What changed in this filing

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Item 5. Market for Registrant’s Common Equity

2020-11-20 compared with 2019-11-15 · 19 added, 476 removed, 40 unchanged (93% of the section changed)

4 unchanged sentences

Payment of future dividends will depend on earnings and other factors.

Issuer Purchases of Equity Securities

The table below sets forth the information with respect to our repurchases of common shares during the three-month period ended September 30, 2019 (in thousands except per share amounts):

Total Number of Shares Purchased (1)

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs

Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs

July 1 - July 31

August 1 - August 31

September 1 - September 30

The Company has an evergreen authorization from the Board of Directors for the repurchase of up to four million common shares in any fiscal year.

The repurchases may be made using our cash and cash equivalents or other available sources.

Shares of stock repurchased pursuant to such authorization are held as treasury shares.

Following the repurchase in August 2019 disclosed in the table, the Company could repurchase up to three million common shares through the year ended September 30, 2019.

Performance Graph

5 unchanged sentences

S&P 500 Index

S&P 1500 Oil & Gas Drilling Index

Dow Jones U.S.

Select Oil Equipment & Services Index

PHLX Oil Service Index

1 unchanged sentence

Stock Portfolio

Information required by this item regarding our marketable securities may be found in, and is incorporated by reference to, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Stock Portfolio Held” included in this Form 10 ‑ K.

Information required by this item regarding our marketable securities may be found in, and is incorporated by reference to, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Investing Activities — Marketable Securities” included in this Form 10‑K.

SELECTED FINANCIAL DATA

7 unchanged sentences

Income (loss) from continuing operations

Loss from discontinued operations

Income (loss) from discontinued operations

Net income (loss)

1 unchanged sentence

Basic earnings (loss) per share from continuing operations

Basic loss per share from discontinued operations

Basic earnings (loss) per share from discontinued operations

Basic earnings (loss) per share

Diluted earnings (loss) per share from continuing operations

Diluted loss per share from discontinued operations

Diluted earnings (loss) per share from discontinued operations

Diluted earnings (loss) per share

1 unchanged sentence

Balance Sheet Data

Cash, cash equivalents and short-term investments

Property, plant and equipment, net

Total assets (1)

Long term debt, net

Total debt (2)

Total shareholders' equity

Debt to capital ratio (3)

Net debt to net capital ratio (4)

Net working capital (5)

Adjusted for ASU No.

2017-07, adopted in fiscal year 2019.

Refer to Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties for further details.

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.

The debt to capital ratio is calculated by dividing total debt by total capitalization (total debt plus shareholders’ equity).

Total debt excludes unamortized discount and debt issuance cost.

Refer to Note 8—Debt .

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.

Net working capital is calculated as current assets, excluding cash and short-term investments, less current liabilities, excluding short–term debt or the current portion of long–term debt.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Part I of this Form 10 ‑ K as well as the Consolidated Financial Statements and related notes thereto included in Item 8— “Financial Statements and Supplementary Data” of this Form 10 ‑ K.

Our future operating results may be affected by various trends and factors which are beyond our control.

Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report under “Cautionary Note regarding Forward-Looking Statements” and Item 1A-- “Risk Factors.” Accordingly, past results and trends should not be used by investors to anticipate future results or trends.

Executive Summary

Helmerich & Payne, Inc.

provides performance-driven drilling services and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies.

As of September 30, 2019 , our drilling rig fleet included a total of 338 drilling rigs.

Our contract drilling services segments consist of the U.S.

Land segment with 299 rigs, the Offshore segment with 8 offshore platform rigs and the International Land segment with 31 rigs as of September 30, 2019 .

At the close of fiscal year 2019 , we had 218 contracted rigs, of which 137 were under a fixed term contract and 81 were working well-to-well, compared to 259 contracted rigs at the same time during the prior year.

land drilling industry recovered from an all-time low of approximately 380 active rigs in the summer of 2016 to over 1,000 rigs in early fiscal 2019, we led the way in reactivating rigs in the United States and gained significant market share in the process.

We believe that our success during this time frame is validation of the capabilities of our land drilling fleet and our decisions during the downturn to prepare for an eventual improvement in the business, and our ability to deliver best-in-class field performance and customer satisfaction.

Our long-term strategy remains focused on innovation, technology, safety, operational excellence and reliability.

As we move forward, we believe that our advanced uniform rig fleet, financial strength, long term contract backlog and strong customer and employee base position us very well to take advantage of future opportunities.

Market Outlook

Our revenues are derived from the capital expenditures of companies involved in the exploration, development and production of crude oil and natural gas (“E&Ps”).

At the core, the level of capital expenditures is dictated by current and expected future prices of crude oil and natural gas, which are determined by various supply and demand factors.

Both commodities have historically been, and we expect them to continue to be, cyclical and highly volatile.

With respect to U.S.

Land Drilling, the resurgence of oil and natural gas production coming from the United States brought about by unconventional shale drilling for oil has significantly impacted the supply of oil and natural gas.

The advent of unconventional drilling in the United States began in early 2009 and continues to evolve as E&Ps drill longer lateral wells with tighter well spacing.

During this time, we designed, built and delivered new technology AC drive rigs (FlexRigs) to the market, substantially growing our fleet.

The pace of progress of unconventional drilling over the years has been cyclical and volatile, dictated by crude oil and natural gas price fluctuations, which at times have proven to be dramatic.

Throughout this time, the length of the lateral section of wells drilled in the U.S.

has continued to grow.

The progression of longer lateral wells has required many of the industry’s rigs to be upgraded to certain specifications in order to meet the technical challenges of drilling longer lateral wells.

The upgraded rigs meeting those specifications are commonly referred to in the industry as super-spec rigs and have the following specific characteristics:

AC Drive, minimum of 1,500 horsepower drawworks, minimum of 750,000 lbs.

hookload rating, 7,500 psi mud circulating system, and multiple-well pad capability.

Beginning in early calendar 2018, we saw the demand for super-spec rigs increase and we benefited by gaining market share as a result of having the largest super-spec fleet in the industry and having the largest number of rigs that could readily and economically be upgraded to the super-spec classification.

