | | 35 | | 33 | | 34 | | 35 |
| | 36 |
| | 37 |
|
Real estate and other | | — | | — | | — | | |
Total | | 100 | % | 100 | % | 100 | % | 100 | % | | 100 | % | | 100 | % |
The fair value of Pension Plan assets at September 30, 20182020 and 2017,2019, summarized by level within the fair value hierarchy described in Note 12—14—Fair Value Measurement of Financial Instruments, are as follows:
| | | | | | | | | | | | |
| | Fair Value as of September 30, 2018 |
| | Total | | Level 1 | | Level 2 | | Level 3 |
| | (in thousands) |
Short-term investments | | $ | 2,745 | | $ | 2,745 | | $ | — | | $ | — |
Mutual funds: | | | | | | | | | | | | |
Domestic stock funds | | | 18,361 | | | 18,361 | | | — | | | — |
Bond funds | | | 17,918 | | | 17,918 | | | — | | | — |
Balanced funds | | | 17,977 | | | 17,977 | | | — | | | — |
International stock funds | | | 14,548 | | | 14,548 | | | — | | | — |
Total mutual funds | | | 68,804 | | | 68,804 | | | — | | | — |
Domestic common stock | | | 23,232 | | | 20,771 | | | 2,461 | | | — |
Oil and gas properties | | | 116 | | | — | | | — | | | 116 |
Total | | $ | 94,897 | | $ | 92,320 | | $ | 2,461 | | $ | 116 |
| | | | | | | | | | | | | |
| | Fair Value as of September 30, 2017 | | | | | | | | | |
| | Total | | Level 1 | | Level 2 | | Level 3 | September 30, 2020 |
| | (in thousands) | |
| (in thousands) | | Total | | Level 1 | | Level 2 | | Level 3 |
Short-term investments | | $ | 3,488 | | $ | 3,488 | | $ | — | | $ | — | $ | 1,541 |
| | $ | 1,541 |
| | $ | 0 |
| | $ | 0 |
|
Mutual funds: | | | | | | | | | | | | | | | | | | | |
Domestic stock funds | | | 18,377 | | | 18,377 | | | — | | | — | 35,660 |
| | 35,660 |
| | 0 |
| | 0 |
|
Bond funds | | | 18,357 | | | 18,357 | | | — | | | — | 17,328 |
| | 17,328 |
| | 0 |
| | 0 |
|
Balanced funds | | | 18,222 | | | 18,222 | | | — | | | — | 17,447 |
| | 17,447 |
| | 0 |
| | 0 |
|
International stock funds | | | 14,583 | | | 14,583 | | | — | | | — | 14,044 |
| | 14,044 |
| | 0 |
| | 0 |
|
Total mutual funds | | | 69,539 | | | 69,539 | | | — | | | — | 84,479 |
| | 84,479 |
| | 0 |
| | 0 |
|
Domestic common stock | | | 19,692 | | | 19,692 | | | — | | | — | |
Oil and gas properties | | | 97 | | | — | | | — | | | 97 | 83 |
| | 0 |
| | 0 |
| | 83 |
|
Total | | $ | 92,816 | | $ | 92,719 | | $ | — | | $ | 97 | $ | 86,103 |
| | $ | 86,020 |
| | $ | 0 |
| | $ | 83 |
|
The
|
| | | | | | | | | | | | | | | |
| | September 30, 2019 |
| (in thousands) | Total | | Level 1 | | Level 2 | | Level 3 |
| Short-term investments | $ | 3,072 |
| | $ | 3,072 |
| | $ | 0 |
| | $ | 0 |
|
| Mutual funds: | | | | | | | |
| Domestic stock funds | 17,555 |
| | 17,555 |
| | 0 |
| | 0 |
|
| Bond funds | 18,034 |
| | 18,034 |
| | 0 |
| | 0 |
|
| Balanced funds | 17,878 |
| | 17,878 |
| | 0 |
| | 0 |
|
| International stock funds | 14,181 |
| | 14,181 |
| | 0 |
| | 0 |
|
| Total mutual funds | 67,648 |
| | 67,648 |
| | 0 |
| | 0 |
|
| Domestic common stock | 20,261 |
| | 17,748 |
| | 2,513 |
| | 0 |
|
| Oil and gas properties | 161 |
| | 0 |
| | 0 |
| | 161 |
|
| Total | $ | 91,142 |
| | $ | 88,468 |
| | $ | 2,513 |
| | $ | 161 |
|
As of September 30, 2020, and 2019, the Pension Plan’s financial assets utilizing Level 1 inputs are valued based on quoted prices in active markets for identical securities.
TheAs of September 30, 2019, the Pension Plan’s Level 2 financial assets include
foreigndomestic common stock.