Heading into calendar year 2019, many customers established their respective budgets based on crude oil price expectations of between $50 and $55 per barrel, which in hindsight proved reasonable given the average crude oil price of approximately $57 per barrel through September 30, 2019.

However, exiting calendar year 2018, industry activity levels were too high relative to recently established 2019 E&P capital budgets.

Consequently, during the first six months of calendar year 2019, the industry experienced a gradual decline in activity, with the rig count falling by approximately 115 rigs (11%).

Despite this decline, many of our customers had spent more than 50% of their planned capital expenditures through midyear.

This resulted in a more rapid decline in activity with the rig count falling roughly 110 rigs (11%) in the subsequent, shorter three-month period.

As a result, E&P spending for the remaining six months of 2019 became more austere due to our customers' emphasis on disciplined capital spending.

Activity for the remainder of calendar year 2019 currently appears subdued and could be further negatively impacted by seasonal holidays and weather, as well as the conditions in the general economy.

Given current crude oil price levels in the mid-$50 per barrel range, we anticipate our customers will set their 2020 capital budgets on that basis of between $50 and $55 per barrel, but that basis could change depending upon where crude oil prices move over the next several months, the time during which most customers will set their capital budgets.

We expect our customers to remain capital disciplined, which will ultimately impact their level of spending during 2020.

During fiscal year 2019, we upgraded 21 FlexRigs and converted 5 FlexRigs to super-spec capacity, bringing our total super-spec FlexRig fleet to 233 rigs.

At September 30, 2019, we had 55 idle super-spec FlexRigs, and we do not anticipate upgrading additional FlexRigs to super-spec capacity.

Some customers may have a requirement or a preference for walking multiple-well pad capability, and we would convert certain idle super-spec skidding rigs to walking for multi-year term contracts.

The lack of a sizable commitment to super-spec upgrades in fiscal year 2020 is the main driver of the decrease in our capital expenditure budget, which is initially set at between $275 million and $300 million for fiscal year 2020, down from $458.4 million in fiscal year 2019.

In our H&P Technologies segment, we expect further market penetration of our digital technology offerings as customers continue to appreciate the economic benefits of deploying these technologies in their well programs.

We continue to see the expansion for more pronounced industry adoption in a measured pace, though realizing the inherent challenges in adopting new and disruptive technologies in a flat oil price environment.

Similar to our other segments, H&P Technologies shares the same underlying drivers in terms of crude oil prices and E&Ps' capital expenditures, but is ultimately tied to rig count activity, both the Company's and the industry's.

In our International Land Drilling segment, we believe that our market leading position in the Neuquén basin of Argentina provides opportunities for us to either deploy additional AC rigs from the United States or upgrade rigs in country to super-spec.

However, a recent political regime change in the country may impact the current contracting environment and possibly delay such opportunities further into calendar year 2020 or beyond.

We continue to believe that our international land operations are a potential area of growth over the next several years, including for idle U.S.

AC rigs, but acknowledge that such growth may be more sporadic than what we have experienced in the U.S.

To that end, we have recently signed letters of intent in the U.A.E to put two FlexRigs back to work starting in fiscal year 2020.

Additionally, we have also recently signed two letters of intent to put two more rigs back to work, one in Bahrain and one in Colombia.

As of September 30, 2019 , our Offshore Drilling operations have reported relatively stable utilization and cash flows.

We expect a relatively similar operating environment during fiscal year 2020.

Recent Developments

In December 2018, we settled an offer to exchange (the “Exchange Offer”) any and all outstanding 4.65 percent unsecured senior notes due 2025 (the “HPIDC 2025 Notes”) issued by Helmerich & Payne International Drilling Co., our wholly-owned direct subsidiary (“HPIDC”), for (i) up to $500.0 million aggregate principal amount of new 4.65 percent unsecured senior notes due 2025 of the Company (the “Company 2025 Notes”), with registration rights, and (ii) cash.

Concurrently with the Exchange Offer, we solicited consents to adopt certain proposed amendments to the indenture governing the HPIDC 2025 Notes.

The HPIDC 2025 Notes tendered had a principal amount of $487.1 million which represents 97.42 percent of the HPIDC 2025 Notes outstanding prior to the Exchange Offer.

See “—Liquidity and Capital Resources” below.

In March 2019, we settled a registered exchange offer (the “Registered Exchange Offer”) to exchange the Company 2025 Notes for new SEC-registered notes that are substantially identical to the terms of the Company 2025 Notes, except that the offer and issuance of the new notes have been registered under the Securities Act and certain transfer restrictions, registration rights and additional interest provisions relating to the Company 2025 Notes do not apply to the new notes.

Approximately 99.99% of the Company 2025 Notes were exchanged in the Registered Exchange Offer.

In September 2019, we redeemed the remaining approximately $12.9 million in aggregate principal amount of HPIDC 2025 Notes for approximately $14.6 million, including accrued interest and a prepayment premium (the “HPIDC 2025 Notes Redemption”).

Simultaneously with the HPIDC 2025 Notes Redemption, HPIDC was released as a guarantor under the Company 2025 Notes and the 2018 Credit Facility (as defined herein).

As a result of such release, H&P is the only obligor under the Company 2025 Notes and the 2018 Credit Facility.

On November 13, 2019, we entered into the first amendment to our 2018 Credit Facility by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “2018 Credit Facility Amendment”).

Amongst other things, the 2018 Credit Facility Amendment (i) extended the maturity date of the 2018 Credit Facility by one year to November 13, 2024, (ii) deleted certain negative covenants and (iii) refreshed the number of permissible extensions of the maturity date that require only the consent of extending lenders.

Business Segments

Effective October 1, 2018 and during the fourth quarter of fiscal year 2019, we implemented organizational changes, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources.

As a result of the reorganization of our operations during the first quarter of fiscal year 2019, we identified a new reportable segment, H&P Technologies.

This reportable segment is used to drive development of advanced digital drilling technologies and directional drilling automation solutions, designed to improve safety, reliability, drilling consistency, and well performance economics for our customers.

Subsequent to the reorganizations, all of our technology companies are included within the H&P Technologies

reportable segment.

Combining drilling technology expertise within this new segment creates a holistic solution-based approach that includes products, services and capabilities.

This approach provides performance-driven drilling services with greater levels of accuracy, consistency, optimization and a reduction of human error to create higher quality wellbores.

This technology addresses our customers' unique challenges, resulting in less tortuosity and reducing positional uncertainty in the directional drilling process.

Another key benefit is that many components of our digital technology, including MOTIVE bit guidance and MagVAR TM survey correction, can be used on any rig, regardless of the drilling or service provider, allowing our customers to benefit from these technologies on all rigs.

During fiscal year 2019, H&P Technologies released AutoSlide SM , which integrates the MOTIVE bit guidance system and several FlexApps to function within the FlexRig operating system and fully automates the control of mud motors while sliding during the vertical, the curve, and the lateral hole sections during horizontal drilling operations.

Similar to our approach with FlexApps, H&P Technologies plans to market AutoSlide across the FlexRig TM fleet initially at a price point that improves cost-efficiency for our customers.

Subsequently, there are also plans to integrate the software to make this offering compatible with non–H&P rigs for those customers with multi-vendor rig fleets.

Currently, our AutoSlide application is commercially available in four regions including the Midland, Bakken, Eagle Ford and MidCon basins and we will be expanding into additional basins in the coming months.

The adoption of our FlexApps continues as customers see the value of these technologies as demonstrated by their requests to use them on both H&P and non-H&P rigs.

Our preparation to respond to this type of demand includes migrating our FlexApp offerings into our H&P Technologies business segment, which occurred in the fourth quarter of fiscal year 2019 and developing rig-neutral solutions to operate the software on non-H&P rigs.

During the third quarter of fiscal year 2019, the Company established an incubator program for new research and development projects, the results of which have been included in "Other" within our segment disclosures.

Business Combinations

In November 2018, we announced our acquisition of Angus Jamieson Consulting (“AJC”), a software-based training and consultancy company based in Inverness, Scotland.

AJC is recognized as an industry leader in wellbore positioning and provides software and in-depth training for clients.

The skills and talents of AJC will accelerate capabilities to deliver future, value-driven automation in H&P Technologies.

In August 2019, we completed an acquisition of an unaffiliated company, DrillScan Energy SAS and its subsidiaries ("DrillScan"), a leading provider of proprietary drilling engineering software, well engineering services and training for the oil and gas industry.

DrillScan brings a team of highly respected industry experts who will contribute to research, development and innovation efforts to advance H&P’s digital technology portfolio.

DrillScan will maintain its headquarters in France and its other international locations.

DrillScan will operate as part of the H&P Technologies reportable segment.

During the third quarter of fiscal year 2019, the Company's management performed a detailed assessment, considering a number of approaches, to maximize the utilization and enhance the margins of the domestic and international FlexRig4 asset groups.

In June 2019, this assessment concluded that marketing a smaller fleet of these two asset groups would provide the best economic outcome.

As such, the decision was made to downsize the number of domestic and international FlexRig4 drilling rigs, to be marketed to our customers, from 71 rigs to 20 domestic rigs and from 10 rigs to 8 international rigs and utilize the major interchangeable components of the decommissioned drilling rigs within these asset groups as capital spares for all of our remaining rig fleet.

This has reduced the aggregate net book values of the FlexRig4 asset groups as of June 30, 2019 from $317.8 million to $107.5 million for domestic rigs and from $55.7 million to $47.8 million for international rigs.

Following the downsizing process, we performed a detailed study to optimize the quantities of capital spares and drilling support equipment required to support the future operations of our rig fleet going forward.

These decisions and analysis resulted in a write down of excess capital spares and drilling support equipment, which had an aggregate net book value of $235.3 million, to their estimated proceeds to ultimately be received on sale or disposal based on our historical experience with sales and disposals of similar assets, resulting in an impairment of $224.3 million ($195.0 million, net of tax, or $1.78 per diluted share), which was recorded in our Consolidated Statement of Operations for the year ended September 30, 2019 .

Of the $224.3 million total impairment charge recorded, $216.9 million ($188.6 million, net of tax, or $1.72 per diluted share) and $7.4 million ($6.4 million, net of tax, or $0.06 per diluted share) was recorded in our U.S.

Land and International Land segment, respectively, during the year ended September 30, 2019 .

The significant assumptions in the valuation are classified as Level 2 inputs by Accounting Standards Codification ("ASC") Topic 820, Fair Value Measurement.

Due to the downsizing of our domestic and international FlexRig4 asset groups, at June 30, 2019, we performed impairment testing on these two asset groups.

We concluded that the net book values of the asset groups are recoverable through estimated undiscounted cash flows with a surplus.

The most significant assumptions used in our undiscounted cash flow model include:

timing on awards of future drilling contracts, operating dayrates, operating costs, rig reactivation costs, drilling rig utilization, estimated remaining useful life, and net proceeds received upon future sale/disposition.

The assumptions are consistent with the Company's internal forecasts for future years.

Although we believe the assumptions used in our analysis are reasonable and appropriate and the probability-weighted average of expected future undiscounted net cash flows exceed the net book value for each of the domestic and international FlexRig4 asset groups as of June 30, 2019, different assumptions and estimates could materially impact the analysis and our resulting conclusion.

Results of Operations for the Fiscal Years Ended September 30, 2019 and 2018

Consolidated Results of Operations

All per share amounts included in the Results of Operations discussion are stated on a diluted basis.

Except as specifically discussed, the following results of operations pertain only to our continuing operations.

Net Income (Loss) Our net loss for fiscal year 2019 was $32.5 million ( $0.33 loss per share), compared with net income of $493.0 million ( $4.49 earnings per share) for fiscal year 2018 .

Net loss in fiscal year 2019 and net income in fiscal year 2018 include after-tax income from early termination revenue associated with drilling contracts terminated prior to the expiration of their fixed term of $7.1 million ( $0.07 per diluted share) and $12.6 million ( $0.12 per diluted share), respectively.