TheAs of September 30, 2020, and 2019, the Pension Plan’s assets utilizing Level 3 inputs consist of oil and gas properties. The fair value of oil and gas properties is determined by Wells Fargo Bank, N.A., based upon actual revenue received for the previous twelve-month period and experience with similar assets.
The following table sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the fiscal years ended September 30, 20182020 and 2017:
2019: | | | | | | | |
| | Oil and Gas Properties | | | | | |
| | Year Ended | Oil and Gas Properties |
| | September 30, | Year Ended September 30, |
| | 2018 | | 2017 | |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 |
Balance, beginning of year | | $ | 97 | | $ | 177 | $ | 161 |
| | $ | 116 |
|
Unrealized gains (losses) relating to property still held at the reporting date | | | 19 | | | (80) | (78 | ) | | 45 |
|
Balance, end of year | | $ | 116 | | $ | 97 | $ | 83 |
| | $ | 161 |
|
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$23.8 million,
$16.6$30.5 million and
$21.6$26.6 million in fiscal years
2020, 2019 and 2018,
2017 and 2016, respectively.
During fiscal year 2016, we determined that employee workforce reductions which started during 2015 and continued into 2016 due to reduced drilling activity resulted in a partial plan termination of the 401(k)/Thrift Plan. Partial plan terminations result in affected participants becoming fully vested in Company contributions and actual earnings thereon at the termination date. As a result of the partial plan termination status, we accrued additional employer contributions totaling $6.3 million in general and administrative expense in fiscal year 2016.
NOTE 1416 SUPPLEMENTAL BALANCE SHEET INFORMATION The following reflects the activity in our reserve for bad debt for fiscal years
2018, 20172020, 2019 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 |
Table of Contents
|
| | | | | | | | | | | |
| (in thousands) | 2020 | | 2019 | | 2018 |
| Reserve for bad debt: | | | | | |
| Balance at October 1, | $ | 9,927 |
| | $ | 6,217 |
| | $ | 5,721 |
|
| Provision for bad debt | 2,203 |
| | 2,321 |
| | 2,193 |
|
| (Write-off) recovery of bad debt | (10,310 | ) | | 1,389 |
| | (1,697 | ) |
| Balance at September 30, | $ | 1,820 |
| | $ | 9,927 |
| | $ | 6,217 |
|
Accounts receivable, prepaid expenses and other current assets, accrued liabilities and long-term liabilities at September 30, 20182020 and 20172019 consist of the following:
| | | | | | | |
| | September 30, | | | | | |
| | 2018 | | 2017 | September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 |
Accounts receivable, net of reserve: | | | | | | | | | |
Trade receivables | | $ | 530,859 | | $ | 398,348 | $ | 150,249 |
| | $ | 461,774 |
|
Income tax receivable | | | 34,343 | | | 78,726 | 42,374 |
| | 33,828 |
|
Total accounts receivable, net of reserve | | $ | 565,202 | | $ | 477,074 | $ | 192,623 |
| | $ | 495,602 |
|
| | | | | | | |
Prepaid expenses and other current assets: | | | | | | | | | |
Restricted cash | | $ | 39,830 | | $ | 32,439 | $ | 45,577 |
| | $ | 31,291 |
|
Deferred mobilization | | | 6,484 | | | 6,458 | 4,528 |
| | 10,571 |
|
Prepaid insurance | | | 6,149 | | | 4,060 | 8,655 |
| | 5,556 |
|
Prepaid value added tax | | | 1,931 | | | 3,870 | 7,484 |
| | 5,209 |
|
Prepaid maintenance and rent | | | 8,526 | | | 5,940 | 7,273 |
| | 9,113 |
|
Prepaid multi-flex rig fabrication | | | 1,327 | | | — | |
| Accrued demobilization | | 2,367 |
| | 2,151 |
|
Other | | | 2,151 | | | 2,356 | 13,421 |
| | 5,037 |
|
Total prepaid expenses and other current assets | | $ | 66,398 | | $ | 55,123 | $ | 89,305 |
| | $ | 68,928 |
|
Accrued liabilities: | | | | | | | | | |
Accrued operating costs | | $ | 37,528 | | $ | 36,949 | $ | 10,942 |
| | $ | 34,992 |
|
Payroll and employee benefits | | | 80,915 | | | 54,941 | 27,068 |
| | 79,465 |
|
Taxes payable, other than income tax | | | 50,683 | | | 35,638 | 39,762 |
| | 50,566 |
|
Self-insurance liabilities | | | 15,887 | | | 22,159 | 36,518 |
| | 37,117 |
|
Deferred income | | | 20,527 | | | 25,893 | 9,266 |
| | 25,426 |
|
Deferred mobilization | | | 9,662 | | | 9,828 | |
| Deferred mobilization revenue | | 5,705 |
| | 14,737 |
|
Accrued income taxes | | | 7,375 | | | 8,011 | 0 |
| | 19,277 |
|
Escrow | | | 11,258 | | | 4,690 | 138 |
| | 1,388 |
|
Litigation and claims | | | 1,749 | | | 1,779 | 393 |
| | 9,990 |
|
| Contingent earnout liability | | 4,926 |
| | 5,535 |
|
| Operating lease liability | | 11,364 |
| | — |
|
Other | | | 8,920 | | | 8,869 | 9,360 |
| | 8,599 |
|
Total accrued liabilities | | $ | 244,504 | | $ | 208,757 | $ | 155,442 |
| | $ | 287,092 |
|
Noncurrent liabilities — Other: | | | | | | | | | |
Pension and other non-qualified retirement plans | | $ | 35,051 | | $ | 37,989 | $ | 54,043 |
| | $ | 51,768 |
|