Net loss in fiscal year 2019 and net income in fiscal year 2018 include after ‑ tax gains from the sale of assets of $30.6 million ( $0.28 per diluted share) and $16.7 million ( $0.15 per diluted share), respectively.

Additionally, net loss in fiscal year 2019 and net income in fiscal year 2018 include after-tax income from a tax benefit of $18.7 million ( $0.17 per diluted share) and a tax benefit of $477.2 million ( $4.36 per diluted share), respectively.

Revenue Consolidated operating revenues were $2.8 billion in fiscal year 2019 and $2.5 billion in fiscal year 2018 , including early termination revenue of $11.3 million and $17.1 million in each respective fiscal year.

Excluding early termination revenue, operating revenue increased $317.1 million in fiscal year 2019 compared to fiscal year 2018 .

The number of revenue days in our U.S.

Land segment increased by approximately 4.9 percent .

Our activity was primarily driven by the fluctuation in oil prices as the second half of fiscal year 2018 experienced oil prices in the $62 to $77 per barrel range followed by a peak during the first quarter of fiscal year 2019 with prices reaching $71 per barrel.

This period of increased pricing was followed by nine months of decreasing oil prices ranging from $51 to $64 per barrel.

Asset Impairment Management monitors industry market conditions impacting its long‑lived assets, intangible assets and goodwill.

When required, an impairment analysis is performed to determine if any impairment exists.

During the year ended September 30, 2019 , and mainly driven by the downsizing of our fleet of FlexRig4 drilling rigs, we wrote down excess capital spares and drilling support equipment, which had an aggregate net book value of $235.3 million , and as a result, an impairment charge of $224.3 million ($195.0 million, net of tax, or $1.78 per diluted share) was recorded in our Consolidated Statement of Operations.

During the fourth quarter of fiscal year 2018, and after ceasing operations in Ecuador, we entered into a sales negotiation with respect to the six conventional rigs present in the country, pursuant to which the rigs, together with associated equipment and machinery, were sold to a third party to be recycled.

As a result, we recorded a non-cash impairment charge of $9.2 million ( $7.0 million , net of tax, or $0.06 per diluted share).

The remaining rig within the same asset group, not to be disposed of, was written down resulting in an additional impairment charge of $1.4 million ( $1.0 million , net of tax, or $0.01 per diluted share).

Additionally, during the fourth quarter of fiscal year 2018, management committed to a plan to auction several previously decommissioned rigs during fiscal year 2019.

As a result, we wrote them down to their estimated fair values and we recorded a non-cash impairment charge of $5.7 million ( $4.2 million , net of tax, or $0.04 per diluted share).

Furthermore, during the fourth quarter of fiscal year 2018, we recorded goodwill and intangible assets impairment losses of $5.6 million ($4.1 million, net of tax, or $0.04 per diluted share) related to the TerraVici technology reporting unit.

The fiscal year 2018 asset impairment charges are included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018.

Interest and Dividend Income Interest and dividend income was $9.5 million and $8.0 million in fiscal years 2019 and 2018 , respectively.

The increase in interest and dividend income in fiscal year 2019 was primarily due to higher earnings on available cash equivalents and short-term investments.

Direct Operating Expenses Direct operating expenses in fiscal year 2019 were $1.8 billion , compared with $1.7 billion in fiscal year 2018 .

The increase in fiscal year 2019 from fiscal year 2018 was primarily attributable to a higher level of activity in fiscal year 2019 .

Selling, General and Administrative Expense Selling, general and administrative expenses totaled $194.4 million in fiscal year 2019 and $199.3 million in fiscal year 2018 .

The $4.9 million decrease is primarily due to lower variable compensation and professional services expenses.

Depreciation and Amortization Depreciation and amortization expense was $562.8 million in fiscal year 2019 and $583.8 million in fiscal year 2018 .

Depreciation and amortization includes amortization of intangible assets of $5.8 million and $5.4 million in fiscal years 2019 and 2018 , respectively, and abandonments of equipment of $11.4 million and $27.7 million in fiscal years 2019 and 2018 , respectively.

In fiscal year 2019 , depreciation expense also includes $4.7 million of accelerated depreciation for components on rigs that are planned for conversion in fiscal year 2020 .

Interest Interest expense, net of amounts capitalized, totaled $25.2 million in fiscal year 2019 and $24.3 million in fiscal year 2018 .

Of the total $25.2 million interest expense incurred in fiscal year 2019, $1.7 million related to the prepayment premium paid for the HPIDC 2025 Notes Redemption in September 2019.

Interest expense is primarily attributable to fixed ‑ rate debt outstanding.

Income Taxes We had an income tax benefit of $18.7 million in fiscal year 2019 compared to an income tax benefit of $477.2 million in fiscal year 2018 .

The effective income tax rate was 36.5 percent in fiscal year 2019 compared to (3,012.3) percent in fiscal year 2018 .

The effective rates differ from the U.S.

federal statutory rate (21.0 percent for fiscal year 2019 and 24.5 percent for fiscal year 2018) due to non-deductible permanent items, state and foreign income taxes, and adjustments to the deferred state income tax rate.

In addition, the effective tax rate for fiscal year 2018 was impacted by income tax adjustments related to the reduction of the federal statutory corporate income tax rate as part of the Tax Reform Act, which was enacted during 2017.

Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities.

Recoverability of any tax assets are evaluated, and necessary allowances are provided.

The carrying values of the net deferred tax assets are based on management’s judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets.

If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future.

See Note 8—Income Taxes to our Consolidated Financial Statements for additional income tax disclosures.

Research and Development During fiscal years 2019 and 2018 , we incurred $27.5 million and $18.2 million , respectively, of research and development expenses.

The increase in expense is primarily related to new initiatives that are conducted through H&P Technologies.

We anticipate research and development expenses to continue during fiscal year 2020 .

Discontinued Operations Expenses incurred within the country of Venezuela are reported as discontinued operations.

In March 2016, the Venezuelan government implemented the previously announced plans for a new foreign currency exchange system.