Self-insurance liabilities | | | 39,380 | | | 29,037 | 37,369 |
| | 37,118 |
|
Contingent earnout liability | | | 11,160 | | | 14,879 | 4,197 |
| | 12,838 |
|
Deferred mobilization | | | 2,738 | | | 7,689 | |
| Deferred revenue | | 2,955 |
| | 9,471 |
|
Uncertain tax positions including interest and penalties | | | 2,870 | | | 3,562 | 2,895 |
| | 2,544 |
|
| Operating lease liability | | 33,886 |
| | — |
|
Payroll tax deferral(1) | | 10,205 |
| | 0 |
|
Other | | | 2,407 | | | 8,253 | 1,630 |
| | 2,007 |
|
Total noncurrent liabilities — other | | $ | 93,606 | | $ | 101,409 | $ | 147,180 |
| | $ | 115,746 |
|
| |
| (1) | Deferral related to the provisions within the Coronavirus Aid, Relief, and Economic Security Act, passed on March 27, 2020, which allows for the deferral of the employer share of Social Security tax. |
NOTE 1517 COMMITMENTS AND CONTINGENCIES Equipment, parts and supplies are ordered in advance to promote efficient construction and capital improvement progress. At September 30,
2018,2020, we had purchase commitments for equipment, parts and supplies of approximately
$110.4$2.7 million.
Lease Obligations
Refer to Note 6—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
In January 2018, an employee of HPIDC suffered personal injury and subsequently brought a lawsuit against the operator and H&P. Pursuant to the terms of the drilling contract between HPIDC and the operator, HPIDC indemnified the operator in our Consolidated Financial Statementsthe lawsuit, subject to certain limitations. H&P has settled this matter on behalf of itself and the operator with $21.0 million of the settlement amount to be paid by the Company. The settlement was paid out during the fiscal yearsyear ended September 30, 2018,2019. While we believe we had meritorious defenses to the matter, we determined that settlement was a reasonable alternative to the uncertainty and expense associated with a jury trial.
In October 2017, an employee of HPIDC suffered personal injury and 2016.subsequently brought a lawsuit against the operator. Pursuant to the terms of the drilling contract between HPIDC and the operator, HPIDC indemnified the operator in the lawsuit, subject to certain limitations. A settlement agreement was reached with the operator. As of September 30, 2019, we accrued $9.5 million for this lawsuit, which was subsequently paid out during the fiscal year ended September 30, 2020.
The Company and its subsidiaries are parties to various other pending legal actions arising in the ordinary course of our business. We maintain insurance against certain business risks subject to certain deductibles. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact on our financial condition, cash flows, or results of operations. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.
NOTE 1618 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 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,
During the third quarter of fiscal year 2020, as part of our contractrestructuring efforts (see Note 19—Restructuring Charges) and consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, we implemented organizational changes. We are moving from a product-based offering, such as a rig or separate technology package, to an integrated solution-based approach by combining proprietary rig technology, automation software, and digital expertise into our rig operations. Operations previously reported within the former U.S. Land and H&P Technologies operating and reportable segments are now managed and presented within the North America Solutions reportable segment. As a result, beginning with the third quarter of fiscal year 2020, our drilling business includesservices operations are organized into the following reportable operating business segments: North America Solutions, Offshore Gulf of Mexico and International Solutions. All prior period segment disclosures have been recast for these segment changes. Our real estate operations, our incubator program for new research and development projects, and our wholly-owned captive insurance companies are included in "Other." Consolidated revenues and expenses reflect the elimination of intercompany transactions. Each reportable operating segment is a strategic business unit that is managed separately, and consolidated revenues and expenses reflect the elimination of all material intercompany transactions.Other includes additional non-reportable operating segments. RevenuesExternal revenues included in “other”"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
Direct operating costs
Depreciation and amortization
| ·
|
| • | | Revenues from external and internal customers
|
| ·
| | Allocated general and administrative costs costs |
Asset impairment charges
Restructuring charges
but excludes
acquisition relatedgain 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.
General and administrative costs are allocated to the segments based primarily on specific identification and, to the extent that such identification is not practical, on other methods which we believe to be a reasonable reflection of the utilization of services provided.
Summarized financial information of our reportable segments for 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, 2020, 2019 and 2018 is shown in the following tables:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | 0 |
| | 0 |
| | 0 |
| | 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 |
|
Table of Contents
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2019 |
| (in thousands) | North America Solutions (1) | | Offshore Gulf of Mexico | | International Solutions | | Other | | Eliminations | | Total |
| External sales | $ | 2,426,191 |
| | $ | 147,635 |
| | $ | 211,731 |
| | $ | 12,933 |
| | $ | — |
| | $ | 2,798,490 |
|
| Intersegment | 0 |
| | 0 |
| | 0 |
| | 0 |
| | 0 |
| | — |
|
| Total sales | 2,426,191 |
| | 147,635 |
| | 211,731 |
| | 12,933 |
| | 0 |
| | 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 |
|
| |
| (1) | Operations previously reported within the H&P Technologies reportable segment are now managed and presented within the North America Solutions reportable segment. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2018 |
| (in thousands) | North America Solutions (1) | | Offshore Gulf of Mexico | | International Solutions | | Other | | Eliminations | | Total |
| External sales | $ | 2,093,601 |
| | $ | 142,500 |
| | $ | 238,356 |
| | $ | 12,811 |
| | $ | — |
| | $ | 2,487,268 |
|
| Intersegment | 0 |
| | 0 |
| | 0 |
| | 0 |
| | 0 |
| | — |
|
| Total sales | 2,093,601 |
| | 142,500 |
| | 238,356 |
| | 12,811 |
| | 0 |
| | 2,487,268 |
|
| | | | | | | | | | | | |
| Segment operating income (loss) | 108,697 |
| | 26,124 |
| | (683 | ) | | 5,883 |
| | — |
| | 140,021 |
|
| Depreciation and amortization | 511,958 |
| | 10,392 |
| | 46,826 |
| | 1,486 |
| | — |
| | 570,662 |
|
| |
| (1) | Operations previously reported within the H&P Technologies reportable segment are now managed and presented within the North America Solutions reportable segment. |
The following table 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, | | | | | | | |
| | 2018 | | 2017 | | 2016 | Year Ended September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 | | 2018 |
Segment operating income (loss) | | $ | 148,349 | | $ | (87,352) | | $ | 68,200 | $ | (544,389 | ) | | $ | 109,233 |
| | $ | 140,021 |
|
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 | | 46,775 |
| | 39,691 |
| | 22,660 |
|
| Corporate selling, general and administrative costs, corporate depreciation and corporate restructuring charges | | (122,573 | ) | | (128,342 | ) | | (129,717 | ) |
| Operating income (loss) from continuing operations | | (620,187 | ) | | 20,582 |
| | 32,964 |
|
Other income (expense) | | | | | | | | | | | | | | |
Interest and dividend income | | | 8,017 | | | 5,915 | | | 3,166 | 7,304 |
| | 9,468 |
| | 8,017 |
|
Interest expense | | | (24,265) | | | (19,747) | | | (22,913) | (24,474 | ) | | (25,188 | ) | | (24,265 | ) |
Gain (loss) on investment securities | | | 1 | | | — | | | (25,989) | (8,720 | ) | | (54,488 | ) | | 1 |
|
| Gain on sale of subsidiary | | 14,963 |
| | 0 |
| | 0 |
|
Other | | | 486 | | | 1,775 | | | (965) | (5,384 | ) | | (1,596 | ) | | (876 | ) |
Total unallocated amounts | | | (15,761) | | | (12,057) | | | (46,701) | (16,311 | ) | | (71,804 | ) | | (17,123 | ) |
Income (loss) from continuing operations before income taxes | | $ | 15,841 | | $ | (184,598) | | $ | (72,667) | $ | (636,498 | ) | | $ | (51,222 | ) | | $ | 15,841 |
|
The following table reconciles segment total assets to total assets as reported on the Consolidated Balance Sheets:
|
| | | | | | | |
| | Year Ended September 30, |
| (in thousands) | 2020 | | 2019 |