Our wholly - owned subsidiaries, Helmerich & Payne International Drilling Co.

and Helmerich & Payne de Venezuela, C.A., filed a lawsuit in the United States District Court for the District of Columbia on September 23, 2011 against the Bolivarian Republic of Venezuela, Petroleos de Venezuela, S.A.

and PDVSA Petroleo, S.A.

We are seeking damages for the taking of our Venezuelan drilling business in violation of international law and for breach of contract.

While there exists the possibility of realizing a recovery, we are currently unable to determine the timing or amounts we may receive, if any, or the likelihood of recovery.

Activity within discontinued operations for both fiscal years 2019 and 2018 is primarily a result of the impact of exchange rate fluctuations on remaining in country assets and liabilities.

Land Operations Segment

(in thousands, except operating statistics)

Operating revenues

Direct operating expenses

Selling, general and administrative expense

Research and development

Asset impairment charge

Segment operating income

Operating Statistics (1) :

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of rigs at the end of period

Rig utilization

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out ‑ of ‑ pocket” expenses of $285,614 and $242,617 for fiscal years 2019 and 2018 , respectively.

Fiscal year 2018 has been restated due to the migration of FlexApps from our U.S.

Land segment to our H&P Technologies segment.

Operating Income In fiscal year 2019 , the U.S.

Land segment had operating income of $93.1 million compared to operating income of $148.3 million in fiscal year 2018 .

Included in U.S.

land revenues for fiscal years 2019 and 2018 is approximately $6.4 million and $17.1 million , respectively, from early termination of fixed ‑ term contracts.

Fixed ‑ term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term (except in limited circumstances including sustained unacceptable performance by us).

Revenue Excluding early termination revenue of $78 and $219 per day for fiscal years 2019 and 2018 , respectively, average revenue per day for fiscal year 2019 increased by $2,225 to $25,355 from $23,130 in fiscal year 2018 .

Our activity increased year-over-year due to increased customer demand, resulting in a 4.9 percent increase in revenue days when comparing fiscal year 2019 to fiscal year 2018 .

Direct Operating Expenses Average expense per day, excluding costs associated with a settled lawsuit of $336 per day for fiscal year 2019, increased $536 to $14,688 in fiscal year 2019 compared to fiscal year 2018.

The increase is primarily due to higher pass-through costs, including higher wages for field personnel in some regions and higher rig recommissioning expense during fiscal year 2019.

These factors were partially offset by a decrease in average daily expenses for idle rig expenses.

Asset Impairment Charge During the fiscal year ended September 30, 2019 , and mainly driven by the downsizing of our fleet of FlexRig4 drilling rigs, we wrote down excess capital spares and drilling support equipment and as a result, an impairment charge of $216.9 million ($188.6 million, net of tax, or $1.72 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2019 .

Depreciation Depreciation includes charges for abandoned equipment of $10.6 million and $26.3 million in fiscal years 2019 and 2018 , respectively.

In fiscal year 2019 , depreciation expense also includes $4.7 million of accelerated depreciation for components on rigs that are scheduled for conversion in fiscal year 2020 .

As the drilling markets continued to recover during fiscal year 2017, we began abandoning older rig components as we upgrade rigs to meet customer demands for additional capabilities.

This trend continued in fiscal years 2018 and 2019 , although it has abated to some extent in fiscal year 2019 as our rig upgrade cadence has slowed.

Utilization Rig utilization increased to 67 percent in fiscal year 2019 from 61 percent in fiscal year 2018 .

The total number of available rigs was 299 at September 30, 2019 compared to 350 at September 30, 2018 .

During the third quarter of fiscal year 2019, domestic FlexRig4’s were downsized by 51 rigs.

At September 30, 2019 , 194 out of 299 existing rigs in the U.S.

Land segment were generating revenue.

Of the 194 rigs generating revenue, 128 were under fixed ‑ term contracts, and 66 were working well-to-well.

At November 6, 2019 , the number of existing rigs under fixed ‑ term contracts in the segment was 129 and the number of rigs working in the well-to-well market was 63 .

Offshore Operations Segment

(in thousands, except operating statistics)

Operating revenues

Direct operating expenses

Selling, general and administrative expense

Segment operating income

Operating Statistics (1) :

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of rigs at the end of period

Rig utilization

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out ‑ of ‑ pocket” expenses of $26,433 and $20,279 for fiscal years 2019 and 2018 , respectively.

The operating statistics only include rigs owned by us and exclude offshore platform management and labor service contracts and currency revaluation expense.

Operating Income In fiscal year 2019 , the Offshore segment had operating income of $19.6 million compared to operating income of $26.1 million in fiscal year 2018 .

This decrease is primarily attributable to a rate reduction that took place during the fourth quarter of fiscal year 2018 as a long-term contract expired.

These negative effects were partially offset by activity and cash flow from an additional rig that commenced operations during the third quarter of fiscal year 2018.

Revenue Average rig revenue per day increased 6.1 percent to $37,478 i n fiscal year 2019 compared to fiscal year 2018 .

This was primarily due to rigs returning from a standby rate to a full operating rate during fiscal year 2019.

Direct Operating Expenses Average rig expense per day increased 10.2 percent in fiscal year 2019 compared to fiscal year 2018 .

This increase was primarily attributable to the factors mentioned above.

Utilization At September 30, 2019 and 2018 , six of our eight platform rigs were contracted.

Utilization increased year-over-year as a previously idle rig returned to work in April 2018.

International Land Operations Segment

(in thousands, except operating statistics)

Operating revenues

Direct operating expenses

Selling, general and administrative expense

Asset impairment charge

Segment operating income (loss)

Operating Statistics (1) :

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of rigs at the end of period

Rig utilization

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out ‑ of ‑ pocket” expenses of $10,797 and $11,828 for fiscal years 2019 and 2018 , respectively.

Also excluded are the effects of currency revaluation income and expense.

Operating Income (Loss) The International Land segment had operating income of $5.4 million for fiscal year 2019 compared to operating loss of $0.7 million for fiscal year 2018 .

The increase was primarily driven by lower depreciation and impairment expense in 2019.

Revenue Our activity has decreased primarily in response to lower commodity prices.

We experienced a 4.0 percent decrease in revenue days when comparing fiscal year 2019 to fiscal year 2018 .

The average number of active rigs was 17.6 during fiscal year 2019 compared to 18.2 during fiscal year 2018 .

Direct Operating Expenses Direct operating expenses decreased in fiscal year 2019 to $157.9 million from $177.9 million in fiscal year 2018 , the average rig expense per day decreased by $2,585 , 10.7 percent , as compared to the fiscal year 2018 average rig expense.

This decrease was primarily attributable to the devaluation of the Argentine peso, which decreased our average daily expenses as a result of being translated from local currency to the U.S.

Included in direct operating expenses are foreign currency transaction losses of $8.2 million and $4.0 million for fiscal years 2019 and 2018 , respectively.

Asset Impairment Charge During the fiscal year ended September 30, 2019 , and mainly driven by the downsizing of our fleet of FlexRig4 drilling rigs, we wrote down excess capital spares and drilling support equipment and as a result, an impairment charge of $7.4 million ($6.4 million, net of tax, or $0.06 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2019 .

During the fourth quarter of fiscal year 2018, after ceasing operations in Ecuador, we entered into a sales negotiation with respect to six conventional rigs, with net book values of $20.8 million, present in the country, pursuant to which the rigs, together with associated equipment and machinery, were sold to a third party to be recycled.

Certain components of these rigs with an $8.5 million net book value, that were not subject to the sale agreement, were transferred to the United States to be utilized on other FlexRigs with high activity and demand.

The sales transaction was completed in November 2018.

We recorded a non-cash impairment charge of $9.2 million ( $7.0 million , net of tax, or $0.06 per diluted share), which is included in Asset Impairment Charge on the Consolidated Statement of Operations for the fiscal year ended September 30, 2018 related to these rigs.

As a result, the remaining rig within the same asset group, not to be disposed of, was written down resulting in an additional impairment charge of $1.4 million ( $1.0 million , net of tax, or $0.01 per diluted share).

Utilization Utilization increased from 49 percent in fiscal year 2018 to 55 percent in fiscal year 2019 and was primarily driven by fewer available rig days as a result of the downsizing of six rigs in Ecuador in the fourth fiscal quarter of 2018 and two International FlexRig4 rigs in the third fiscal quarter of 2019.

H&P Technologies Operations Segment

(in thousands)

Operating revenues

Direct operating expenses

Research and development

Selling, general and administrative expense

Depreciation and amortization

Asset impairment charge

Segment operating loss

Operating Loss H&P Technologies had an operating loss of $12.2 million during fiscal year 2019 compared to an operating loss of $39.6 million during fiscal year 2018 .

The change was primarily driven by additional revenue growth during 2019 and the commercialization of our FlexApp offerings during fiscal year 2018.

Additionally, during the fourth quarter of 2019, we migrated our FlexApp offerings into our H&P Technologies segment.

The activity of our FlexApps was previously included in our U.S.

Land segment.

Prior period information has been restated to reflect the transfer of FlexApps revenues and related costs from U.S.

Land segment to H&P Technologies segment.

This was partially offset by additional research and development initiatives during fiscal year 2019 .

Other Operations

Results of our other operations, excluding corporate selling, general and administrative costs and corporate depreciation, are as follows:

(in thousands)

Operating revenues

Direct operating expenses

Selling, general and administrative expense

Research and development

Depreciation and amortization

Operating income

Prior period information has been restated to reflect the change in reportable segments.

Operating Income Operating income from other operations declined due to higher research and development expense.

During fiscal year 2019 , other operations had operating income of $3.4 million compared to operating income of $5.9 million during fiscal year 2018 .

Results of Operations for the Fiscal Years Ended September 30, 2018 and 2017

The results of operations for the fiscal years ended September 30, 2018 and 2017 are included in Part 2, Item 7— "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our 2018 Annual Report on Form 10-K.

Liquidity and Capital Resources

Sources of Liquidity

Our sources of available liquidity include existing cash balances on hand, cash flows from operations, and availability under our credit facility.

Our liquidity requirements include meeting ongoing working capital needs, funding our capital expenditure projects, paying dividends declared, and repaying our outstanding indebtedness.

Historically, we have financed operations primarily through internally generated cash flows.

During periods when internally generated cash flows are not sufficient to meet liquidity needs, we will borrow from available credit sources, access capital markets or sell our portfolio securities.

Likewise, if we are generating excess cash flows, we may invest in highly rated short ‑ term money market and debt securities.

These investments can include U.S.

Treasury securities, U.S.

Agency issued debt securities, corporate bonds, certificates of deposit and money market funds.

We have continued to reinvest maturities and earnings during fiscal years 2019 and 2018 .

The securities are recorded at fair value.

We may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity as necessary, fund our additional purchases, exchange or redeem Senior Notes, or repay any amounts under our credit facility.

Our ability to access the debt and equity capital markets depends on a number of factors, including our credit rating, market and industry conditions and market perceptions of our industry, general economic conditions, our revenue backlog and our capital expenditure commitments.

Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling rigs under contract, the dayrates we receive under those contracts, the efficiency with which we operate our drilling units, the timing of collections on outstanding accounts receivable, the timing of payments to our vendors for operating costs, and capital expenditures.

To date, general inflationary trends have not had a material effect on our operating margins.

As of September 30, 2019 , we had $347.9 million of cash and cash equivalents on hand and $53.0 million of short-term investments.

Our cash flows for the fiscal years ended September 30, 2019 , 2018 and 2017 are presented below:

Year Ended September 30,

(in thousands)

Net cash provided (used) by:

Operating activities

Investing activities

Financing activities

Increase (decrease) in cash and cash equivalents

Operating Activities

Net working capital excluding cash and short-term investments decreased $108.7 million to $303.9 million as of September 30, 2019 from $412.6 million as of September 30, 2018 due to lower activity coupled with ongoing efforts to improve our cash conversion cycle.

Net cash provided from operating activities was $855.8 million in fiscal year 2019 compared to $557.9 million in fiscal year 2018 .

The $297.9 increase in cash provided by operating activities is primarily due to the decrease in net working capital.