Total assets (1) | | | |
North America Solutions (2) | $ | 3,812,718 |
| | $ | 5,284,141 |
|
| Offshore Gulf of Mexico | 93,501 |
| | 102,442 |
|
| International Solutions | 181,181 |
| | 217,094 |
|
| Other | 22,144 |
| | 32,532 |
|
| | 4,109,544 |
| | 5,636,209 |
|
| Investments and corporate operations | 720,077 |
| | 203,306 |
|
| Total assets from continuing operations | 4,829,621 |
| | 5,839,515 |
|
| Discontinued operations | 0 |
| | 0 |
|
| | $ | 4,829,621 |
| | $ | 5,839,515 |
|
| |
| (1) | Assets by segment exclude investments in subsidiaries and intersegment activity. |
| |
| (2) | Operations previously reported within the H&P Technologies reportable segment are now managed and presented within the North America Solutions reportable segment. |
The following table presents revenues from external customers
and long-lived assets by country based on the location of service provided:
| | | | | | | | | | |
| | Year Ended September 30, | | | | | | | |
| | 2018 | | 2017 | | 2016 | Year Ended September 30, |
| | (in thousands) | |
| (in thousands) | | 2020 | | 2019 | | 2018 |
Operating revenues | | | | | | | | | | | | | | |
United States | | $ | 2,247,400 | | $ | 1,591,769 | | $ | 1,386,786 | $ | 1,626,407 |
| | $ | 2,585,008 |
| | $ | 2,247,400 |
|
Argentina | | | 190,038 | | | 157,257 | | | 159,427 | 84,402 |
| | 165,718 |
| | 190,038 |
|
| Bahrain | | 28,653 |
| | 11,528 |
| | 9,525 |
|
| United Arab Emirates | | 24,716 |
| | 4,728 |
| | 0 |
|
Colombia | | | 38,793 | | | 37,554 | | | 20,488 | 6,414 |
| | 29,757 |
| | 38,793 |
|
Ecuador | | | — | | | 6 | | | 4,948 | |
Other Foreign | | | 11,037 | | | 18,155 | | | 52,583 | 3,335 |
| | 1,751 |
| | 1,512 |
|
Total | | $ | 2,487,268 | | $ | 1,804,741 | | $ | 1,624,232 | $ | 1,773,927 |
| | $ | 2,798,490 |
| | $ | 2,487,268 |
|
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 | |
The following table presents property, plant and equipment by country based on the location of service provided:
|
| | | | | | | |
| | Year Ended September 30, |
| (in thousands) | 2020 | | 2019 |
| Property, plant and equipment, net | | | |
| United States | $ | 3,562,525 |
| | $ | 4,269,405 |
|
| Argentina | 49,419 |
| | 132,321 |
|
| Colombia | 21,740 |
| | 61,757 |
|
| Other Foreign | 12,657 |
| | 38,601 |
|
| Total | $ | 3,646,341 |
| | $ | 4,502,084 |
|
NOTE 17 GUARANTOR AND NON-GUARANTOR FINANCIAL INFORMATIONIn March 2015, Helmerich & Payne International Drilling Co. (“19 RESTRUCTURING CHARGES
Beginning in the
issuer”),third quarter of fiscal year 2020, we implemented cost controls and began evaluating further measures to respond to the combination of weakened commodity prices, uncertainties related to the COVID-19 pandemic, and the resulting market volatility. We restructured our operations to accommodate scale during an industry downturn and to re-organize our operations to align to new marketing and management strategies. We commenced a
100 percent owned subsidiarynumber of
Helmerich & Payne, Inc. (“parent”, “the guarantor”), issued senior unsecured notes with an aggregate principal amountrestructuring efforts as a result of
$500.0 million. The notes are fullythis evaluation, which included, among other things a reduction in our capital allocation plans, changes to our organizational structure, and
unconditionally guaranteed by the parent. No subsidiariesa reduction of
the parent currently guarantee the notes, subject to certain provisions that if any subsidiary guarantees certain other debtstaffing levels. Costs incurred, as of
the issuer or parent, then such subsidiary will provide a guarantee of the obligation under the notes.InSeptember 30, 2020, in connection with the notes, werestructuring are providingcomprised of one-time severance benefits to employees who were voluntarily or involuntarily terminated, benefits related to forfeitures and costs related to modification of stock-based compensation awards.
The following table summarizes the Company's restructuring charges incurred during the fiscal year ended September 30, 2020:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands) | 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 |
|
The following condensed consolidating financial information in accordance withtable summarizes 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 informationCompany's accrual for restructuring charges for the issuer, Helmerich & Payne International Drilling Co.,fiscal year ended September 30, 2020:
|
| | | |
| (in thousands) | Employee Termination Benefits |
| Accrued restructuring charges at September 30, 2019 | $ | 0 |
|
| Charges | 19,530 |
|
| Cash payments | (18,979 | ) |
| Accrued restructuring charges at September 30, 2020 | $ | 551 |
|
These expenses are recorded within restructuring charges on our Consolidated Statements of Operations for the fiscal year ended September 30, 2020 and
parent, guarantor, Helmerich & Payne, Inc.the related liability is
shown in the tables below.recorded within accounts payable on our Consolidated Balance Sheets at September 30, 2020. 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 1820 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 |
|
| | | | | | | | | | | | | | | | | | | |
| | Fiscal Year 2020 Quarters Ended |
| (in thousands, except per share amounts) | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total (1) |
| Operating revenues | $ | 614,657 |
| | $ | 633,639 |
| | $ | 317,364 |
| | $ | 208,267 |
| | $ | 1,773,927 |
|
| Operating income (loss) | 31,368 |
| | (518,541 | ) | | (57,584 | ) | | (75,430 | ) | | (620,187 | ) |
| Income (loss) from continuing operations | 30,729 |
| | (420,468 | ) | | (46,007 | ) | | (60,646 | ) | | (496,392 | ) |
| Net income (loss) | 30,605 |
| | (420,540 | ) | | (45,599 | ) | | (58,963 | ) | | (494,497 | ) |
| Basic earnings per common share: | | | | | | | | | |
| Income (loss) from continuing operations | 0.27 |
| | (3.88 | ) | | (0.43 | ) | | (0.57 | ) | | (4.62 | ) |
| Net income (loss) | 0.27 |
| | (3.88 | ) | | (0.43 | ) | | (0.55 | ) | | (4.60 | ) |
| Diluted earnings per common share: | | | | | | | | | |
| Income (loss) from continuing operations | 0.27 |
| | (3.88 | ) | | (0.43 | ) | | (0.57 | ) | | (4.62 | ) |
| Net income (loss) | 0.27 |
| | (3.88 | ) | | (0.43 | ) | | (0.55 | ) | | (4.60 | ) |
| |
| (1) | | The sum of earnings per share for the four quarters may not equal the total earnings per share for the fiscal year due to changes in the average number of common shares outstanding. |
In the first quarter of fiscal year 2018, net income includes a tax benefit of approximately $502.1 million, or $4.59 per share on a diluted basis, an after-tax gain from the sale of assets of $4.2 million, or $0.04 per share on a diluted basis. In the second quarter of fiscal year 2018, net loss includes an after-tax gain from the sale of assets of $3.8 million, or $0.04 per share on a diluted basis. In the third quarter of fiscal year 2018, net loss includes an after-tax gain from the sale of assets of $3.1 million, or $0.02 per share on a diluted basis. In the fourth quarter of fiscal year 2018, net loss includes an after-tax gain from the sale of assets of $5.5 million, or $0.05 per share on a diluted basis and an after-tax loss from asset impairments of approximately $17.2 million, or $0.16 per share on a diluted basis.
| | | | | | | | | | | | | | | |
2017 | | 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) |
|
| | | | | | | | | | | |
| | Fiscal Year 2020 Quarters Ended |
| (in thousands, except per share amounts) | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| Included within net income (loss): | | | | | | | |
| Gain from the sale of assets, after tax | 3,314 |
| | 7,985 |
| | 3,254 |
| | 21,674 |
|
| Asset impairment charges, after tax | 0 |
| | (436,225 | ) | | 0 |
| | 0 |
|
| Restructuring charges, after tax | 0 |
| | 0 |
| | (12,001 | ) | | (428 | ) |
| | | | | | | | |
| Effect on diluted earnings per common share: | | | | | | | |
| Gain from the sale of assets, after tax | 0.03 |
| | 0.07 |
| | 0.03 |
| | 0.2 |
|
| Asset impairment charges, after tax | 0 |
| | (4.02 | ) | | 0 |
| | 0 |
|
| Restructuring charges, after tax | 0 |
| | 0 |
| | (0.11 | ) | | 0 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Fiscal Year 2019 Quarters Ended |
| (in thousands, except per share amounts) | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total (1) |
| Operating revenues | $ | 740,598 |
| | $ | 720,868 |
| | $ | 687,974 |
| | $ | 649,050 |
| | $ | 2,798,490 |
|
| Operating income (loss) | 54,289 |
| | 95,146 |
| | (167,874 | ) | | 39,021 |
| | 20,582 |
|
| Income (loss) from continuing operations | 8,364 |
| | 71,857 |
| | (154,621 | ) | | 41,890 |
| | (32,510 | ) |
| Net income (loss) | 18,959 |
| | 60,891 |
| | (154,683 | ) | | 41,177 |
| | (33,656 | ) |
| Basic earnings per common share: | | | | | | | | | |
| Income (loss) from continuing operations | 0.07 |
| | 0.65 |
| | (1.42 | ) | | 0.38 |
| | (0.33 | ) |
| Net income (loss) | 0.17 |
| | 0.55 |
| | (1.42 | ) | | 0.37 |
| | (0.34 | ) |
| Diluted earnings per common share: | | | | | | | | | |
| Income (loss) from continuing operations | 0.07 |
| | 0.65 |
| | (1.42 | ) | | 0.38 |
| | (0.33 | ) |
| Net income (loss) | 0.17 |
| | 0.55 |
| | (1.42 | ) | | 0.37 |
| | (0.34 | ) |
| |
| (1) | | The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding. |
|
| | | | | | | | | | | |
| | Fiscal Year 2019 Quarters Ended |
| (in thousands, except per share amounts) | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| Included within net income (loss): | | | | | | | |
| Gain from the sale of assets, after tax | 4,268 |
| | 8,886 |
| | 7,718 |
| | 9,752 |
|
| Asset impairment charges, after tax | 0 |
| | 0 |
| | (173,227 | ) | | 0 |
|
| | | | | | | | |
| Effect on diluted earnings per common share: | | | | | | | |
| Gain from the sale of assets, after tax | 0.04 |
| | 0.08 |
| | 0.07 |
| | 0.09 |
|
| Asset impairment charges, after tax | 0 |
| | 0 |
| | (1.58 | ) | | 0 |
|
In the first quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $0.6 million, or $0.01 per share on a diluted basis. In the second quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $10.1 million, or $0.09 per share on a diluted basis. In the third quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $1.3 million, or $0.01 per share on a diluted basis. In the fourth quarter of fiscal year 2017, net loss includes an after-tax gain from the sale of assets of $2.3 million, or $0.02 per share on a diluted basis.
NOTE 19 SUBSEQUENT EVENTS
On November 13, 2018, we entered into the 2018 Credit Facility, which will mature on November 13, 2023. The 2018 Credit Facility has $750 million in aggregate availability with a maximum of $75 million available for use as letters of credit. The 2018 Credit Facility also permits aggregate commitments under the facility to be increased by $300 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The 2018 Credit Facility is currently guaranteed by our wholly-owned direct subsidiary, HPIDC, which guarantee is subject to release following certain events set forth in the 2018 Credit Facility. The borrowings under the 2018 Credit Facility accrue interest at a spread over either the London Interbank Offered Rate (LIBOR) or the Base Rate. We also pay a commitment fee based on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined based on the debt rating for senior unsecured debt of the Company or HPIDC as determined by Moody’s and S&P. The spread over LIBOR ranges from 0.875 percent to 1.500 percent per annum and commitment fees range from 0.075 percent to 0.200 percent per annum. Based on the unsecured debt rating of HPIDC on September 30, 2018, the
spread over LIBOR would have been 1.125 percent and commitment fees would have been 0.125 percent. There is a financial covenant in the 2018 Credit Facility that requires us to maintain a total debt to total capitalization ratio of less than 50 percent. The 2018 Credit Facility contains additional terms, conditions, restrictions and covenants that we believe are usual and customary in unsecured debt arrangements for companies of similar size and credit quality, including a limitation that priority debt (as defined in the credit agreement) may not exceed 17.5 percent of the net worth of the Company. As of the closing, there were no borrowings, but there were three letters of credit outstanding in the amount of $38.0 million, and we had $712.0 million available to borrow under the 2018 Credit Facility.
In connection with entering into the 2018 Credit Facility, we terminated our $300 million unsecured credit facility under the credit agreement dated as of July 13, 2016 by and among HPIDC, as borrower, the Company, as guarantor, Wells Fargo, National Association, as administrative agent, and the lenders party thereto.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
| a)
|
| Item 9A. | CONTROLS AND PROCEDURES |
| |
| a) | Evaluation of Disclosure Controls and Procedures. |
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of the end of the period covered by this report have been designed and are effective at the reasonable assurance level so that the information required to be disclosed by us in our periodic SEC filings, is recorded, processed, summarized and reported within the time periods specific in the SEC’s rules, regulations, and forms and is communicated to management. We believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.
Our assessment of our system of internal controls included the consideration of a high proportion of our control owners and control performers working remotely due to Federal and State social distancing guidelines.
| |
| b) | | Management’s Report on Internal Control over Financial Reporting. |
A copy of our Management’s Report on Internal Control over Financial Reporting is included in Item 8 of this Form 10-K.
| |
| c) | | Attestation Report of the Independent Registered Public Accounting Firm. |
A copy of the report of Ernst & Young LLP, our independent registered public accounting firm, is included in Item 8 of this Form 10-K.
| |
| d) | | Changes in Internal Control Over Financial Reporting. |
None.
None.
***
Item 9B. | |
| Item 9B. | OTHER INFORMATION |
None.
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,” “Executive
Officers of the Company” in Part IOfficers” and
“Section“Delinquent Section 16(a)
Beneficial Ownership Reporting Compliance”Reports” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March
5, 2019,2, 2021, to be filed with the SEC not later than 120 days after September 30,
2018.2020.
We have adopted a Code of Ethics for Principal Executive Officer and Senior Financial Officers. The text of this code is located on our website under “Corporate Governance.” Our Internet address is www.hpinc.com. We intend to disclose any amendments to or waivers from this code on our website.
Item 11. EXECUTIVE COMPENSATION
| |
| Item 11. | EXECUTIVE COMPENSATION |
The information required by this item regarding executive compensation, as well as director compensation and compensation committee interlocks and insider participation, is incorporated herein by reference to the material beginning with the caption “Executive Compensation Discussion and Analysis” and ending with the caption “Potential Payments Upon Change‑in‑Change‑in‑Control”, as well as under the captions “Director Compensation in Fiscal 2018”Year 2020” and “Corporate Governance—Compensation Committee Interlocks and Insider Participation” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019,2, 2021, to be filed with the SEC not later than 120 days after September 30, 2018.2020.
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, 2019,2, 2021, to be filed with the SEC not later than 120 days after September 30, 2018.2020.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated herein by reference to the material under the captions “Corporate Governance—Transactions With Related Persons, Promoters and Certain Control Persons” and “Corporate Governance—Director Independence” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March 5, 2019,2, 2021, to be filed with the SEC not later than 120 days after September 30, 2018.2020.
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated herein by reference to the material under the caption “Proposal 2—Ratification of Appointment of Independent Auditors—Audit Fees” in our definitive Proxy Statement for the Annual Meeting of Stockholders to be held March
5, 2019,2, 2021, to be filed with the SEC not later than 120 days after September 30,
2018.2020.Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES1. Financial Statements: Our consolidated financial statements, together with the notes thereto and the report of Ernst & Young LLP dated November 16, 2018, are listed below and included in Item 8—“Financial Statements and Supplementary Data” of this Form 10‑K.
| |
| 1. | Financial Statements: Our consolidated financial statements, together with the notes thereto and the report of Ernst & Young LLP dated November 20, 2020, are listed below and included in Item 8— “Financial Statements and Supplementary Data” of this Form 10‑K. |
2. Financial Statement Schedules: All schedules are omitted because they are not applicable or required or because the required information is contained in the financial statements or included in the notes thereto.
3. Exhibits. The following documents are included as exhibits to this Form 10‑K. Exhibits incorporated by reference are duly noted as such.
| |
| 2. | Financial Statement Schedules: All schedules are omitted because they are not applicable or required or because the required information is contained in the financial statements or included in the notes thereto. |
| |
| 3. | Exhibits: The following documents are included as exhibits to this Form 10‑K. Exhibits incorporated by reference are duly noted as such. |
|
| |
| 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 16. FORM 10-K SUMMARYNone.
(This page has been left blank intentionally.)
SIGNATURES
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 20, 2020 | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated:
Signature
| | Title
| | Date
|
| | | | |
Signature | | Title | | Date |
| | | | |
| /s/ John W. Lindsay | | Director, President and Chief Executive | | November 16, 2018 20, 2020 |
John W. Lindsay | | Officer (Principal Executive Officer) | | |
| | | | |
/s/ Mark W. Smith | | Senior Vice President and Chief Financial Officer | | November 16, 2018 20, 2020 |
Mark W. Smith | | (Principal Financial OfficerOfficer) | | |
| | | | |
| /s/ Sara M. Momper | | Vice President and Chief Accounting Officer | | November 20, 2020 |
| Sara M. Momper | | (Principal Accounting Officer) | | |
| | | | |
/s/ Hans Helmerich | | Director and Chairman of the Board | | November 16, 2018 20, 2020 |
Hans Helmerich | | | | |
| | | | |
/s/ DelanyDelaney Bellinger | | Director | | November 16, 2018 20, 2020 |
DelanyDelaney Bellinger
| | | | |
| | | | |
/s/ Kevin G. Cramton | | Director | | November 16, 2018 20, 2020 |
Kevin G. Cramton | | | | |
| | | | |
/s/ Randy A. Foutch | | Director | | November 16, 2018 20, 2020 |
Randy A. Foutch | | | | |
| | | | |
/s/ Paula Marshall
| | Director
| | November 16, 2018
|
Paula Marshall
| | | | |
| | | | |
/s/ Jose R. Mas | | Director | | November 16, 2018 20, 2020 |
Jose R. Mas | | | | |
| | | | |
/s/ Thomas A. Petrie | | Director | | November 16, 2018 20, 2020 |
Thomas A. Petrie | | | | |
| | | | |
/s/ Donald F. Robillard, Jr. | | Director | | November 16, 2018 20, 2020 |
Donald F. Robillard, Jr. | | | | |
| | | | |
/s/ Edward B. Rust, Jr. | | Director | | November 16, 2018 20, 2020 |
Edward B. Rust, Jr. | | | | |
| | | | |
/s/ Mary M. VanDeWeghe | | Director | | November 20, 2020 |
| Mary M. VanDeWeghe | | | | |
| | | | |
| /s/ John D. Zeglis | | Director | | November 16, 2018 20, 2020 |
John D. Zeglis | | | | |