In fiscal year 2017 , net cash provided from operating activities was $371.2 million .

The $186.7 increase in cash provided by operating activities between fiscal years 2018 and 2017 was primarily due to higher activity and average daily margins in fiscal year 2018.

Investing Activities

Capital Expenditures Our investing activities are primarily related to capital expenditures for our fleet.

Our capital expenditures were $458.4 million in 2019 , $466.6 million in fiscal year 2018 and $397.6 million in fiscal year 2017 .

Our fiscal year 2020 capital spending is currently estimated to be between $275 million and $300 million .

This estimate includes normal capital maintenance requirements, information technology spending and a limited number of upgrades primarily related to augmenting the capabilities of our existing rig fleet.

Acquisition of Business During fiscal years 2019 and 2018 , we paid $16.2 million and $47.9 million , respectively, net of cash acquired, for the acquisition of drilling technology companies.

Sale of Assets Our proceeds from asset sales totaled $50.8 million in fiscal year 2019 , $44.4 million in fiscal year 2018 and $23.4 million in fiscal year 2017 .

Stock Portfolio Held We manage marketable securities consisting of common shares of Schlumberger, Ltd.

that, at the close of fiscal year 2019 , had a fair value of $16.0 million .

The value of the portfolio is subject to fluctuation in the market and may vary considerably over time.

The portfolio is recorded at fair value on our balance sheet.

In September 2019, we sold our remaining 1.6 million shares in Valaris, previously known as Ensco Rowan plc, for total proceeds of approximately $12.0 million.

Our marketable securities held as of September 30, 2019 are presented below:

(in thousands, except for share amounts)

Number of Shares

Schlumberger, Ltd.

Financing Activities

The increase of $56.5 million in net cash used by financing activities in fiscal year 2019 from fiscal year 2018 was primarily due to payments made for the early extinguishment of long-term debt and the repurchase of shares.

Dividends We paid dividends of $2.84 , $2.82 , and $2.80 per share during fiscal years 2019 , 2018 and 2017 , respectively.

Total dividends paid were $313.4 million , $308.4 million and $305.5 million in fiscal years 2019 , 2018 and 2017 , respectively.

Adjusting for stock splits accordingly, we have increased the effective annual dividend per share every fiscal year for the past 47 years.

The declaration and amount of future dividends is at the discretion of our Board of Directors and subject to our financial condition, results of operations, cash flows, and other factors our Board of Directors deems relevant.

Credit Facilities

On November 13, 2018, we entered into a credit agreement by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, providing for an unsecured revolving credit facility (the “2018 Credit Facility”), which was originally set to mature on November 13, 2023.

Pursuant to the 2018 Credit Facility Amendment entered into on November 13, 2019, among other things, the maturity date was extended by one year to November 13, 2024.

The 2018 Credit Facility has $750 million in aggregate availability with a maximum of $75 million available for use as letters of credit.

The 2018 Credit Facility also permits aggregate commitments under the facility to be increased by $300 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.

The 2018 Credit Facility was originally guaranteed by HPIDC, but such guarantee was released simultaneously with the redemption of the HPIDC 2025 Notes and the release of HPIDC as a guarantor under the Company 2025 Notes.

The borrowings under the 2018 Credit Facility accrue interest at a spread over either the London Interbank Offered Rate (LIBOR) or the Base Rate.

We also pay a commitment fee on the unused balance of the facility.

Borrowing spreads as well as commitment fees are determined based on the debt rating for senior unsecured debt of the Company, as determined by Moody’s and Standard & Poor's ("S&P").

The spread over LIBOR ranges from 0.875 percent to 1.500 percent per annum and commitment fees range from 0.075 percent to 0.200 percent per annum.

Based on the unsecured debt rating of the Company on September 30, 2019, the spread over LIBOR would have been 1.125 percent had borrowings been outstanding under the facility and commitment fees are 0.125 percent.

There is a financial covenant in the 2018 Credit Facility that requires us to maintain a total debt to total capitalization ratio of less than or equal to 50 percent.

The 2018 Credit Facility contains additional terms, conditions, restrictions and covenants that we believe are usual and customary in unsecured debt arrangements for companies of similar size and credit quality, including a limitation that priority debt (as defined in the credit agreement) may not exceed 17.5 percent of the net worth of the Company.

As of September 30, 2019 , there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility.

See Note 7—Debt to our Consolidated Financial Statements for more information about the 2018 Credit Facility.

In connection with entering into the 2018 Credit Facility, we terminated our $300.0 million unsecured credit facility under the credit agreement dated as of July 13, 2016 by and among HPIDC, as borrower, the Company, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto.

As of September 30, 2019 , we had two outstanding letters of credit with banks under bilateral line of credit agreements, in the amounts of $25.5 million and $2.1 million, respectively.

Subsequent to our fiscal year end, in October 2019, the balance of the $25.5 million outstanding letter of credit was reduced to $24.8 million.

As of September 30, 2019 , we also had a $20.0 million unsecured standalone line of credit facility, for the purpose of obtaining the issuance of bid and performance bonds, as well as other miscellaneous international needs.

$11.5 million was outstanding under the $20.0 million facility as of September 30, 2019 .

The applicable agreements for all unsecured debt contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality.

At September 30, 2019 , we were in compliance with all debt covenants, and we anticipate that we will continue to be in compliance during the next quarter of fiscal year 2020.

Repurchase and Retirement of Common Shares

We have an evergreen authorization to purchase up to four million common shares per fiscal year.

During fiscal 2019 , we purchased one million common shares at an aggregate cost of $42.8 million , which are held as treasury shares.

We had no purchases of common shares during the fiscal years ended September 30, 2018 and 2017 .

Future Cash Requirements

Our operating cash requirements, scheduled debt repayments, interest payments, any declared dividends, and estimated capital expenditures for fiscal year 2020 are expected to be funded through current cash and cash to be provided from operating activities.

However, there can be no assurance that we will continue to generate cash flows at current levels.

The long ‑ term debt to total capitalization ratio was 10.8 percent at September 30, 2019 compared to 10.1 percent at September 30, 2018 .

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.

For information regarding our drilling contract backlog, see Item 1— “Business — Contract Backlog” .

Material Commitments

Our contractual obligations as of September 30, 2019 are summarized in the table below:

Payments due by year

(in thousands)

Long-term debt

Operating leases (2)

Purchase obligations (2)

Total contractual obligations

Interest on fixed ‑ rate debt was estimated based on principal maturities.

See Note 7—Debt to our Consolidated Financial Statements.

See Note 16—Commitments and Contingencies to our Consolidated Financial Statements.

The above table does not include obligations for our pension plan or amounts recorded for uncertain tax positions.

In fiscal years 2019 and 2018 , we did not make any contributions to the pension plan.

Contributions may be made in fiscal year 2020 to fund unexpected distributions in lieu of liquidating pension assets.

Future contributions beyond fiscal year 2020 are difficult to estimate due to multiple variables involved.

At September 30, 2019 , we had $17.9 million recorded for uncertain tax positions and related interest and penalties.

However, the timing of such payments to the respective taxing authorities cannot be estimated at this time.

Income taxes are more fully described in Note 8—Income Taxes to our Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Accounting policies that we consider significant are summarized in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties to our Consolidated Financial Statements included in Part II, Item 8 – Financial Statements and Supplementary Data of this report.

The preparation of our financial statements in conformity with U.S.

GAAP requires management to make certain estimates and assumptions.

These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures of contingent assets and liabilities.

Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.

These estimates and assumptions are evaluated on an on ‑ going basis.

Actual results may differ from these estimates under different assumptions or conditions.

The following is a discussion of the critical accounting policies and estimates used in our financial statements.

Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are capitalized at cost, while maintenance and repairs are expensed as incurred.

The interest expense applicable to the construction of qualifying assets is capitalized as a component of the cost of such assets.

We account for the depreciation of property, plant and equipment using the straight ‑ line method over the estimated useful lives of the assets considering the estimated salvage value of the property, plant and equipment.

Both the estimated useful lives and salvage values require the use of management estimates.

Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation or result in abandonments.

For the fiscal years presented in this report, no significant changes were made to the determinations of useful lives or salvage values.

Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.

Impairment of Long ‑ lived Assets, Goodwill and Other Intangible Assets

Management assesses the potential impairment of our long ‑ lived assets and finite-lived intangibles whenever events or changes in circumstances indicate that the carrying value may not be recoverable.

Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, change in technology and/or overall changes in general market conditions.

If a review of the long ‑ lived assets and finite-lived intangibles indicates that the carrying value of certain of these assets or asset groups is more than the estimated undiscounted future cash flows, an impairment charge is made, as required, to adjust the carrying value to the estimated fair value.

Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig’s marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics including utilization.

The fair value of drilling rigs is determined based upon either an income approach using estimated discounted future cash flows, a market approach considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors, a cost approach utilizing reproduction costs new as adjusted for the asset age and condition, and/or a combination of multiple approaches.

The use of different assumptions could increase or decrease the estimated fair value of assets and could therefore affect any impairment measurement.

We review goodwill for impairment annually in the fourth fiscal quarter or more frequently if events or changes in circumstances indicate it is more likely than not that the carrying amount of the reporting unit holding such goodwill may exceed its fair value.

We initially assess goodwill for impairment based on qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount.

If further testing is necessary or a quantitative test is elected, we quantitatively compare the fair value of a reporting unit with its carrying amount, including goodwill.

If the carrying amount exceeds the fair value, an impairment charge will be recognized in an amount equal to the excess;

however, the loss recognized would not exceed the total amount of goodwill allocated to that reporting unit.

Self ‑ Insurance Accruals

We self ‑ insure a significant portion of expected losses relating to workers’ compensation, general liability, employer’s liability and automobile liability.

Generally, deductibles range from $1 million to $5 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States.

Insurance is purchased over deductibles to reduce our exposure to catastrophic events but there can be no assurance that such coverage will apply or be adequate in all circumstances.

Estimates are recorded for incurred outstanding liabilities for workers’ compensation and other casualty claims.

Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred.

Estimates for liabilities and retained losses are based on adjusters’ estimates, our historical loss experience and statistical methods commonly used within the insurance industry that we believe are reliable.

We also engage a third-party actuary to perform a periodic review of our domestic casualty losses.

Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices.

Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

Our wholly ‑ owned captive insurance company finances a significant portion of the physical damage risk on company ‑ owned drilling rigs as well as international casualty deductibles.

An actuary reviews our captive losses on an annual basis.

We insure working land rigs and related equipment at values that approximate the current replacement costs on the inception date of the policies.

However, we self-insure large deductibles under these policies.

We also carry insurance with varying deductibles and coverage limits with respect to stacked rigs, offshore platform rigs, and “named wind storm” risk in the Gulf of Mexico.

We self ‑ insure a number of other risks, including loss of earnings and business interruption, and most cyber risks.

Revenue Recognition

Contract drilling services revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured.

For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment.

Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized as the drilling service is provided.

Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.

Reimbursements received for out ‑ of ‑ pocket expenses are recorded as both revenues and direct costs.

For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

Deferred income taxes are accounted for under the liability method, which takes into account the differences between the basis of the assets and liabilities for financial reporting purposes and amounts recognized for income tax purposes.

Our net deferred tax liability balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions.

Included in our net deferred tax liability balance are deferred tax assets that are assessed for realizability.

If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates.

In addition, we operate in several countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions.

We recognize uncertain tax positions we believe have a greater than 50 percent likelihood of being sustained.

We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments.

New Accounting Standards

See Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties to our Consolidated Financial Statements for recently adopted accounting standards and new accounting standards not yet adopted.

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.

For the purpose of understanding the impact on our Cash Flow from Operations, net working capital is calculated as current assets, excluding cash and short-term investments, less current liabilities, excluding dividends payable, short–term debt and the current portion of long–term debt.

Net working capital is not a measure of operating performance or liquidity defined by U.S.

GAAP and may not be comparable to similarly titled measures presented by other companies.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity