Helmerich & Payne, Inc. (HP)

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Part I of this Form 10‑K as well as the Consolidated Financial Statements and related notes thereto included in Part II, Item 8— Financial Statements and Supplementary Data of this Form 10‑K. Our future operating results may be affected by various trends and factors which are beyond our control. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Form 10-K under “Cautionary Note regarding Forward-Looking Statements” and Item 1A—Risk Factors. Accordingly, past results and trends should not be used by investors to anticipate future results or trends.

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Executive Summary

H&P through its operating subsidiaries provides performance-driven drilling solutions and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. As of September 30, 2024, our drilling rig fleet included a total of 262 drilling rigs. Our reportable operating business segments consist of the North America Solutions segment with 228 rigs, the International Solutions segment with 27 rigs, and the Offshore Gulf of Mexico segment with seven offshore platform rigs as of September 30, 2024. At the close of fiscal year 2024, we had 170 active contracted rigs, of which 100 were under a fixed-term contract and 70 were working well-to-well, compared to 164 contracted rigs at September 30, 2023. Our long-term strategy remains focused on innovation, technology, safety, operational excellence and reliability. As we move forward, we believe that our rig fleet, technology offerings, financial strength, contract backlog and strong customer and employee base position us very well to respond to continued cyclical and often times volatile market conditions and to take advantage of future opportunities.

Pending KCA Deutag Acquisition

On July 25, 2024, H&P and certain of its wholly owned subsidiaries entered into the Purchase Agreement to acquire KCA Deutag for total cash consideration of approximately $2.0 billion, which consists of the $0.9 billion unadjusted share purchase price and $1.1 billion to contemporaneously repay or redeem certain of KCA Deutag's existing debt upon consummation of the Acquisition. Total consideration is subject to adjustment as set forth in the Purchase Agreement. The transaction is expected to close prior to calendar 2024 year end, subject to customary closing conditions and regulatory approvals.

Market Outlook

Our revenues are primarily derived from the capital expenditures of companies involved in the exploration, development and production of crude oil and natural gas (“E&Ps”). Generally, the level of capital expenditures is dictated by capital budgets set to achieve respective production targets in relation to current and expected future prices of crude oil and natural gas, which are determined by various supply and demand factors and have historically been volatile. Furthermore, E&Ps have become more fiscally disciplined in their level of capital expenditures relative to commodity price fluctuations, which has resulted in less volatility within the oilfield service businesses, including our operations.

The capital budgets for calendar year 2025 have not yet been established by many of our customers; however, based upon the crude oil and natural gas pricing environment and many of our customers' desire to at least maintain their current production levels, we expect the level of capital spending and activity in calendar year 2025 to be similar to that experienced in calendar year 2024. The overall demand for super-spec rigs in the U.S. remains relatively strong and while some readily available idle super-spec capacity exists in the market, it is not to a level that has materially impacted pricing as it could be quickly reabsorbed into the market. This supply-demand dynamic combined with the value proposition we provide our customers through our drilling expertise, high-quality FlexRig® fleet, and automation technology remains constructive for our underlying contract economics.

With regard to our North America Solutions segment, our rig count remained relatively range-bound during fiscal 2024 despite a decline in the overall industry rig count. The rig market was pressured by continued weakness in natural gas prices as well as other non-commodity price related factors, such as customer capital budgets, drilling plans, production levels and customer consolidations. We still believe the supply and demand dynamics surrounding our North America Solutions segment remain constructive for future activity and pricing levels. As such, heading into fiscal year 2025, we expect our rig activity to remain relatively stable bound absent any significant changes to commodity prices. The Company also expects its strategy around employing a fiscally prudent approach to deploying capital and prioritizing economic margins over rig utilization to remain intact.

Collectively, our other business segments, Offshore Gulf of Mexico and International Solutions, are exposed to the same macro commodity price environment affecting our North America Solutions segment; however, activity levels in the International Solutions segment are also subject to other various geopolitical and financial factors specific to the countries of our operations. During fiscal 2025, our operational presence in certain international markets, primarily the Middle East and the offshore management contract business, is expected to increase substantially upon consummation of the pending Acquisition. Outside the pending Acquisition our activity in the Middle East region is expected to increase from a historical level of 2 to 3 rigs working in the region to approximately 9 to 11 rigs as we export rigs from the U.S. and begin operations in Saudi Arabia. The pending Acquisition and commencement of rig operations in Saudi Arabia is a continuation of the Company's strategy of international growth and diversification. Currently, activity levels in our Offshore Gulf of Mexico business segment look to remain relatively steady at current levels for the foreseeable future.

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Recent Developments

International Revenue Contracts

In February 2024, the Company finalized the contractual terms with Saudi Aramco for a seven super-spec FlexRig® tender award for work in the Kingdom of Saudi Arabia. These rigs are expected to commence operations shortly after delivery. The rigs are being sourced from our idle super-spec rigs in the U.S., converted to walking configurations, and further equipped to suit contractual specifications. During the year ended September 30, 2024, we began mobilizing five super-spec rigs to the Kingdom of Saudi Arabia. We commenced operations in the first quarter of fiscal 2025.

Pending KCA Deutag Acquisition

On July 25, 2024, H&P and certain of its wholly owned subsidiaries entered into the Purchase Agreement to acquire KCA Deutag for total cash consideration of approximately $2.0 billion, which consists of the $0.9 billion unadjusted share purchase price and $1.1 billion to contemporaneously repay or redeem certain of KCA Deutag's existing debt upon consummation of the Acquisition. Total consideration is subject to adjustment as set forth in the Purchase Agreement. The transaction is expected to close prior to calendar 2024 year end, subject to customary closing conditions and regulatory approvals.

KCA Deutag is a diverse global drilling company. The company has a significant land drilling presence in the Middle East, which represents approximately two-thirds of the company’s calendar year 2023 Operating EBITDA, with additional operations in South America, Europe and Africa. In addition to its land operations, KCA Deutag has asset-light offshore management contract operations in the North Sea, Angola, Azerbaijan and Canada, with super major customers and long-term earnings visibility through a robust backlog. KCA Deutag’s Kenera segment comprises manufacturing and engineering businesses, including Bentec, with three facilities serving the energy industry, representing a longer-term growth opportunity.

Senior Notes Issued in Fiscal Year 2024

On September 17, 2024, we completed a private offering of $1.25 billion aggregate principal amount of the Notes, comprised of the following tranches: $350.0 million aggregate principal amount of 4.65 percent senior notes due 2027 issued at a price equal to 99.958 percent of their face value, $350.0 million aggregate principal amount of 4.85 percent senior notes due 2029 issued at a price equal to 99.883 percent of their face value and $550.0 million aggregate principal amount of 5.50 percent senior notes due 2034 issued at a price equal to 99.670 percent of their face value.

The Company intends to use the net proceeds, together with the proceeds of its term loan credit facility (discussed below) and cash on hand, to finance the purchase price for the Acquisition, to repay certain of KCA Deutag’s outstanding indebtedness, and to pay related fees and expenses. For additional information regarding the Notes, refer to Note 6—Debt to the Consolidated Financial Statements.

Term Loan Credit Agreement

On August 14, 2024, the Company entered into the Term Loan Credit Agreement, dated as of August 14, 2024, among the Company, Morgan Stanley Senior Funding, Inc. (“MSSF”), as administrative agent, and the other lenders party thereto. Under the Term Loan Credit Agreement, the Company may obtain unsecured term loans in a single delayed draw in an aggregate principal amount up to $400.0 million. The Term Loan Credit Agreement matures at the two-year anniversary of the funding of the term loans unless earlier terminated pursuant to the terms of the Term Loan Credit Agreement. We expect to use the proceeds from the Term Loan Credit Agreement, together with the net proceeds from the sale of the Notes and cash on hand, to finance the purchase price for the Acquisition, to repay certain of KCA Deutag's outstanding indebtedness, and pay related fees and expenses. The funding of the term loans had not occurred as of September 30, 2024.

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Revolving Credit Facility

On August 14, 2024, the Company entered into the Amended Credit Facility with the lenders party thereto (the “Revolving Credit Agreement Lenders”), the issuing lenders party thereto and Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent, swing line lender and issuing lender, which amended and restated the Credit Agreement, dated as of November 13, 2018 (as amended through Amendment No. 2 to Credit Agreement dated as of March 8, 2022, the “Existing Credit Agreement”), among the Company, the lenders party thereto and Wells Fargo, as administrative agent, swing line lender and issuing lender.

Under the terms of the Amended Credit Facility, the Company may obtain unsecured revolving loans in an aggregate principal amount not to exceed $950 million outstanding at any time. $775 million of the revolving commitments under the Amended Credit Facility expire on November 12, 2028 and $175 million of the revolving commitments mature on November 10, 2027 (the “Stated Maturity Date”), but the Company may request two one-year extensions of the Stated Maturity Date, subject to satisfaction of certain conditions. Commitments under the Amended Credit Facility may be increased by up to $100 million, subject to the agreement of the Company and new or existing Revolving Credit Agreement Lenders.

The proceeds of the loans made under the Amended Credit Facility may be used by the Company for (i) working capital and other general corporate purposes, (ii) for the payment of fees and expenses related to the entering into of the Amended Credit Facility and the other credit documents and (iii) for the refinancing of the extensions of credit under the Existing Credit Agreement.

Contract Backlog

Drilling contract backlog is the expected future dayrate revenue from executed contracts. We calculate backlog as the total expected revenue from fixed-term contracts and do not include any anticipated contract renewals or expected performance bonuses as part of its calculation. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. In addition to depicting the total expected revenue from fixed-term contracts, backlog is indicative of expected future cash flow that the Company expects to receive regardless of whether a customer honors the fixed-term contract to expiration of a contract or decides to terminate the contract early and pay an early termination payment. In the event of an early termination payment, the timing of the recognition of backlog and the total amount of revenue may differ; however, the overall associated gross margin is preserved. As such, management finds backlog a useful metric for future planning and budgeting, whereas investors consider it useful in estimating future revenue and cash flows of the Company. As of September 30, 2024 and 2023, our contract drilling backlog was $1.5 billion and $1.4 billion, respectively. The increase in backlog at September 30, 2024 compared to 2023 is primarily due to the Company finalizing contractual terms with Saudi Aramco for a seven super-spec FlexRig® tender award for work in the Kingdom of Saudi Arabia. Approximately 53.3 percent of the September 30, 2024 total backlog is reasonably expected to be fulfilled in fiscal year 2025.

The following table sets forth the total backlog by reportable segment as of September 30, 2024 and 2023, and the percentage of the September 30, 2024 backlog reasonably expected to be fulfilled in fiscal year 2025:

The early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. In some limited circumstances, such as sustained unacceptable performance by us, no early termination payment would be paid to us. Early terminations could cause the actual amount of revenue earned to vary from the backlog reported. See Item 1A—Risk Factors—"Our current backlog of drilling services and solutions revenue may decline and may not be ultimately realized as fixed‑term contracts and may, in certain instances, be terminated without an early termination payment.” within this Form 10-K regarding fixed term contract risk. Additionally, see Item 1A—Risk Factors—"The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, could have a material adverse effect on our business, financial condition and results of operations." within this Form 10-K.

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Results of Operations for the Fiscal Years Ended September 30, 2024 and 2023

Consolidated Results of Operations

Net Income We recorded income of $344.2 million ($3.43 per diluted share) for the fiscal year ended September 30, 2024 compared to income of $434.1 million ($4.16 per diluted share) for the fiscal year ended September 30, 2023.

Operating Revenue Consolidated operating revenues were $2.8 billion and $2.9 billion during fiscal years 2024 and 2023, respectively. The $0.1 billion decrease was primarily driven by lower activity levels.

Direct Operating Expenses, Excluding Depreciation and Amortization Direct operating expenses in fiscal year 2024 were $1.6 billion, compared to direct operating expenses of $1.7 billion in fiscal year 2023. The decrease was primarily attributable to the aforementioned lower activity levels. Additionally, we recognized $6.7 million in direct operating expenses associated with the fair value adjustments of contingent consideration related to earnout payments associated with our business acquisition in fiscal year 2019, partially offset by a gain on involuntary conversion of a rig of approximately $5.5 million.

Depreciation and Amortization Depreciation and amortization expense was $397.3 million in fiscal year 2024 and $382.3 million in fiscal year 2023. The increase was primarily driven by $12.7 million of accelerated depreciation for components on rigs that were scheduled for conversion in fiscal year 2024 compared to $2.4 million for fiscal year 2023. Depreciation and amortization includes amortization of intangible assets of $6.4 million and $6.6 million and abandonments of equipment of $6.5 million and $3.3 million in fiscal years 2024 and 2023, respectively.

Research and Development Expense Research and development expense was $41.0 million and $30.0 million in fiscal years 2024 and 2023, respectively. The increase was primarily driven by an associated asset acquisition during the fiscal year ended September 30, 2024, as well as costs related to expanded project scopes.

Selling, General and Administrative Expense Selling, general and administrative expenses increased to $244.9 million in the fiscal year ended September 30, 2024 compared to $206.7 million in the fiscal year ended September 30, 2023. The $38.2 million increase in fiscal year 2024 is primarily due to a $19.6 million increase in labor and labor-related expenses; and a $8.9 million increase in IT related and professional service expenses.

Asset Impairment Charges During the fiscal year ended September 30, 2023, the Company initiated a plan to decommission, scrap and/or sell certain assets including four international FlexRig® drilling rigs, four international conventional drilling rigs, and additional equipment. The aggregate net book value of these assets of $13.2 million was written down to their estimated scrap value of $1.1 million, resulting in non-cash impairment charges of $12.1 million for the fiscal year ended September 30, 2023, of which $8.1 million of the charge is recorded within the International Solutions segment. The remaining $4.0 million is recorded within the North America Solutions segment. The impairment charge was recorded in the Consolidated Statement of Operations for the fiscal year ended September 30, 2023.

Acquisition Transaction Costs During the fiscal year ended September 30, 2024, we recognized approximately $15.0 million in acquisition transaction costs associated with the acquisition of KCA Deutag. These non-recurring costs are primarily related to third-party legal and advisory services. See Note 11—Acquisition Transaction Costs for additional details related to the Acquisition.

Gain on Investment Securities During the fiscal year ended September 30, 2024, we recognized an aggregate gain of $14.0 million on investment securities. This gain consisted primarily of $30.9 million and $1.6 million gains on our equity investments in ADNOC Drilling and Tamboran Corp.; both of which were a result of increases in the fair market values of the stocks. The gains on our equity investments in ADNOC Drilling and Tamboran Corp. during the fiscal year ended September 30, 2024 were offset by $10.2 million and $1.4 million of losses on our investments in Galileo and a geothermal equity security, respectively, due to changes in the fair values of the investments, and a $7.1 million loss as a result of a Blue Chip Swap transaction. See Note 2—Summary of Significant Accounting Policies, Related Risks and Uncertainties—International Solutions Drilling Risks for additional details related to the Blue Chip Swap. During the fiscal year ended September 30, 2023, we recognized an aggregate gain of $11.3 million on investment securities. This gain was mainly comprised of a $27.4 million gain on our equity investment in ADNOC Drilling, partially offset against a $4.2 million loss on our investment in Tamboran Corp.; both of which were a result of fluctuations in the fair market value of the stocks. Additionally, the aggregate gain was offset by a $12.2 million loss on investment recognized during the fiscal year ended September 30, 2023 as a result of a Blue Chip Swap transaction that occurred during the period.

Interest and Dividend Income Interest and dividend income was $41.2 million and $28.4 million in fiscal years 2024 and 2023, respectively. The increase was primarily due to $11.1 million in dividends received from ADNOC Drilling compared to $3.4 million in fiscal year 2023.

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Interest Expense Interest expense totaled $29.1 million in fiscal year 2024 and $17.3 million in fiscal year 2023. The increase was primarily attributable to approximately $9.2 million of commitment fees recognized during the twelve months ended September 30, 2024 related to a bridge loan facility the Company entered into during the period. For additional information regarding commitment fees, refer to Note 6—Debt to the Consolidated Financial Statements.

Income Taxes We had an income tax expense of $136.9 million in fiscal year 2024 compared to an income tax expense of $159.3 million in fiscal year 2023. The effective income tax rate was 28.5 percent in fiscal year 2024 compared to 26.8 percent in fiscal year 2023. The effective rates differ from the U.S. federal statutory rate (21.0 percent for the fiscal years 2024 and 2023) primarily due to non-deductible permanent items and state and foreign income taxes.

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 7—Income Taxes to our Consolidated Financial Statements for additional income tax disclosures.

North America Solutions

The following table presents certain information with respect to our North America Solutions reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 366 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues were $2.4 billion and $2.5 billion in fiscal year 2024 and 2023, respectively. The $73.8 million decrease in operating revenues was primarily due to a 10.4 percent decrease in activity levels partially offset by higher average pricing levels.

Direct Operating Expenses Direct operating expenses decreased by $81.1 million during fiscal year ended September 30, 2024. The decrease was primarily driven by lower activity levels, partially offset by an increase in per revenue day labor and materials and supplies expense.

Depreciation and Amortization Depreciation and amortization expense increased to $366.4 million during the fiscal year ended September 30, 2024 as compared to $354.0 million during the fiscal year ended September 30, 2023. The increase was primarily driven by $12.7 million of accelerated depreciation for components on rigs that were scheduled for conversion in fiscal year 2024 compared to $2.4 million in fiscal year 2023.

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Research and Development Expense Research and development expense increased to $41.3 million during the fiscal year ended September 30, 2024 as compared to $30.5 million during the fiscal year ended September 30, 2023. The increase was driven by an associated asset acquisition during the fiscal year ended September 30, 2024, as well as costs related to expanded project scopes.

Selling, General and Administrative Expenses Selling, general and administrative expenses increased to $61.1 million during the fiscal year ended September 30, 2024 as compared to $58.4 million during the fiscal year ended September 30, 2023. This increase was primarily driven by a $5.2 million increase in labor and labor-related expenses partially offset by a $3.0 million decrease in professional service expenses.

Asset Impairment Charges During the fiscal year ended September 30, 2023, assets that were previously classified as Assets held-for-sale were either sold or written down to scrap value. The aggregate net book value of these remaining assets was $3.0 million, which exceeded the estimated scrap value of $0.3 million, resulting in a non-cash impairment charge of $2.7 million during the fiscal year ended September 30, 2023. During the same period, we also identified additional equipment that met the asset held-for-sale criteria and were reclassified as Assets held-for-sale on our Consolidated Balance Sheets. The aggregate net book value of the equipment of $1.4 million was written down to its estimated scrap value of $0.1 million, resulting in a non-cash impairment charge of $1.3 million during the fiscal year ended September 30, 2023.

International Solutions

The following table presents certain information with respect to our International Solutions reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 366 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues were $194.0 million and $212.6 million in the fiscal years ended September 30, 2024 and 2023, respectively. The $18.6 million decrease in operating revenue was primarily driven by a 3.6 percent decrease in activity levels and decreases in per revenue day pricing, partially offset by higher ancillary services revenue.

Operating Expenses Direct operating expenses decreased to $174.6 million during the fiscal year ended September 30, 2024 as compared to $187.3 million during the fiscal year ended September 30, 2023. This decrease was primarily driven by a 3.6 percent decrease in activity levels and decreases in per revenue day materials and supplies expense.

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Asset Impairment Charges During the fiscal year ended September 30, 2023, the Company initiated a plan to decommission and scrap four international FlexRig® drilling rigs and four conventional drilling rigs located in Argentina that are not suitable for unconventional drilling. As a result, these rigs were reclassified to Assets held-for-sale on our Consolidated Balance Sheets. The rigs’ aggregate net book value of $8.8 million was written down to the estimated scrap value of $0.7 million, which resulted in a non-cash impairment charge of $8.1 million recorded in Asset impairment charges within our Consolidated Statement of Operations during the fiscal year ended September 30, 2023.

Offshore Gulf of Mexico

The following table presents certain information with respect to our Offshore Gulf of Mexico reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 366 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues were $106.2 million and $130.2 million in the fiscal year ended September 30, 2024 and 2023, respectively. The 18.5 percent decrease in operating revenue was primarily due to a 23.9 percent decrease in activity levels, partially offset by higher per revenue day reimbursable revenue.

Direct Operating Expenses Direct operating expenses decreased to $82.7 million during the fiscal year ended September 30, 2024 as compared to $96.8 million during the fiscal year ended September 30, 2023. The decrease was primarily driven by a decrease in activity levels as described above, partially offset by an increase in per revenue day materials and supplies expense.

Other Operations

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

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Operating Revenues We continue to use our Captive insurance companies to insure the deductibles for our domestic workers’ compensation, general liability, automobile liability claims programs, and medical stop-loss program and to insure the deductibles from the Company's international casualty and rig property programs. Operating revenues of $71.6 million and $77.3 million during the fiscal years ended September 30, 2024 and 2023, respectively, primarily consisted of $61.2 million and $67.4 million, respectively, in intercompany premium revenues recorded by the Captives. These revenues were eliminated upon consolidation.

Direct Operating Expenses Direct operating expenses of $69.8 million and $57.9 million during the fiscal years ended September 30, 2024 and 2023, respectively, primarily consisted of $11.4 million and $12.5 million, respectively, in adjustments to accruals for estimated losses allocated to the Captives, rig and casualty insurance premiums of $37.6 million and $39.7 million, respectively, and medical stop loss expenses of $15.5 million and $10.6 million, respectively. The change to accruals for estimated losses is primarily due to actuarial valuation adjustments by our third-party actuary.

Results of Operations for the Fiscal Years Ended September 30, 2023 and 2022

A discussion of our results of operations for the fiscal year ended September 30, 2023 compared to the fiscal year ended September 30, 2022 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, 2023, filed with the SEC on November 8, 2023.

Liquidity and Capital Resources

Sources of Liquidity

Our sources of available liquidity include existing cash balances on hand, cash flows from operations, and availability under the Amended Credit Facility. Our liquidity requirements include meeting ongoing working capital needs, funding our capital expenditure projects, paying dividends declared, repaying our outstanding indebtedness, and funding the pending acquisition of KCA Deutag. Historically, we have financed operations primarily through internally generated cash flows. During periods when internally generated cash flows are not sufficient to meet liquidity needs, we may utilize cash on hand, borrow from available credit sources, access capital markets or sell our investments. Likewise, if we are generating excess cash flows or have cash balances on hand beyond our near-term needs, we may return cash to shareholders through dividends or share repurchases, or 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, highly rated corporate bonds and commercial paper, certificates of deposit and money market funds. However, in some international locations we may make short-term investments that are less conservative, as equivalent highly rated investments are unavailable. See—Note 2—Summary of Significant Accounting Policies, Related Risks and Uncertainties—International Solutions Drilling Risks.

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

Cash Flows

Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling rigs under contract, the revenue we receive under those contracts, the efficiency with which we operate our drilling rigs, the timing of collections on outstanding accounts receivable, the timing of payments to our vendors for operating costs, and capital expenditures. As our revenues increase, operating net working capital is typically a use of capital, while conversely, as our revenues decrease, operating net working capital is typically a source of capital.

As of September 30, 2024 and 2023, we had cash and cash equivalents of $217.3 million and $257.2 million and short-term investments of $292.9 million and $93.6 million, respectively. Our cash flows for the fiscal years ended September 30, 2024, 2023 and 2022 are presented below:

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Operating Activities

Our operating net working capital (non-GAAP) as of September 30, 2024, 2023, and 2022 is presented below:

Cash flows provided by operating activities were approximately $684.7 million, $833.7 million, and $233.9 million for the fiscal year ended September 30, 2024, 2023, and 2022 respectively. The change in cash provided by operating activities between fiscal years 2024 and 2023 is primarily driven by lower activity levels partially offset by higher average pricing levels. The increase in cash provided by operating activities between fiscal years 2023 and 2022 was primarily driven by higher activity and pricing. For the purpose of understanding the impact on our cash flows from operating activities, operating net working capital is calculated as current assets, excluding cash and cash equivalents, short-term investments, assets held-for-sale, and prepaid property, plant and equipment, less current liabilities, excluding dividends payable, short-term debt and advance payments for sale of property, plant and equipment.

Operating net working capital was $236.6 million, $239.6 million and $271.8 million as of September 30, 2024, 2023 and 2022, respectively. This metric is considered a non-GAAP measure of the Company's liquidity. The Company considers operating net working capital to be a supplemental measure for presenting and analyzing trends in our cash flows from operations over time. Likewise, the Company believes that operating net working capital is useful to investors because it provides a means to evaluate the operating performance of the business using criteria that are used by our internal decision makers.

Investing Activities

Capital Expenditures Our capital expenditures were $495.1 million, $395.5 million and $250.9 million in fiscal years 2024, 2023 and 2022, respectively. The increase in capital expenditures is driven by the timing of procurement associated with equipment overhauls and certain long-term projects including the procurement of long lead items for international expansion projects. Our fiscal year 2025 capital spending is currently estimated to be between $290 million and $325 million. This estimate includes normal capital maintenance requirements, planned rig-related equipment upgrades, and skidding to walking conversions for up to six rigs.

Net Sales of Short-Term Investments Our net sales of short-term investments during fiscal year 2024 were $3.5 million compared to net sales of $14.3 million and $79.6 million in fiscal years 2023 and 2022, respectively. The change in activity is driven by our ongoing liquidity management. Additionally, the Central Bank of Argentina maintains currency controls that limit our ability to access U.S. dollars in Argentina and remit cash from our Argentine operations. The execution of certain trades known as Blue Chip Swaps effectively results in a parallel U.S. dollar exchange rate. During the fiscal year ended 2024 and 2023, we entered into a Blue Chip Swap transaction, which resulted in a $7.1 million and $12.2 million loss on investment recorded in Gain on investment securities within our Consolidated Statements of Operations, respectively. As a result of the Blue Chip Swap transactions, $13.8 million and $9.8 million of net cash was repatriated to the U.S. during 2024 and 2023, respectively.

Net Purchases of Long-Term Investments Our net purchases of long-term investments were $9.1 million, $20.7 million and $29.2 million in fiscal years 2024, 2023 and 2022, respectively. Our activity during the fiscal year ended September 30, 2024, was driven by $9.1 million of investments in various debt and equity securities. Our activity during the fiscal year ended September 30, 2023, was driven by a $14.1 million equity investment in Tamboran Resources Corporation, $4.1 million in debt and equity security investments in various geothermal energy companies, and $2.5 million investments in other equity securities. Our activity during the fiscal year ended September 30, 2022, was driven by a $33.0 million cornerstone investment in Galileo Holdco 2 Limited Technologies and the purchase of $18.2 million in various geothermal investments, offset by $22.0 million of proceeds received from the liquidation of our remaining equity securities in Schlumberger, Ltd.

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Insurance Proceeds from Involuntary Conversion In November 2022, a fire at a wellsite caused substantial damage to one of our super-spec rigs within our North America Solutions segment. The major components were destroyed beyond repair and considered a total loss, and, as a result, these assets were written off and the rig was removed from our available rig count. At the time of the loss, the rig was fully insured under replacement cost insurance. During the fiscal year ended September 30, 2024, we collected $5.5 million of the total expected insurance proceeds. The total insurance proceeds received during the period exceeds the recognized loss and therefore was recognized as a gain within operating income during the fiscal year ended September 30, 2024. During the fiscal year ended September 30, 2023, we collected $9.2 million of the total expected insurance proceeds.

Sale of Assets Our proceeds from asset sales totaled $46.4 million, $70.1 million and $62.3 million in fiscal year 2024, 2023 and 2022, respectively. The decrease in proceeds is mainly driven by lower rig activity which drives lower reimbursement from customers for lost or damaged drill pipe and other used drilling equipment.

Financing Activities

Dividends We paid dividends of $1.68 per share, comprised of a base cash dividend of $1.00 and a supplemental cash dividend of $0.68 during the fiscal year 2024. Comparatively, we paid dividends of $1.94 and $1.00 per share in 2023 and 2022. Total dividends paid were $168.5 million, $201.5 million and $107.4 million in fiscal years 2024, 2023 and 2022, respectively.

Debt Issuance Proceeds and Costs On September 17, 2024, we issued $1.2 billion net aggregate principal amount of senior notes. Debt issuance costs paid in fiscal year 2024 were $22.9 million, of which $9.6 million relates to the senior notes issued in the current year and $13.3 million relates to other financing arrangements. For additional information regarding debt issuance and related costs, refer to Note 6—Debt to the Consolidated Financial Statements.

Repurchase of Shares The Company has an evergreen authorization from the Board of Directors for the repurchase of up to four million common shares in any calendar year. The repurchases may be made using our cash and cash equivalents or other available sources. During the fiscal year ended September 30, 2024, we repurchased 1.4 million common shares at an aggregate cost of $51.6 million, including accrued excise tax of $0.3 million, resulting in a net cash outflow of $51.3 million. During the fiscal year ended September 30, 2023, we repurchased 6.5 million common shares at an aggregate cost of $249.0 million, including excise tax of $1.8 million, resulting in a net cash outflow $247.2 million. During the fiscal year ended September 30, 2022, we repurchased 3.2 million common shares at an aggregate cost of $77.0 million.

Senior Notes Issued in Fiscal Year 2024

On September 17, 2024, we completed a private offering of $1.25 billion aggregate principal amount of the Notes, comprised of the following tranches: $350.0 million aggregate principal amount of 4.65 percent senior notes due 2027 issued at a price equal to 99.958 percent of their face value, $350.0 million aggregate principal amount of 4.85 percent senior notes due 2029 issued at a price equal to 99.883 percent of their face value and $550.0 million aggregate principal amount of 5.50 percent senior notes due 2034 issued at a price equal to 99.670 percent of their face value.

The Company intends to use the net proceeds, together with the proceeds of its term loan credit facility (discussed below) and cash on hand, to finance the purchase price for the Acquisition, to repay certain of KCA Deutag’s outstanding indebtedness, and to pay related fees and expenses.

The Notes are subject to a “special mandatory redemption,” which would require the Company to redeem the Notes at a special mandatory redemption price equal to 101.0 percent of the principal amount of the Notes to be redeemed plus accrued and unpaid interest thereon in the event that (i) the consummation of the Acquisition does not occur on or before October 25, 2025, (or such later date as the Company may agree to extend the "Long Stop Date" under the Purchase Agreement), (ii) the Purchase Agreement is terminated without the consummation of the Acquisition or (iii) if the Company otherwise notifies the trustee of the Notes that it will not pursue the consummation of the Acquisition.

In connection with the issuance of the Notes, the Company also entered into a registration rights agreement, dated as of September 17, 2024 (the “Registration Rights Agreement”), with the initial purchasers of the Notes named therein. Under the Registration Rights Agreement, the Company agreed, among other things, to: (i) file a registration statement (the “Exchange Offer Registration Statement”) with the SEC to register an offer to exchange each series of the Notes for freely tradable notes having terms identical in all material respects to each such series of Notes (the “Registered Exchange Offer”); (ii) use commercially reasonable efforts to cause the Exchange Offer Registration Statement to become effective under the Securities Act not later than the later of (x) the 30th day following the Company’s filing of a Current Report on Form 8-K or an amendment thereto including the financial statements of KCA Deutag and pro forma financial information related to the Company’s acquisition of KCA Deutag required by Items 9.01(a) and 9.01(b) of Form 8-K (the “KCA Deutag Financials Form 8-K”) and (y) June 16, 2025; and (iii) use commercially reasonable efforts to cause the Registered Exchange Offer to be completed not later than the later of (x) the 60th day following the Company’s filing of the KCA Deutag Financials Form 8-K and (y) July 14, 2025 (the “Exchange Offer Closing Deadline”), subject to certain limitations.

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If, among other events, the Registered Exchange Offer is not completed by the Exchange Offer Closing Deadline, then special additional interest will accrue in an amount equal to 0.25 percent per annum of the principal amount of the Notes, from and including the date on which such default shall occur to but excluding the date on which such default is cured.

The indenture governing the Notes contains certain covenants that, among other things, limit the ability of the Company and its subsidiaries to incur certain liens; engage in sale and lease-back transactions; and consolidate, merge or transfer all or substantially all of the assets of the Company. The indenture governing the Notes also contains customary events of default with respect to the Notes.

Senior Notes Extinguished in Fiscal Year 2022

On December 20, 2018, we issued approximately $487.1 million in aggregate principal amount of the 4.65 percent senior notes due 2025 (the "2025 Notes"). On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 2025 Notes at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. The Company financed the redemption of the 2025 Notes with the net proceeds from the offering of the 2031 Notes (discussed below), together with cash on hand. The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021.

On October 27, 2021, we redeemed all of the outstanding 2025 Notes. As a result, the associated make-whole premium of $56.4 million and the write off of the unamortized discount and debt issuance costs of $3.7 million were recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 debt extinguishment and recorded in Loss on extinguishment of debt on our Consolidated Statements of Operations during the fiscal year ended September 30, 2022.

Senior Notes Issued in Fiscal Year 2021

On September 29, 2021, we issued $550.0 million aggregate principal amount of the 2.90 percent senior notes due 2031 (the "2031 Notes") in an offering to persons reasonably believed to be qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act. Interest on the 2031 Notes is payable semi-annually on March 29 and September 29 of each year, commencing on March 29, 2022.

In June 2022, we settled a registered exchange offer (the “2022 Registered Exchange Offer”) to exchange the 2031 Notes for new, SEC-registered notes that are substantially identical to the terms of the 2031 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 2031 Notes do not apply to the new notes. All of the 2031 Notes were exchanged in the 2022 Registered Exchange Offer.

The indenture governing the 2031 Notes contains certain covenants that, among other things and subject to certain exceptions, limit the ability of the Company and its subsidiaries to incur certain liens; engage in sale and lease-back transactions; and consolidate, merge or transfer all or substantially all of the assets of the Company. The indenture governing the 2031 Notes also contains customary events of default with respect to the 2031 Notes.

Term Loan Credit Agreement

On August 14, 2024, the Company entered into the Term Loan Credit Agreement, dated as of August 14, 2024, among the Company, MSSF as administrative agent, and the other lenders party thereto. Under the Term Loan Credit Agreement, the Company may obtain unsecured term loans in a single delayed draw in an aggregate principal amount up to $400.0 million. The Term Loan Credit Agreement matures at the two-year anniversary of the funding of the term loans unless earlier terminated pursuant to the terms of the Term Loan Credit Agreement. We expect to use the proceeds from the Term Loan Credit Agreement, together with the net proceeds from the sale of Notes and cash on hand, to finance the purchase price for the Acquisition, to repay certain of KCA Deutag's outstanding indebtedness, and to pay related fees and expenses.

The benchmark rate is the Secured Overnight Financing Rate ("SOFR"). We can elect to borrow at either an adjusted SOFR rate or an adjusted base rate, plus an applicable margin. The adjusted SOFR rate is the forward-looking term rate based on SOFR for the applicable tenor of one, three, or six months, plus 0.10 percent per annum. The adjusted base rate is a fluctuating rate per annum equal to the highest of (i) the administrative agent's prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) the one-month adjusted SOFR rate plus 1.0 percent. We also pay a commitment fee on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined based on the debt rating for senior unsecured debt of the Company, as determined by Moody’s and Standard & Poor’s. The applicable margin for SOFR borrowings and adjusted base rate borrowings ranges from 1.0 percent to 1.625 percent per annum and zero to 0.625 percent per annum, respectively. Commitment fees for both rates range from 0.10 percent to 0.250 percent per annum. Based on the unsecured debt rating of the Company on September 30, 2024, the spread over SOFR would have been 1.375 percent had borrowings been outstanding under the Term Loan Credit Agreement and commitment fees would have been 0.175 percent.

The funding of the term loans had not occurred as of September 30, 2024.

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Bridge Loan Facility

In connection with, and concurrently with the entry into, the Purchase Agreement, the Company entered into a debt commitment letter dated July 25, 2024 with MSSF, pursuant to which MSSF has committed, subject to satisfaction of standard conditions, to provide the Company with an unsecured 364-day bridge loan facility in an aggregate principal amount of approximately $2.0 billion (the “Bridge Loan Facility”) the proceeds of which, if drawn, would have been used to fund the Acquisition. On October 15, 2024, the remaining commitments under the Bridge Loan Facility were reduced such that there were no remaining commitments available, and the Bridge Loan Facility was automatically terminated in accordance with its terms. For additional information regarding the Bridge Loan Facility, refer to Note 6—Debt to the Consolidated Financial Statements.

Revolving Credit Facility

On August 14, 2024, the Company entered into the Amended Credit Facility with the Revolving Credit Agreement Lenders, the issuing lenders party thereto and Wells Fargo, as administrative agent, swing line lender and issuing lender, which amended and restated the Credit Agreement, dated as of November 13, 2018 (as amended through Amendment No. 2 to the Credit Agreement dated as of March 8, 2022, the “Existing Credit Agreement”), among the Company, the lenders party thereto and Wells Fargo, as administrative agent, swing line lender and issuing lender.

Under the terms of the Amended Credit Facility, the Company may obtain unsecured revolving loans in an aggregate principal amount not to exceed $950.0 million outstanding at any time (the “Revolving Credit Facility”). $775.0 million of the revolving commitments under the Amended Credit Facility expire on November 12, 2028 and $175.0 million of the revolving commitments mature on November 10, 2027 (the “Stated Maturity Date”), but the Company may request two one-year extensions of the Stated Maturity Date, subject to satisfaction of certain conditions. Commitments under the Amended Credit Facility may be increased by up to $100.0 million, subject to the agreement of the Company and new or existing Revolving Credit Agreement Lenders.

The proceeds of the loans made under the Amended Credit Facility may be used by the Company for (i) working capital and other general corporate purposes, (ii) for the payment of fees and expenses related to the entering into of the Amended Credit Facility and the other credit documents and (iii) for the refinancing of the extensions of credit under the Existing Credit Agreement.

The benchmark rate is the SOFR. We can elect to borrow at either an adjusted SOFR rate or an adjusted base rate, plus an applicable margin. The adjusted SOFR rate is the forward-looking term rate based on SOFR for the applicable tenor of one, three, or six months, plus 0.10 percent per annum. The adjusted base rate is a fluctuating rate per annum equal to the highest of (i) the administrative agent's prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) the one-month adjusted SOFR rate plus 1.0 percent. We also pay a commitment fee on the unused balance of the facility. Borrowing spreads as well as commitment fees are determined based on the debt rating for senior unsecured debt of the Company, as determined by Moody’s and Standard & Poor’s. The applicable margin for SOFR borrowings and adjusted base rate borrowings ranges from 0.875 percent to 1.500 percent per annum and zero to 0.50 percent per annum, respectively. Commitment fees for both rates range from 0.075 percent to 0.200 percent per annum. Based on the unsecured debt rating of the Company on September 30, 2024, the spread over SOFR would have been 1.250 percent had borrowings been outstanding under the Amended Credit Facility and commitment fees would have been 0.150 percent. There is a financial covenant in the Amended Credit Facility that requires us to maintain a total funded debt to total capitalization ratio of less than or equal to 55.0 percent. The Amended 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, 2024, there were no borrowings or letters of credit outstanding, leaving $950.0 million available to borrow under the Amended Credit Facility.

As of September 30, 2024, we had $160.0 million in uncommitted bilateral credit facilities, for the purpose of obtaining the issuance of international letters of credit, bank guarantees, and performance bonds. Of the $160.0 million, $39.7 million was outstanding as of September 30, 2024. Separately, we had $5.0 million in standby letters of credit and bank guarantees outstanding. In total, we had $44.7 million outstanding as of September 30, 2024.

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, 2024, we were in compliance with all debt covenants.

Future Cash Requirements

Our operating cash requirements, scheduled debt repayments, interest payments, any declared dividends, and estimated capital expenditures for fiscal year 2025 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. If needed, we may decide to obtain additional funding from our $950.0 million Amended Credit Facility. Our indebtedness under our unsecured senior notes totaled $1.8 billion at September 30, 2024 and comprised with the following maturities: $350.0 million due December 2027, $350.0 million due December 2029, $550.0 million due September 2031, and $550.0 million due December 2034.

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On July 25, 2024, H&P and certain of its wholly owned subsidiaries entered into the Purchase Agreement to acquire KCA Deutag for total cash consideration of approximately $2.0 billion, which consists of the $0.9 billion unadjusted share purchase price and $1.1 billion to contemporaneously repay or redeem certain of KCA Deutag's existing debt upon consummation of the Acquisition. Total consideration is subject to adjustment as set forth in the Purchase Agreement. The transaction is expected to close prior to calendar 2024 year end, subject to customary closing conditions and regulatory approvals. We expect to use the proceeds from the Term Loan Credit Agreement, together with the net proceeds from the sale of the Notes and cash on hand, to finance the purchase price for the Acquisition, to repay certain of KCA Deutag's outstanding indebtedness, and to pay related fees and expenses.

As of September 30, 2024, we had a $495.5 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 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.

At September 30, 2024, we have recorded approximately $0.8 million of unrecognized tax benefits, interest, and penalties. We cannot predict with certainty if we will achieve ultimate resolution of any additional uncertain tax positions associated with our U.S. and international operations resulting in any additional material increases or decreases of our unrecognized tax benefits for the next twelve months.

The long‑term debt to total capitalization ratio was 38.2 percent and 16.6 percent as of September 30, 2024 and 2023. For additional information regarding debt agreements, refer to Note 6—Debt to the Consolidated Financial Statements.

There were no other significant changes in our financial position since September 30, 2023.

Material Commitments

Our contractual obligations as of September 30, 2024 are summarized in the table below:

(1)Interest on fixed-rate unsecured senior notes was estimated based on principal maturities. See Note 6—Debt to our Consolidated Financial Statements.

(2)See Note 4—Leases to our Consolidated Financial Statements.

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

Critical Accounting Policies and Estimates

Accounting policies that we consider significant are summarized in Note 2—Summary of Significant Accounting Policies, Related Risks and Uncertainties to our Consolidated Financial Statements included in Part II, Item 8—"Financial Statements and Supplementary Data" of this Form 10-K. The preparation of our financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. These estimates and assumptions are evaluated on an ongoing 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.

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Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are capitalized at cost, while maintenance and repairs are expensed as incurred. 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. Assets held-for-sale are reported at the lower of the carrying amount or fair value less estimated costs to sell. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation or result in abandonments. For the fiscal years presented in this Form 10-K, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.

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

Management assesses the potential impairment of our long‑lived assets and finite-lived intangibles whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, change in technology and/or overall changes in general market conditions. If a review of the long‑lived assets and finite-lived intangibles indicates that the carrying value of certain of these assets or asset groups is more than the estimated undiscounted future cash flows, an impairment charge is made, as required, to adjust the carrying value to the estimated fair value. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig’s marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics including utilization. The fair value of drilling rigs is determined based upon either an income approach using estimated discounted future cash flows, a market approach considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors, a cost approach utilizing new reproduction costs 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.

See Note 5—Goodwill and Intangible Assets for additional discussion of goodwill and intangible assets.

Self‑Insurance Accruals

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.

We self‑insure a significant portion of expected losses relating to workers’ compensation, general liability, employer’s liability, auto liability, and certain other insurance coverages. Generally, deductibles range from $1 million to $10 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events but there can be no assurance that such coverage will apply or be adequate in all circumstances. Estimates are recorded for incurred outstanding liabilities for workers’ compensation and other casualty claims. Retained losses under worker's compensation, general, automobile, and employer's liability policies are estimated and accrued based upon our estimates of the aggregate liability for claims incurred. These estimates are based on adjusters’ estimates, our historical loss experience and statistical methods commonly used within the insurance industry that we believe are reliable.

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We also engage a third-party actuary to perform a periodic review of our 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 companies finance a significant portion of the physical damage risk on company‑owned drilling rigs as well as casualty deductibles and other risk retentions. An actuary reviews the loss reserves retained by the Company and the Captives on an annual basis.

Revenue Recognition

Drilling services revenues are primarily comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. With most drilling contracts, we receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenue associated with the mobilization and demobilization of our drilling 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. The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced or no payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Direct costs incurred for the mobilization, are deferred and recognized on a straight-line basis as the drilling service is provided. While costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.

We also act as a principal for certain reimbursable services and auxiliary equipment provided by us to our clients, for which we incur costs and earn revenues. Many of these costs are variable, or dependent upon the activity that is performed each day under the related contract. Accordingly, reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs during the period to which they relate within the series of distinct time increments. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

Income Taxes

Deferred income taxes are accounted for under the liability method, which takes into account the differences between the basis of the assets and liabilities for financial reporting purposes and amounts recognized for income tax purposes. Our net deferred tax liability balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions. Included in our net deferred tax liability balance are deferred tax assets that are assessed for realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates.

In addition, we operate in several countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions we believe have a greater than 50 percent likelihood of being sustained. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments.

New Accounting Standards

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

Non-GAAP Measurements

Direct Margin

Direct margin is considered a non-GAAP metric. We define "Direct margin" as operating revenues less direct operating expenses. Direct margin is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. Direct margin is not a substitute for financial measures prepared in accordance with GAAP and should therefore be considered only as supplemental to such GAAP financial measures.

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The following table reconciles direct margin to segment operating income, which we believe is the financial measure calculated and presented in accordance with GAAP that is most directly comparable to direct margin.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Part I of this Form 10‑K as well as the Consolidated Financial Statements and related notes thereto included in Part II, Item 8— “Financial Statements and Supplementary Data” of this Form 10‑K. Our future operating results may be affected by various trends and factors which are beyond our control. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Form 10-K under “Cautionary Note regarding Forward-Looking Statements” and Item 1A— “Risk Factors.” Accordingly, past results and trends should not be used by investors to anticipate future results or trends.

Executive Summary

Helmerich & Payne, Inc. (“H&P,” which, together with its subsidiaries, is identified as the “Company,” “we,” “us,” or “our,” except where stated or the context requires otherwise) through its operating subsidiaries provides performance-driven drilling solutions and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. As of September 30, 2023, our drilling rig fleet included a total of 262 drilling rigs. Our reportable operating business segments consist of the North America Solutions segment with 233 rigs, the Offshore Gulf of Mexico segment with seven offshore platform rigs and the International Solutions segment with 22 rigs as of September 30, 2023. At the close of fiscal year 2023, we had 164 active contracted rigs, of which 91 were under a fixed-term contract and 73 were working well-to-well, compared to 192 contracted rigs at September 30, 2022. Our long-term strategy remains focused on innovation, technology, safety, operational excellence and reliability. As we move forward, we believe that our advanced uniform rig fleet, technology offerings, financial strength, contract backlog and strong customer and employee base position us very well to respond to continued cyclical and often times volatile market conditions and to take advantage of future opportunities.

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Market Outlook

Our revenues are primarily derived from the capital expenditures of companies involved in the exploration, development and production of crude oil and natural gas (“E&Ps”). Generally, the level of capital expenditures is dictated by capital budgets set to achieve respective production targets in relation to 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.

Our drilling services operations are organized into the following reportable operating segments: North America Solutions, Offshore Gulf of Mexico, and International Solutions. With respect to North America Solutions, the resurgence of oil and natural gas production coming from the United States brought about by unconventional shale drilling for oil has significantly impacted the supply of oil and natural gas and the type of rig utilized in the U.S. land drilling industry.

The technical requirements of drilling longer lateral unconventional shale wells often necessitate the use of rigs that 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.

There is a strong customer preference for super-spec rigs not only due to the higher rig specifications that enable more technical drilling but also due to the drilling efficiencies gained in utilizing a super-spec rig. As a result, there has been a structural decline in the use of non-super-spec rigs across the industry. We are the largest provider of super-spec rigs in the industry and, accordingly, we believe we are well positioned to respond to various market conditions.

Historically there has been a strong correlation between crude oil and natural gas prices and the demand for drilling rigs with the rig count increasing and decreasing with the up and down movements in commodity prices. While that correlation remains for a segment of the market, beginning in 2021, a portion of rig activity has not moved in tandem with crude oil prices to the same extent as a large portion of our customers instituted a more disciplined approach to their operations and capital spending in order to enhance their own financial returns. Those customers established capital budgets based upon commodity price assumptions for the upcoming year and adhered to them, not adjusting activity plans as commodity prices moved.

The capital budgets for calendar year 2024 have not yet been established by many of our customers; however, based upon the crude oil and natural gas pricing environment and many of our customers' desire to at least maintain their current production levels, we expect the level of capital spending and activity in calendar year 2024 to be similar to that experienced in calendar year 2023. The overall demand for super-spec rigs in the U.S. remains relatively strong and while some readily available idle super-spec capacity exists in the market, it is not to a level that has materially impacted pricing as it could be quickly reabsorbed into the market. This supply-demand dynamic combined with the value proposition we provide our customers through our drilling expertise, high-quality FlexRig® fleet, and automation technology is expected to result in an improvement in our underlying contract economics.

With regards to our North America Solutions segment, volatility in natural gas prices and the related reduced rig demand contributed to an increased level of rig releases in the market during the first half of calendar year 2023. During the second half of calendar year 2023, other non-commodity price related factors, such as customer capital budgets, drilling plans, productions levels and customer consolidations, also led some customers to release rigs as well. Heading into our fiscal year 2024, we expect our rig activity to increase modestly during the first half of the fiscal year as customers reset their capital budgets for 2024 and will likely remain at a relatively stable level during the back half of the fiscal year. This is similar to the rig activity patterns we have experienced during the last few years as well. During fiscal year 2023, the Company employed a fiscally prudent approach to deploying capital and prioritizing economic margins over rig utilization, and we plan to maintain this approach in fiscal 2024. Furthermore, we still believe the supply and demand dynamics surrounding our North America Solutions segment remain constructive for future activity and pricing levels.

Collectively, our other business segments, Offshore Gulf of Mexico and International Solutions, are exposed to the same macro commodity price environment affecting our North America Solutions segment; however, activity levels in the International Solutions segment are also subject to other various geopolitical and financial factors specific to the countries of our operations. During fiscal 2024, we plan to continue to devote capital to our international expansion strategy. While we understand this strategy will take time and capital to execute, we believe it is important in terms of growth and diversification for the Company. Currently, activity levels in the International Solutions and Offshore Gulf of Mexico business segments look to remain relatively steady at current levels for the foreseeable future.

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Over the past two years, the Company has experienced inflationary pressures related to labor and consumable inventory and more recently as a result of cost-acceleration related to running our rig fleet harder to achieve the well designs, lateral lengths and drilling efficiencies our customers demand. The inflationary forces have abated, and the financial impacts were partially mitigated by pass-through mechanisms in our contracts. However, the performance and efficiency gains we achieve require us to continue to push the service intensity of our rigs and equipment. Accordingly, we expect operational expenses to remain at elevated levels compared to recent years. Additionally, we are also experiencing inflationary pressures in our non-operational expenses particularly around labor and third-party services. As a consequence of these pressures, we are projecting an increase in our selling, general and administrative expenses during fiscal 2024.

Recent Developments

Credit Facility Extension

On February 10, 2023, lenders with $680.0 million of commitments under the 2018 Credit Facility exercised their option to extend the maturity of the 2018 Credit Facility from November 11, 2026 to November 12, 2027. The remaining $70.0 million of commitments under the 2018 Credit Facility will expire on November 13, 2024, unless extended by the applicable lender before such date.

Investment in Tamboran

In October 2022, we made a $14.1 million equity investment, representing 106.0 million common shares in Tamboran Resources Limited, a publicly traded company on the Australian Securities Exchange Ltd under the ticker "TBN." Tamboran is focused on playing a constructive role in the global energy transition towards a lower carbon future, by developing a significantly low CO2 gas resource within Australia's Beetaloo Sub-basin. During the year ended September 30, 2023, we recognized a loss of $4.2 million, recorded within Gain (loss) on investment securities on our Consolidated Statements of Operations, as a result of the change in fair value of the investment during the period. Concurrent with the investment agreement, we entered into a fixed-term drilling services agreement with Tamboran. During the fourth fiscal quarter of 2023, drilling services commenced. See Note 2—Summary of Significant Accounting Policies, Related Risks and Uncertainties to our Consolidated Financial Statements for additional related party disclosures.

Significant Lease Commenced

During the fiscal year ended September 30, 2023, we entered into a lease agreement to relocate our Tulsa corporate headquarters to a new office space. This lease commenced during the fourth fiscal quarter of 2023 and resulted in a $17.6 million increase to right-of-use assets and lease liability on our Consolidated Balance Sheets. In addition, we began amortizing the right of use asset over the initial lease term of approximately 12 years.

Contract Backlog

Drilling contract backlog is the expected future dayrate revenue from executed contracts. We calculate backlog as the total expected revenue from fixed-term contracts and do not include any anticipated contract renewals or expected performance bonuses as part of its calculation. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. In addition to depicting the total expected revenue from fixed-term contracts, backlog is indicative of expected future cash flow that the Company expects to receive regardless of whether a customer honors the fixed-term contract to expiration of a contract or decides to terminate the contract early and pay an early termination payment. In the event of an early termination payment, the timing of the recognition of backlog and the total amount of revenue may differ; however, the overall associated gross margin is preserved. As such, management finds backlog a useful metric for future planning and budgeting, whereas investors consider it useful in estimating future revenue and cash flows of the Company. As of September 30, 2023 and 2022, our contract drilling backlog was $1.4 billion and $1.2 billion, respectively. The increase in backlog at September 30, 2023 from 2022 is primarily due to an increase in the number of contracts executed under FlexPool agreements. Approximately 33.8 percent of the September 30, 2023 total backlog is reasonably expected to be fulfilled in fiscal year 2025 and thereafter.

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The following table sets forth the total backlog by reportable segment as of September 30, 2023 and 2022, and the percentage of the September 30, 2023 backlog reasonably expected to be fulfilled in fiscal year 2025 and thereafter:

The early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. In some limited circumstances, such as sustained unacceptable performance by us, no early termination payment would be paid to us. Early terminations could cause the actual amount of revenue earned to vary from the backlog reported. See Item 1A—"Risk Factors—Our current backlog of drilling services and solutions revenue may decline and may not be ultimately realized as fixed‑term contracts and may, in certain instances, be terminated without an early termination payment” within this Form 10-K regarding fixed term contract risk. Additionally, see Item 1A—"Risk Factors—The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, could have a material adverse effect on our business, financial condition and results of operations" within this Form 10-K.

Results of Operations for the Fiscal Years Ended September 30, 2023 and 2022

Consolidated Results of Operations

Net Income We recorded net income of $434.1 million ($4.16 per diluted share) for the fiscal year ended September 30, 2023 compared to net income of $7.0 million ($0.05 per diluted share) for the fiscal year ended September 30, 2022.

Operating Revenue Consolidated operating revenues were $2.9 billion and $2.1 billion during fiscal years 2023 and 2022, respectively. The $0.8 billion increase in fiscal year 2023 from fiscal year 2022 was primarily driven by an increase in average rig pricing and activity levels in our North America Solutions segment and increased activity levels in our International Solutions segment. Refer to segment results below for further details.

Direct Operating Expenses, Excluding Depreciation and Amortization Direct operating expenses in fiscal year 2023 were $1.7 billion, compared to direct operating expenses of $1.4 billion in fiscal year 2022. The increase in fiscal year 2023 from fiscal year 2022 was primarily attributable to the previously mentioned higher activity levels as well as a North America Solutions wage increase that became effective at the end of fiscal year 2022.

Depreciation and Amortization Depreciation and amortization expense was $382.3 million in fiscal year 2023 and $403.2 million in fiscal year 2022. The decrease is reflective of lower capital expenditures over the last several years. Depreciation and amortization includes amortization of intangible assets of $6.6 million and $7.2 million in fiscal years 2023 and 2022, and abandonments of equipment of $3.3 million and $6.6 million in fiscal years 2023 and 2022, respectively.

Selling, General and Administrative Expense Selling, general and administrative expenses increased to $206.7 million in the fiscal year ended September 30, 2023 compared to $182.4 million in the fiscal year ended September 30, 2022. The $24.3 million increase in fiscal year 2023 is primarily due to an increase in professional fees of $12.0 million and an increase in labor and labor-related expenses of $8.6 million.

Asset Impairment Charges During the fiscal year ended September 30, 2023, the Company initiated a plan to decommission, scrap and/or sell certain assets including four international FlexRig® drilling rigs, four international conventional drilling rigs, and additional equipment. The aggregate net book value of these assets of $13.2 million was written down to their estimated scrap value of $1.1 million, resulting in non-cash impairment charges of $12.1 million for the fiscal year ended September 30, 2023, of which $8.1 million of the charge is recorded within the International Solutions segment. The remaining $4.0 million is recorded within the North America Solutions segment. The impairment charge was recorded in the Consolidated Statement of Operations for the fiscal year ended September 30, 2023. Comparatively, during the fiscal year ended September 30, 2022, we identified various assets that met the asset held-for-sale criteria and were reclassified as assets held-for-sale within our North America Solutions and International Solutions segments, which resulted in a non-cash impairment charge of $4.4 million, of which $2.5 million of the charge is recorded within the International Solutions segment. The remaining $1.9 million is recorded within the North America Solutions segment. The impairment charge was recorded in the Consolidated Statement of Operations for the fiscal year ended September 30, 2022.

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Gain on Investment Securities During the fiscal year ended September 30, 2023, we recognized an aggregate gain of $11.3 million on investment securities. This gain was mainly comprised of a $27.4 million gain on our equity investment in ADNOC Drilling, partially offset against a $4.2 million loss on our investment in Tamboran; both of which were a result of fluctuations in the fair market value of the stocks. Additionally, the aggregate gain was offset by a $12.2 million loss on investment recognized during the fiscal year ended September 30, 2023 as a result of a Blue Chip Swap transaction that occurred during the period. See—Note 2—Summary of Significant Accounting Policies, Related Risks and Uncertainties—International Solutions Drilling Risks for additional information related to the Blue Chip Swap. During the fiscal year ended September 30, 2022, we recognized an aggregate gain of $57.9 million on investment securities. This gain was mainly comprised of a $47.4 million gain on our equity investment in ADNOC Drilling, caused by an increase in the fair market value of the stock, and a gain of $8.2 million on the sale of our equity investment in Schlumberger, Ltd.

Interest and Dividend Income Interest and dividend income was $28.4 million and $18.1 million in fiscal years 2023 and 2022, respectively. The increase in interest and dividend income in fiscal year 2023 was primarily due to higher market interest rates.

Interest Expense Interest expense totaled $17.3 million in fiscal year 2023 and $19.2 million in fiscal year 2022. The decrease in interest expense is primarily attributable to the fiscal year 2022 interest expense associated with our 4.65% Senior Notes due 2025 which were redeemed on October 27, 2021.

Income Taxes We had an income tax expense of $159.3 million in fiscal year 2023 compared to an income tax expense of $24.4 million in fiscal year 2022. The effective income tax rate was 26.8 percent in fiscal year 2023 compared to 77.8 percent in fiscal year 2022. The effective rates differ from the U.S. federal statutory rate (21.0 percent for the fiscal years 2023 and 2022) primarily due to non-deductible permanent items, the foreign derived intangible income deduction (in fiscal year 2022), state and foreign income taxes, and adjustments to the deferred state income tax rate. Additionally, the effective income tax rate is higher in fiscal year 2022 as the low level of net income before tax increases the impact of the rate differences.

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 7—Income Taxes to our Consolidated Financial Statements for additional income tax disclosures.

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North America Solutions

The following table presents certain information with respect to our North America Solutions reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 365 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues were $2.5 billion and $1.8 billion in fiscal year 2023 and 2022, respectively. Operating revenues increased $0.7 billion in fiscal year 2023 primarily due to higher pricing and a 3.6 percent increase in activity levels.

Direct Operating Expenses Direct operating expenses increased to $1.4 billion during the fiscal year ended September 30, 2023 as compared to $1.2 billion during the fiscal year ended September 30, 2022. This increase was primarily driven by an increase of $137.3 million in labor and labor-related expenses driven by higher activity levels and increased field wages beginning in late September 2022. Additionally, materials and supplies expense increased by $19.3 million, which was also primarily driven by higher activity levels.

Depreciation and Amortization Depreciation and amortization expense decreased to $354.0 million during the fiscal year ended September 30, 2023 as compared to $375.3 million during the fiscal year ended September 30, 2022. The decrease is reflective of lower capital expenditures over the last several years.

Selling, General and Administrative Expenses Selling, general and administrative expenses increased to $58.4 million during the fiscal year ended September 30, 2023 as compared to $43.8 million during the fiscal year ended September 30, 2022. This increase was largely driven by a $10.8 million increase in professional services fees.

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Offshore Gulf of Mexico

The following table presents certain information with respect to our Offshore Gulf of Mexico reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 365 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues were $130.2 million and $125.5 million in the fiscal year ended September 30, 2023 and 2022, respectively. The 3.8 percent increase in operating revenue was largely driven by pricing increases and wage increase pass-throughs which occurred in the latter portion of fiscal year 2022 partially offset by the mix of rigs being on lower standby or mobilization rates as opposed to working at full rates.

Direct Operating Expenses Direct operating expenses increased to $96.8 million during the fiscal year ended September 30, 2023 as compared to $90.4 million during the fiscal year ended September 30, 2022. The increase was primarily driven by the factors described above.

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International Solutions

The following table presents certain information with respect to our International Solutions reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 365 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues were $212.6 million and $136.1 million in the fiscal years ended September 30, 2023 and 2022, respectively. The $76.5 million increase in fiscal year 2023 from fiscal year 2022 was primarily driven by a 57.7 percent increase in activity levels. Additionally, during the year ended September 30, 2022, we recognized $16.4 million in revenue related to the settlement of a contract drilling dispute related to drilling services provided from fiscal year 2016 through 2019 with YPF S.A. Refer to Note 9 - Revenue from Contracts with Customers for additional details.

Operating Expenses Direct operating expenses increased to $187.3 million during the fiscal year ended September 30, 2023 as compared to $120.8 million during the fiscal year ended September 30, 2022. This increase was primarily driven by an increase of $33.3 million in labor and labor-related expense and an increase of $17.6 million in materials and supplies as a result of higher activity levels.

Asset Impairment Charges During the fiscal year ended September 30, 2023, the Company initiated a plan to decommission and scrap four international FlexRig® drilling rigs and four conventional drilling rigs located in Argentina that are not suitable for unconventional drilling. As a result, these rigs were reclassified to Assets held-for-sale on our Consolidated Balance Sheets. The rigs’ aggregate net book value of $8.8 million was written down to the estimated scrap value of $0.7 million, which resulted in a non-cash impairment charge of $8.1 million recorded in Asset impairment charges within our Consolidated Statement of Operations during the fiscal year ended September 30, 2023. During the fiscal year ended September 30, 2022, we identified two international FlexRig® drilling rigs that met the asset held-for-sale criteria and were reclassified to Assets held-for-sale on our Consolidated Balance Sheets. This resulted in a non-cash impairment charge of $2.5 million recorded in Asset impairment charges within our Consolidated Statement of Operations during the fiscal year ended September 30, 2022, as the rigs aggregate net book value of $3.4 million exceeded the fair value of the rigs less estimated cost to sell of $0.9 million.

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Other Operations

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

Operating Revenues We continue to use our Captive insurance companies to insure the deductibles for our domestic workers’ compensation, general liability, automobile liability claims programs, and medical stop-loss program and to insure the deductibles from the Company's international casualty and rig property programs. Intercompany premium revenues recorded by the Captives during the fiscal years ended September 30, 2023 and 2022 amounted to $67.4 million and $57.0 million, respectively, which were eliminated upon consolidation.

Direct Operating Expenses Direct operating expenses consisted primarily of $12.5 million and $7.0 million in adjustments to accruals for estimated losses allocated to the Captives and rig and casualty insurance premiums of $39.7 million and $35.6 million during the fiscal years ended September 30, 2023 and 2022, respectively. The change to accruals for estimated losses is primarily due to actuarial valuation adjustments by our third-party actuary.

Results of Operations for the Fiscal Years Ended September 30, 2022 and 2021

A discussion of our results of operations for the fiscal year ended September 30, 2022 compared to the fiscal year ended September 30, 2021 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, 2022, filed with the Securities and Exchange Commission ("SEC") on November 16, 2022.

Liquidity and Capital Resources

Sources of Liquidity

Our sources of available liquidity include existing cash balances on hand, cash flows from operations, and availability under the 2018 Credit Facility. Our liquidity requirements include meeting ongoing working capital needs, funding our capital expenditure projects, paying dividends declared, and repaying our outstanding indebtedness. Historically, we have financed operations primarily through internally generated cash flows. During periods when internally generated cash flows are not sufficient to meet liquidity needs, we may utilize cash on hand, borrow from available credit sources, access capital markets or sell our investments. Likewise, if we are generating excess cash flows or have cash balances on hand beyond our near-term needs, we may return cash to shareholders through dividends or share repurchases, or 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, highly rated corporate bonds and commercial paper, certificates of deposit and money market funds. However, in some international locations we may make short-term investments that are less conservative, as equivalent highly rated investments are unavailable. See—Note 2—Summary of Significant Accounting Policies, Related Risks and Uncertainties—International Solutions Drilling Risks.

We may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity as necessary, fund our additional purchases, exchange or redeem senior notes, or repay any amounts under the 2018 Credit Facility. Our ability to access the debt and equity capital markets depends on a number of factors, including our credit rating, market and industry conditions and market perceptions of our industry, general economic conditions, our revenue backlog and our capital expenditure commitments.

Cash Flows

Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling rigs under contract, the revenue we receive under those contracts, the efficiency with which we operate our drilling rigs, the timing of collections on outstanding accounts receivable, the timing of payments to our vendors for operating costs, and capital expenditures. As our revenues increase, operating net working capital is typically a use of capital, while conversely, as our revenues decrease, operating net working capital is typically a source of capital. To date, general inflationary trends have not had a material effect on our operating margins or cash flows as we have been able to offset these cumulative cost trends with rate increases.

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As of September 30, 2023 and 2022, we had cash and cash equivalents of $257.2 million and $232.1 million and short-term investments of $93.6 million and $117.1 million, respectively. Our cash flows for the fiscal years ended September 30, 2023, 2022 and 2021 are presented below:

Operating Activities

Our operating net working capital (non-GAAP) as of September 30, 2023, 2022, and 2021 is presented below:

Cash flows provided by operating activities were approximately $833.7 million, $233.9 million, and $136.4 million for the fiscal year ended September 30, 2023, 2022, and 2021 respectively. The increase in cash provided by operating activities between fiscal years 2023 and 2022 is primarily driven by higher activity and pricing. The increase in cash provided by operating activities between fiscal years 2022 and 2021 was primarily driven by higher activity and pricing, and is partially offset by changes in operating net working capital. For the purpose of understanding the impact on our cash flows from operating activities, operating net working capital is calculated as current assets, excluding cash and cash equivalents, short-term investments, assets held-for-sale, and prepaid property, plant and equipment, less current liabilities, excluding dividends payable, short-term debt and advance payments for sale of property, plant and equipment.

Operating net working capital was $239.6 million, $271.8 million and $129.9 million as of September 30, 2023, 2022 and 2021, respectively. This metric is considered a non-GAAP measure of the Company's liquidity. The Company considers operating net working capital to be a supplemental measure for presenting and analyzing trends in our cash flows from operations over time. Likewise, the Company believes that operating net working capital is useful to investors because it provides a means to evaluate the operating performance of the business using criteria that are used by our internal decision makers.

Investing Activities

Capital Expenditures Our capital expenditures were $395.5 million, $250.9 million and $82.1 million in fiscal years 2023, 2022 and 2021, respectively. The increase in capital expenditures is largely driven by higher activity levels and increased costs associated with rig upgrades, including walking rig conversions. Our fiscal year 2024 capital spending is currently estimated to be between $450 million and $500 million. This estimate includes normal capital maintenance requirements, information technology spending, and skidding to walking conversions for up to 14 rigs.

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Net Purchases & Sales of Short-Term Investments Our net sales of short-term investments during fiscal year 2023 were $14.3 million compared to net sales of $79.6 million and net purchases $107.4 million in fiscal years 2022 and 2021, respectively. The change in activity is driven by our ongoing liquidity management. Additionally, the Central Bank of Argentina maintains currency controls that limit our ability to access U.S. dollars in Argentina and remit cash from our Argentine operations. The execution of certain trades known as Blue Chip Swaps effectively results in a parallel U.S. dollar exchange rate. During the fiscal year ended 2023, we entered into a Blue Chip Swap transaction, which resulted in a $12.2 million loss on investment recorded in Gain on investment securities within our Consolidated Statements of Operations. As a result of the Blue Chip Swap transaction, $9.8 million of net cash was repatriated to the U.S. during the period.

Net Purchases of Long-Term Investments Our net purchases of long-term investments were $20.7 million, $29.2 million and $102.5 million in fiscal years 2023, 2022 and 2021, respectively. During the fiscal year ended September 30, 2023, our activity was primarily driven by a $14.1 million equity investment in Tamboran Resources Limited, $4.1 million in debt and equity security investments in various geothermal energy companies, and $2.5 million investments in other equity securities. The decrease in net purchases between fiscal years 2022 and 2021 is primarily driven by our $100.0 million cornerstone investment in ADNOC Drilling purchased during fiscal year 2021, the $22.0 million of proceeds received from the liquidation of our remaining equity securities in Schlumberger, Ltd, during the fiscal year ended September 30, 2022, offset by the purchase of a $33.0 million cornerstone investment in a convertible note in Galileo Holdco 2 and the purchase of $18.2 million in various geothermal investments during fiscal year 2022.

Sale of Assets Our proceeds from asset sales totaled $70.1 million, $62.3 million and $43.5 million in fiscal year 2023, 2022 and 2021, respectively. The increase in proceeds is largely driven by higher rig activity which drives higher reimbursement from customers for lost or damaged drill pipe and other used drilling equipment. Additionally, in fiscal year 2022, we sold our casing running and trucking assets.

Insurance Proceeds from Involuntary Conversion In November 2022, a fire at a wellsite caused substantial damage to one of our super spec-rigs within our North America Solutions segment. The major components were destroyed beyond repair and considered a total loss, and, as a result, these assets were written off and the rig was removed from our available rig count. At the time of the loss, the rig was fully insured under replacement cost insurance. The insurance recovery is expected to exceed the net book value of the components written off. During the fiscal year ended September 30, 2023, we collected $9.2 million of the total expected insurance proceeds.

Advance Payment for Sale of Property, Plant and Equipment During September 2021, the Company agreed to sell eight FlexRig land rigs with an aggregate net book value of $55.6 million to ADNOC Drilling for $86.5 million. We received $86.5 million in cash consideration in advance of delivering the rigs.

Financing Activities

Repurchase of Shares The Company has an evergreen authorization from the Board of Directors for the repurchase of up to four million common shares in any calendar year. In December 2022, the Board of Directors increased the maximum number of shares authorized to be repurchased in calendar year 2023 to five million common shares. On June 7, 2023, the Board of Directors further increased the maximum number of shares authorized to be repurchased in calendar year 2023 to seven million shares. The repurchases may be made using our cash and cash equivalents or other available sources and are held as treasury shares on our Condensed Consolidated Balance Sheets. During the fiscal year ended September 30, 2023, we repurchased 6.5 million common shares at an aggregate cost of $249.0 million, including accrued excise tax of $1.8 million, resulting in a net cash outflow of $247.2 million. During the fiscal year ended September 30, 2022, we repurchased 3.2 million common shares at an aggregate cost of $77.0 million. There were no purchases of common shares in fiscal year 2021.

Dividends We paid dividends of $1.94 per share, comprised of a base cash dividend of $1.00 and a supplemental cash dividend of $0.94 during the fiscal year 2023. Comparatively, we paid dividends of $1.00 per share in 2022 and 2021. Total dividends paid were $201.5 million, $107.4 million and $109.1 million in fiscal years 2023, 2022 and 2021, respectively.

Debt Issuance Proceeds and Costs On September 29, 2021, we issued $548.7 million aggregate principal amount of the 2031 Notes in an offering to persons reasonably believed to be qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act (“Rule 144A”) and to certain non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act (“Regulation S”). Debt issuance fees paid as of September 30, 2021 were $3.9 million.

Redemption of 4.65% Senior Notes due 2025 On October 27, 2021, we redeemed all of the outstanding 2025 Notes, resulting in a cash outflow of $487.1 million. As a result, the associated make-whole premium of $56.4 million was paid during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 debt extinguishment. The Company financed the redemption of the 2025 Notes with the net proceeds from the offering of the 2031 Notes, together with cash on hand. Additional details are fully discussed in Note 6—Debt.

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Senior Notes

2.90% Senior Notes due 2031 On September 29, 2021, we issued $550.0 million aggregate principal amount of the 2.90 percent 2031 Notes in an offering to persons reasonably believed to be qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act (“Rule 144A”) and to certain non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act (“Regulation S”). Interest on the 2031 Notes is payable semi-annually on March 29 and September 29 of each year, commencing on March 29, 2022.

In June 2022, we settled a registered exchange offer (the “Registered Exchange Offer”) to exchange the 2031 Notes for new, SEC-registered notes that are substantially identical to the terms of the 2031 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 2031 Notes do not apply to the new notes. All of the 2031 Notes were exchanged in the Registered Exchange Offer.

The indenture governing the 2031 Notes contains certain covenants that, among other things and subject to certain exceptions, limit the ability of the Company and its subsidiaries to incur certain liens; engage in sale and lease-back transactions; and consolidate, merge or transfer all or substantially all of the assets of the Company. The indenture governing the 2031 Notes also contains customary events of default with respect to the 2031 Notes.

4.65% Senior Notes due 2025 On December 20, 2018, we issued approximately $487.1 million in aggregate principal amount of the 2025 Notes. The debt issuance cost were being amortized straight-line over the stated life of the obligation, which approximated the effective interest method.

On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 2025 Notes at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. The Company financed the redemption of the 2025 Notes with the net proceeds from the offering of the 2031 Notes, together with cash on hand. The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021.

On October 27, 2021, we redeemed all of the outstanding 2025 Notes. As a result, the associated make-whole premium of $56.4 million and the write off of the unamortized discount and debt issuance costs of $3.7 million were recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 debt extinguishment and recorded in Loss on extinguishment of debt on our Consolidated Statements of Operations during the fiscal year ended September 30, 2022.

Credit Facility

On November 13, 2018, we entered into a credit agreement by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which was amended on November 13, 2019, providing for an unsecured revolving credit facility (as amended, the “2018 Credit Facility”), that was set to mature on November 13, 2024. On April 16, 2021, lenders with $680.0 million of commitments under the 2018 Credit Facility exercised their option to extend the maturity of the 2018 Credit Facility from November 13, 2024 to November 12, 2025. No other terms of the 2018 Credit Facility were amended in connection with this extension. On March 8, 2022, we entered into the second amendment to the 2018 Credit Facility, which, among other things, raised the number of potential future extensions of the maturity date applicable to extending lenders from one to two such potential extensions and replaced provisions in respect of interest rate determinations that were based on the London Interbank Offered Rate with provisions based on the Secured Overnight Financing Rate. Additionally, lenders with $680.0 million of commitments under the 2018 Credit Facility exercised their option to extend the maturity of the 2018 Credit Facility from November 12, 2025 to November 11, 2026. On February 10, 2023, lenders with $680.0 million of commitments under the 2018 Credit Facility exercised their option to extend the maturity of the 2018 Credit Facility from November 11, 2026 to November 12, 2027. The remaining $70.0 million of commitments under the 2018 Credit Facility will expire on November 13, 2024, unless extended by the applicable lender before such date.

The 2018 Credit Facility has $750.0 million in aggregate availability with a maximum of $75.0 million available for use as letters of credit. As of September 30, 2023, there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. For a full description of the 2018 Credit Facility, see Note 6—Debt to the Consolidated Financial Statements.

As of September 30, 2023, we had $95.0 million in uncommitted bilateral credit facilities, for the purpose of obtaining the issuance of international letters of credit, bank guarantees, and performance bonds. Of the $95.0 million, $40.0 million was outstanding as of September 30, 2023. Separately, we had $2.1 million in standby letters of credit and bank guarantees outstanding. In total, we had $42.1 million outstanding as of September 30, 2023.

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, 2023, we were in compliance with all debt covenants.

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Future Cash Requirements

Our operating cash requirements, scheduled debt repayments, interest payments, any declared dividends, and estimated capital expenditures for fiscal year 2024 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. If needed, we may decide to obtain additional funding from our $750.0 million 2018 Credit Facility. We currently do not anticipate the need to draw on the 2018 Credit Facility. Our indebtedness under our unsecured senior notes totaled $550.0 million at September 30, 2023 and matures on September 29, 2031.

As of September 30, 2023, we had a $517.8 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 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.

At September 30, 2023, we have recorded approximately $3.1 million of unrecognized tax benefits, interest, and penalties. We believe it is reasonably possible up to $2.6 million of the unrecognized tax benefits, interest, and penalties will be recognized as of June 30, 2024 as a result of a lapse of the statute of limitations. Any further reversals or payments of the liability cannot be estimated at this time.

The long‑term debt to total capitalization ratio was 16.6 percent as of September 30, 2023 and 2022. For additional information regarding debt agreements, refer to Note 6—Debt to the Consolidated Financial Statements.

There were no other significant changes in our financial position since September 30, 2022.

Material Commitments

Our contractual obligations as of September 30, 2023 are summarized in the table below:

(1)Interest on fixed-rate 2031 Notes was estimated based on principal maturities. See Note 6—Debt to our Consolidated Financial Statements.

(2)See Note 4—Leases to our Consolidated Financial Statements.

(3)See Note 15—Commitments and Contingencies to our Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Accounting policies that we consider significant are summarized in Note 2—Summary of Significant Accounting Policies, Related Risks and Uncertainties to our Consolidated Financial Statements included in Part II, Item 8—"Financial Statements and Supplementary Data" of this Form 10-K. The preparation of our financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. These estimates and assumptions are evaluated on an ongoing 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.

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Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are capitalized at cost, while maintenance and repairs are expensed as incurred. 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. Assets held-for-sale are reported at the lower of the carrying amount or fair value less estimated costs to sell. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation or result in abandonments. For the fiscal years presented in this Form 10-K, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.

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

Management assesses the potential impairment of our long‑lived assets and finite-lived intangibles whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, change in technology and/or overall changes in general market conditions. If a review of the long‑lived assets and finite-lived intangibles indicates that the carrying value of certain of these assets or asset groups is more than the estimated undiscounted future cash flows, an impairment charge is made, as required, to adjust the carrying value to the estimated fair value. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig’s marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics including utilization. The fair value of drilling rigs is determined based upon either an income approach using estimated discounted future cash flows, a market approach considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors, a cost approach utilizing new reproduction costs 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 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.

We self‑insure a significant portion of expected losses relating to workers’ compensation, general liability, employer’s liability, auto liability, as well as other insurance coverages. Generally, deductibles range from $1 million to $10 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events but there can be no assurance that such coverage will apply or be adequate in all circumstances. Estimates are recorded for incurred outstanding liabilities for workers’ compensation and other casualty claims. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred. Estimates for liabilities and retained losses are based on adjusters’ estimates, our historical loss experience and statistical methods commonly used within the insurance industry that we believe are reliable.

We also engage a third-party actuary to perform a periodic review of our 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 companies finance a significant portion of the physical damage risk on company‑owned drilling rigs as well as casualty deductibles. An actuary reviews the loss reserves retained by the Company and the captives on an annual basis.

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Revenue Recognition

Drilling services revenues are primarily comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. With most drilling contracts, we receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenue associated with the mobilization and demobilization of our drilling 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. The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced or no payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Direct costs incurred for the mobilization, are deferred and recognized on a straight-line basis as the drilling service is provided. While costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.

We also act as a principal for certain reimbursable services and auxiliary equipment provided by us to our clients, for which we incur costs and earn revenues. Many of these costs are variable, or dependent upon the activity that is performed each day under the related contract. Accordingly, reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs during the period to which they relate within the series of distinct time increments. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

Income Taxes

Deferred income taxes are accounted for under the liability method, which takes into account the differences between the basis of the assets and liabilities for financial reporting purposes and amounts recognized for income tax purposes. Our net deferred tax liability balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions. Included in our net deferred tax liability balance are deferred tax assets that are assessed for realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates.

In addition, we operate in several countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions we believe have a greater than 50 percent likelihood of being sustained. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments.

New Accounting Standards

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

Non-GAAP Measurements

Direct Margin

Direct margin is considered a non-GAAP metric. We define "Direct margin" as operating revenues less direct operating expenses. Direct margin is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. Direct margin is not a substitute for financial measures prepared in accordance with GAAP and should therefore be considered only as supplemental to such GAAP financial measures.

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The following table reconciles direct margin to segment operating income (loss), which we believe is the financial measure calculated and presented in accordance with GAAP that is most directly comparable to direct margin.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Part I of this Form 10‑K as well as the Consolidated Financial Statements and related notes thereto included in Part II, Item 8— “Financial Statements and Supplementary Data” of this Form 10‑K. Our future operating results may be affected by various trends and factors which are beyond our control. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Form 10-K under “Cautionary Note regarding Forward-Looking Statements” and Item 1A— “Risk Factors.” Accordingly, past results and trends should not be used by investors to anticipate future results or trends.

Executive Summary

Helmerich & Payne, Inc. (“H&P,” which, together with its subsidiaries, is identified as the “Company,” “we,” “us,” or “our,” except where stated or the context requires otherwise) through its operating subsidiaries provides performance-driven drilling solutions and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. As of September 30, 2022, our drilling rig fleet included a total of 271 drilling rigs. Our reportable operating business segments consist of the North America Solutions segment with 236 rigs, the Offshore Gulf of Mexico segment with seven offshore platform rigs and the International Solutions segment with 28 rigs as of September 30, 2022. At the close of fiscal year 2022, we had 192 active contracted rigs, of which 125 were under a fixed-term contract and 67 were working well-to-well, compared to 137 contracted rigs at September 30, 2021. Our long-term strategy remains focused on innovation, technology, safety, operational excellence and reliability. As we move forward, we believe that our advanced uniform rig fleet, technology offerings, financial strength, contract backlog and strong customer and employee base position us very well to respond to continued cyclical and often times volatile market conditions and to take advantage of future opportunities.

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Market Outlook

Our revenues are primarily derived from the capital expenditures of companies involved in the exploration, development and production of crude oil and natural gas (“E&Ps”). Generally, the level of capital expenditures is dictated by current and expected future prices of crude oil and natural gas, which are determined by various supply and demand factors. Both commodities have historically been, and we expect them to continue to be, cyclical and highly volatile.

Our drilling services operations are organized into the following reportable operating segments: North America Solutions, Offshore Gulf of Mexico, and International Solutions. With respect to North America Solutions, the resurgence of oil and natural gas production coming from the United States brought about by unconventional shale drilling for oil has significantly impacted the supply of oil and natural gas and the type of rig utilized in the U.S. land drilling industry.

The technical requirements of drilling longer lateral unconventional shale wells often necessitate the use of rigs that 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.

There is a strong customer preference for super-spec rigs not only due to the higher rig specifications that enable more technical drilling, but also due to the drilling efficiencies gained in utilizing a super-spec rig. As a result, there has been a structural decline in the use of non-super-spec rigs across the industry. We are the largest provider of super-spec rigs in the industry and, accordingly, we believe we are well positioned to respond to various market conditions.

Historically there has been a strong correlation between crude oil and natural gas prices and the demand for drilling rigs with the rig count increasing and decreasing with the up and down movements in the commodity prices. However, beginning in 2021, rig activity has not moved in tandem with crude oil prices to the same extent it had historically as a large portion of our customers instituted a more disciplined approach to their operations and capital spending in order to enhance their own financial returns. Those customers established capital budgets based upon commodity price assumptions for the upcoming year and adhered to them, not adjusting activity plans as commodity prices moved.

The capital budgets for calendar year 2023 have not yet been established by many of our customers; however, based upon the crude oil and natural gas pricing environment and many of our customers' desire to at least maintain their current production levels, we expect the level of capital spending and activity in calendar year 2023 to be similar to modestly higher than that experienced in calendar year 2022. In recent years the U.S. demand for super-spec rigs has strengthened. Despite this increased demand for super-spec rigs there is still idle super-spec rig capacity in the market; however, much of that idle capacity represents rigs that have not been active during the preceding two years and in some cases even longer. Consequently, there have been additional costs incurred to bring those long-idled rigs back into working condition, which contributed to upward pricing for super-spec rigs. This supply-demand dynamic combined with the value proposition we provide our customers through our drilling expertise, high-quality FlexRig® fleet, and automation technology resulted in an improvement in our underlying contract economics.

Our North America Solutions active rig count has more than tripled from COVID pandemic lows of 47 rigs in August 2020 to 176 rigs at September 30, 2022. Given the current market dynamics, our disciplined approach to deploying capital, and our fiscal year 2023 capital budget of $425 to $475 million, we project that our active rig count could reach 192 rigs during the first half of calendar 2023. While H&P stands ready to respond to the future demand for its super-spec rigs, we will do so by applying the same disciplined approach, focusing on financial returns. That said, the market for our rigs and others like them in the industry will likely remain tight as supply-chain challenges and labor constraints experienced across the energy industry may inhibit the industry’s ability overall to supply a significant quantity of super-specs rigs. As the largest provider of super-spec rigs in the U.S., H&P is not immune from supply-chain challenges or potential labor constraints, or inflationary pressures that can arise as a result of these matters. However, we believe we are well positioned to address these challenges and do not believe they are a limiting factor relative to our activity plans for fiscal 2023 nor believe they will have a significant adverse impact on our financial results. As a result of increased customer demand and limited supply additions given high required rig reactivation expenditures and supply chain constraints, we expect the momentum of the upward pressure on pricing to continue into fiscal 2023.

Collectively, our other business segments, Offshore Gulf of Mexico and International Solutions, are exposed to the same macro commodity price environment affecting our North America Solutions segment; however, activity levels in the International Solutions segment are also subject to other various geopolitical and financial factors specific to the countries of our operations. While we do not expect much activity change in our Offshore Gulf of Mexico segment, we do expect margin improvements based on recent rate increases. Regarding our International Solutions segment, we see opportunities for improvement in activity and the related corresponding margin improvement, but those will likely occur on a more extended timeline compared to what we have experienced in the North America Solutions segment.

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Recent Developments

Investment in Tamboran

In October 2022, we purchased a $14.1 million equity investment, representing approximately 106 million shares, in Tamboran Resources Limited ("Tamboran"). Tamboran's shares are listed and publicly traded on the Australian Securities Exchange. Additionally, during September 2022, we entered into a fixed-term drilling services agreement with Tamboran. The expected $30.3 million of revenue to be earned over the term of the contract is included within our contract backlog as of September 30, 2022, as mobilization is expected to commence in fiscal year 2023.

Investments in Geothermal Energy

During the fiscal year ended September 30, 2022, we purchased an additional $18.2 million in geothermal energy investments consisting of both debt and equity securities. Investments were made in five separate companies that are pursuing technological concepts to make unconventional geothermal energy a viable economic renewable energy source. These companies are developing enhanced geothermal system ("EGS") and closed loop concepts. The EGS concepts use one or more of the following: horizontal drilling, induced permeability, and fiber optic sensing. The closed loop concepts use multilateral wellbores, proprietary working fluid, or coaxial pipe configurations. All of these concepts are designed to harvest geothermal heat to create carbon-free, 24/7 geothermal energy. The aggregate balance of our investments in geothermal energy companies was $23.7 million and $2.7 million at September 30, 2022 and 2021, respectively. At this time, we expect the quantity and pace of our geothermal investments to be reduced relative to fiscal year 2022.

Investment in ADNOC Drilling

During September 2021, the Company made a $100.0 million cornerstone investment in ADNOC Drilling in advance of its announced IPO, representing 159.7 million shares of ADNOC Drilling, equivalent to a one percent ownership stake and subject to a three-year lockup period. ADNOC Drilling’s IPO was completed on October 3, 2021, and its shares are listed and traded on the Abu Dhabi Securities Exchange. Our investment is classified as a long-term equity investment within Investments in our Consolidated Balance Sheets. During the fiscal year ended September 30, 2022, we recognized a gain of $47.4 million on our Consolidated Statements of Operations, as a result of the change in fair value of the investment during the period. As of September 30, 2022, this investment is classified as a Level 1 investment based on the quoted stock price on the Abu Dhabi Securities Exchange. During the fiscal year ended September 30, 2022, we also received dividends in the amount of $6.6 million as a result of this investment.

Investment in Galileo Technologies

During the fiscal year ended September 30, 2022, the Company made a $33.0 million cornerstone investment in Galileo Holdco 2 Limited Technologies ("Galileo Holdco 2"), part of the group of companies known as Galileo Technologies (“Galileo”) in the form of a convertible note. Galileo specializes in liquification, natural gas compression and re-gasification modular systems and technologies to make the production, transportation, and consumption of natural gas, biomethane, and hydrogen more economically viable. The convertible note bears interest at 5% per annum with a maturity date of the earlier of April 2027 or an exit event (as defined in the agreement as either an initial public offering or a sale of Galileo). If the conversion option is exercised, the note would convert into common shares of the parent of Galileo Holdco 2 ("Galileo Parent"). We do not intend to sell this investment prior to its maturity date or an exit event. Two of our Directors are independent directors of Galileo Parent. Neither Director has a direct or indirect material interest in the transaction.

Pension Plan Lump-sum Distribution

During March 2022, the Company's domestic noncontributory defined benefit pension plan was amended to include a limited lump sum distribution option and a special eligibility window to be available to certain participants. During the period beginning on May 2, 2022 and ending on June 30, 2022, these participants could elect the limited lump sum distribution. This one-time lump sum was subsequently paid in August 2022 and resulted in a pension settlement charge of $7.8 million during the year ended September 30, 2022.

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Contract Backlog

Drilling contract backlog is the expected future dayrate revenue from executed contracts. We calculate backlog as the total expected revenue from fixed-term contracts and do not include any anticipated contract renewals or expected performance bonuses as part of its calculation. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. In addition to depicting the total expected revenue from fixed-term contracts, backlog is indicative of expected future cash flow that the Company expects to receive regardless of whether a customer honors the fixed-term contract to expiration of a contract or decides to terminate the contract early and pay an early termination payment. In the event of an early termination payment, the timing of the recognition of backlog and the total amount of revenue may differ; however, the overall associated gross margin is preserved. As such, management finds backlog a useful metric for future planning and budgeting, whereas investors consider it useful in estimating future revenue and cash flows of the Company. As of September 30, 2022 and 2021, our contract drilling backlog was $1.2 billion and $0.6 billion, respectively. The increase in backlog at September 30, 2022 from September 30, 2021 is primarily due to an increase in the number of fixed term drilling contracts executed. Approximately 30.8 percent of the September 30, 2022 total backlog is reasonably expected to be fulfilled in fiscal year 2024 and thereafter.

The following table sets forth the total backlog by reportable segment as of September 30, 2022 and 2021, and the percentage of the September 30, 2022 backlog reasonably expected to be fulfilled in fiscal year 2024 and thereafter:

The early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. In some limited circumstances, such as sustained unacceptable performance by us, no early termination payment would be paid to us. Early terminations could cause the actual amount of revenue earned to vary from the backlog reported. See Item 1A—"Risk Factors—Our current backlog of drilling services and solutions revenue may decline and may not be ultimately realized as fixed‑term contracts and may, in certain instances, be terminated without an early termination payment” within this Form 10-K regarding fixed term contract risk. Additionally, see Item 1A—"Risk Factors—The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, could have a material adverse effect on our business, financial condition and results of operations" within this Form 10-K.

Results of Operations for the Fiscal Years Ended September 30, 2022 and 2021

Consolidated Results of Operations

Net Income (Loss) We reported income from continuing operations of $6.6 million ($0.05 per diluted share) from operating revenues of $2.1 billion for the fiscal year ended September 30, 2022 compared to a loss from continuing operations of $337.5 million ($3.14 loss per diluted share) from operating revenues of $1.2 billion for the fiscal year ended September 30, 2021. Included in net income for the fiscal year ended September 30, 2022 is income of $0.4 million (with no impact on a per diluted share basis) from discontinued operations. Including discontinued operations, we recorded net income of $7.0 million ($0.05 per diluted share) for the fiscal year ended September 30, 2022 compared to a net loss of $326.2 million ($3.04 loss per diluted share) for the fiscal year ended September 30, 2021.

Operating Revenue Consolidated operating revenues were $2.1 billion in fiscal year 2022 and $1.2 billion in fiscal year 2021, including early termination revenue of $0.7 million and $7.7 million in each respective fiscal year. Excluding early termination revenue, operating revenue increased $0.8 billion in fiscal year 2022 compared to fiscal year 2021. The increase in fiscal year 2022 from fiscal year 2021 was primarily driven by an increase in average rig pricing and activity levels in our North America Solutions segment and increased activity levels in our International Solutions segment. Refer to segment results below for further details.

Direct Operating Expenses, Excluding Depreciation and Amortization Direct operating expenses in fiscal year 2022 were $1.4 billion, compared with $1.0 billion in fiscal year 2021. The increase in fiscal year 2022 from fiscal year 2021 was primarily attributable to the previously mentioned higher activity levels.

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Depreciation and Amortization Depreciation and amortization expense was $403.2 million in fiscal year 2022 and $419.7 million in fiscal year 2021. The decrease in depreciation and amortization during the fiscal year ended September 30, 2022 compared to the fiscal year ended September 30, 2021 was primarily attributable to the termination of depreciation on eight rigs that were included in the ADNOC sale during the fourth quarter of fiscal year 2021 coupled with ongoing relatively low levels of capital expenditures. Depreciation and amortization includes amortization of intangible assets of $7.2 million in fiscal years 2022 and 2021, and abandonments of equipment of $6.6 million and $2.0 million in fiscal years 2022 and 2021, respectively.

Selling, General and Administrative Expense Selling, general and administrative expenses increased to $182.4 million in the fiscal year ended September 30, 2022 compared to $172.2 million in the fiscal year ended September 30, 2021. The $10.2 million increase in fiscal year 2022 compared to fiscal year 2021 is primarily due to a $6.0 million increase in IT infrastructure spending, and a $5.6 million increase in labor and travel expense.

Asset Impairment Charges During the fiscal year ended September 30, 2022, we identified various assets that met the asset held-for-sale criteria and were reclassified as assets held-for-sale on our Consolidated Balance Sheets. The combined net book value of these assets was $5.4 million and were written down to their estimated fair value less cost to sell of $1.0 million, resulting in a non-cash impairment charge of $4.4 million, within our North America Solutions and International Solutions segments. The impairment charge was recorded in the Consolidated Statement of Operations for the fiscal year ended September 30, 2022. Comparatively, during the fiscal year ended September 30, 2021, the Company developed a plan to sell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the majority of which were previously decommissioned, written down and/or held as capital spares, which resulted in an impairment charge of $56.4 million. Also, during the fiscal year ended September 30, 2021, we formalized a plan to sell assets related to two of our lower margin service offerings, trucking and casing running services, all within our North America Solutions segment, which resulted in a non-cash impairment charge of $14.4 million.

Gain on Investment Securities During the fiscal year ended September 30, 2022, we recognized an aggregate gain of $57.9 million on investment securities. This gain was primarily comprised of a $47.4 million gain on our equity investment in ADNOC Drilling caused by an increase in the fair market value of the stock. In September 2021, the Company made a cornerstone equity investment consisting of 159.7 million shares for $100.0 million as part of ADNOC Drilling's initial public offering. This investment is subject to a three-year lock-up period. Additionally, during the fiscal year ended September 30, 2022, we sold our remaining equity securities of approximately 467.5 thousand shares in Schlumberger, Ltd. and received proceeds of approximately $22.0 million. We recognized an aggregate gain of $8.2 million related to this investment, which included a $0.5 million gain recognized upon the sale and a $7.7 million gain as a result of the change in the fair value of the investment during the fiscal year ended September 30, 2022.

Restructuring Charges During the fiscal years ended September 30, 2022 and 2021, we incurred $0.8 million and $5.9 million, respectively, in restructuring charges. The charges incurred during the fiscal year ended September 30, 2021 included $1.5 million in one-time severance benefits paid to employees who were voluntarily or involuntarily terminated primarily as a result of the reorganization of our IT operations coupled with charges of $4.5 million primarily related to the relocation of our Houston assembly facility and the downsizing of our storage yards used for idle rigs.

Interest and Dividend Income Interest and dividend income was $18.1 million and $10.3 million in fiscal years 2022 and 2021, respectively. The increase in interest and dividend income in fiscal year 2022 was primarily due to $6.6 million of dividend income received as a result of our investment in ADNOC drilling.

Interest Expense Interest expense totaled $19.2 million in fiscal year 2022 and $24.0 million in fiscal year 2021. The decrease in interest expense is primarily attributable to a lower interest rate on our 2.90% Senior Notes due 2031 (issued in September 2021) as compared to our 4.65% Senior Notes due 2025, which was fully redeemed in October 2021.

Income Taxes We had an income tax expense of $24.4 million in fiscal year 2022 compared to an income tax benefit of $103.7 million in fiscal year 2021. The effective income tax rate was 78.8 percent in fiscal year 2022 compared to 23.5 percent in fiscal year 2021. The effective rates differ from the U.S. federal statutory rate (21.0 percent for the fiscal years 2022 and 2021) primarily due to non-deductible permanent items, the foreign derived intangible income deduction (in fiscal year 2022), state and foreign income taxes, and adjustments to the deferred state income tax rate. Additionally, the effective income tax rate is higher in fiscal year 2022 as the low level of net income before tax increases the impact of the rate differences.

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.

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Discontinued Operations Income from discontinued operations was $0.4 million and $11.3 million in fiscal years 2022 and 2021, respectively. Expenses incurred within the country of Venezuela are reported as discontinued operations. Our wholly-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 seizure 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 2022 and 2021 is caused by exchange rate fluctuations due to the remeasurement of an uncertain tax liability.

North America Solutions

The following table presents certain information with respect to our North America Solutions reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 365 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues were $1.8 billion and $1.0 billion in fiscal year 2022 and 2021, respectively. Operating revenues increased $0.8 billion in fiscal year 2022 compared to fiscal year 2021. This increase is primarily driven by higher pricing and higher activity levels.

Direct Operating Expenses Direct operating expenses increased to $1.2 billion during the fiscal year ended September 30, 2022 as compared to $0.8 billion during the fiscal year ended September 30, 2021. This increase was primarily driven by an increase of $241.0 million in labor expense and an increase of $87.0 million in materials and supplies as we experienced higher activity levels and had an increase in field wages beginning in December 2021.

Depreciation and Amortization Depreciation expense decreased to $375.3 million during the fiscal year ended September 30, 2022 as compared to $392.4 million during the fiscal year ended September 30, 2021. The decrease was primarily attributable to the termination of depreciation on eight rigs located in the U.S. that were included in the ADNOC sale during the fourth quarter of fiscal year 2021 coupled with ongoing relatively low levels of capital expenditures during the 2022 fiscal year.

Selling, General and Administrative Expenses We had a $7.3 million decrease in selling, general and administrative costs during the fiscal year ended September 30, 2022 compared to the fiscal year ended September 30, 2021. This decrease was primarily driven by a $5.3 million decrease in professional services fees.

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Asset Impairment Charges During the fiscal year ended September 30, 2022, we identified two partial rig substructures that met the asset held-for-sale criteria and were reclassified as assets held-for-sale on our Consolidated Balance Sheets. The combined net book value of these assets of $2.0 million were written down to their estimated scrap value of $0.1 million, resulting in a non-cash impairment charge of $1.9 million during the fiscal year ended September 30, 2022 in the Consolidated Statement of Operations. Comparatively, during the fiscal year ended September 30, 2021, the Company developed a plan to sell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the majority of which were previously decommissioned, written down and/or held as capital spares. This resulted in an impairment charge of $56.4 million during the year ended September 30, 2021. During the same period, we also formalized a plan to sell assets related to two of our lower margin service offerings, trucking and casing running services, all within our North America Solutions segment, which resulted in a non-cash impairment charge of $14.4 million during the year ended September 30, 2021.

Restructuring Charges For the fiscal years ended September 30, 2022 and 2021, we incurred $0.5 million and $3.9 million, respectively, in restructuring charges. The charges incurred during the fiscal year ended September 30, 2021 primarily included charges of $3.8 million related to the relocation of the Houston assembly facility and the downsizing of storage yards used for idle rigs.

Offshore Gulf of Mexico

The following table presents certain information with respect to our Offshore Gulf of Mexico reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 365 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues were $125.5 million and $126.4 million in the fiscal year ended September 30, 2022 and 2021, respectively. The 0.7 percent decrease in operating revenue is primarily driven by lower reimbursable expenses and the mix of rigs working at full rates as opposed to being on lower standby or mobilization rates, partially offset by pricing increases which occurred in the later portion of the 2022 fiscal year.

Direct Operating Expenses Direct operating expenses decreased to $90.4 million during the fiscal year ended September 30, 2022 as compared to $97.2 million during the fiscal year ended September 30, 2021. The decrease was primarily driven by a $6.3 million favorable adjustment in self-insurance liabilities related to prior period claims coupled with the factors described above.

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International Solutions

The following table presents certain information with respect to our International Solutions reportable segment:

(1)These operating metrics and financial data, including average active rigs, are provided to allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.

(2)Direct margin, which is considered a non-GAAP metric, is defined as operating revenues less direct operating expenses and is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. See — Non-GAAP Measurements below for a reconciliation of segment operating income (loss) to direct margin.

(3)Defined as the number of contractual days we recognized revenue for during the period.

(4)Active rigs generate revenue for the Company; accordingly, 'average active rigs' represents the average number of rigs generating revenue during the applicable time period. This metric is calculated by dividing revenue days by total days in the applicable period (i.e., 365 days).

(5)Defined as the number of rigs generating revenue at the applicable end date of the time period.

Operating Revenues Operating revenues increased $78.2 million in fiscal year 2022 compared to fiscal year 2021. This increase is primarily driven by higher activity levels. Additionally, in the first quarter of fiscal year 2022, we recognized $16.4 million in revenue related to the settlement of a contract drilling dispute related to drilling services provided from fiscal years 2016 through 2019 with YPF S.A. Refer to Note 10—Revenue from Contracts with Customers for additional details.

Operating Expenses Direct operating expenses increased to $120.8 million during the fiscal year ended September 30, 2022 as compared to $68.7 million during the fiscal year ended September 30, 2021. This increase was primarily driven by an increase of $25.9 million in labor expense and an increase of $25.4 million in materials and supplies as we experienced higher activity levels.

Asset Impairment Charges During the fiscal year ended September 30, 2022, we identified two international FlexRig® drilling rigs that met the asset held-for-sale criteria and were reclassified as assets held-for-sale on our Consolidated Balance Sheets. In conjunction with establishing a plan to sell these rigs we recognized a non-cash impairment charge of $2.5 million during the fiscal year ended September 30, 2022 in the Consolidated Statement of Operations, as the rigs aggregate net book value of $3.4 million exceeded the fair value of the rigs less estimated cost to sell of $0.9 million. During the fiscal year ended September 30, 2021, we recorded no impairment charges.

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Other Operations

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

Operating Revenues We continue to use our Captive insurance companies to insure the deductibles for our domestic workers’ compensation, general liability, automobile liability claims programs, and medical stop-loss program and to insure the deductibles from the Company's international casualty and rig property programs. Intercompany premium revenues recorded by the Captives during the fiscal years ended September 30, 2022 and 2021 amounted to $57.0 million and $35.4 million, respectively, which were eliminated upon consolidation.

Direct Operating Expenses Direct operating expenses consisted primarily of $7.0 million and $12.6 million in adjustments to accruals for estimated losses allocated to the Captives and rig and casualty insurance premiums of $35.6 million and $21.9 million during the fiscal years ended September 30, 2022 and 2021, respectively. The change to accruals for estimated losses is primarily due to actuarial valuation adjustments by our third-party actuary.

Results of Operations for the Fiscal Years Ended September 30, 2021 and 2020

A discussion of our results of operations for the fiscal year ended September 30, 2021 compared to the fiscal year ended September 30, 2020 is included in Part II, Item 7— "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2021, filed with the Securities and Exchange Commission ("SEC") on November 18, 2021.

Liquidity and Capital Resources

Sources of Liquidity

Our sources of available liquidity include existing cash balances on hand, cash flows from operations, and availability under the 2018 Credit Facility. Our liquidity requirements include meeting ongoing working capital needs, funding our capital expenditure projects, paying dividends declared, and repaying our outstanding indebtedness. Historically, we have financed operations primarily through internally generated cash flows. During periods when internally generated cash flows are not sufficient to meet liquidity needs, we may utilize cash on hand, borrow from available credit sources, access capital markets or sell our investments.  Likewise, if we are generating excess cash flows or have cash balances on hand beyond our near-term needs, we may invest in highly rated short‑term money market and debt securities. These investments can include U.S. Treasury securities, U.S. Agency issued debt securities, highly rated corporate bonds and commercial paper, certificates of deposit and money market funds. However, in some international locations we may make short-term investments that are less conservative, as equivalent highly rated investments are unavailable. See—Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties—International Solutions Drilling Risks.

We may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity as necessary, fund our additional purchases, exchange or redeem senior notes, or repay any amounts under the 2018 Credit Facility. Our ability to access the debt and equity capital markets depends on a number of factors, including our credit rating, market and industry conditions and market perceptions of our industry, general economic conditions, our revenue backlog and our capital expenditure commitments.

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Cash Flows

Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling rigs under contract, the revenue we receive under those contracts, the efficiency with which we operate our drilling rigs, the timing of collections on outstanding accounts receivable, the timing of payments to our vendors for operating costs, and capital expenditures. As our revenues increase, operating net working capital is typically a use of capital, while conversely, as our revenues decrease, operating net working capital is typically a source of capital. To date, general inflationary trends have not had a material effect on our operating margins or cash flows as we have been able to more than offset these cumulative cost trends with rate increases.

As of September 30, 2022 and 2021, we had cash and cash equivalents of $232.1 million and $917.5 million and short-term investments of $117.1 million and $198.7 million, respectively. During the fiscal year ended September 30, 2022, our cash, cash equivalents, and restricted cash balance decreased approximately $667.7 million compared to our balance at September 30, 2021. This change was primarily driven by the redemption of all the outstanding 2025 Notes, resulting in a cash outflow of $487.1 million during the during the fiscal year ended September 30, 2022. Additionally, the associated make-whole premium of $56.4 million was paid during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 debt extinguishment.

Our cash flows for the fiscal years ended September 30, 2022, 2021 and 2020 are presented below:

Operating Activities

Our operating net working capital (non-GAAP) as of September 30, 2022, 2021, and 2020 is presented below:

Cash flows provided by operating activities were approximately $233.9 million, $136.4 million, and $538.9 million for the fiscal year ended September 30, 2022, 2021, and 2020 respectively. The change in cash provided by operating activities between fiscal years 2022 and 2021 is primarily driven by higher activity and rates, partially offset by changes in working capital. The decrease in cash provided by operating activities between fiscal years 2021 and 2020 was primarily driven by lower operating activity and lower pricing. For the purpose of understanding the impact on our cash flows from operating activities, operating net working capital is calculated as current assets, excluding cash and cash equivalents, short-term investments, and assets held-for-sale, less current liabilities, excluding dividends payable, short-term debt and advance payments for sale of property, plant and equipment.

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Operating net working capital was $281.9 million, $129.9 million and $194.2 million as of September 30, 2022, 2021 and 2020, respectively. This metric is considered a non-GAAP measure of the Company's liquidity. The Company considers operating net working capital to be a supplemental measure for presenting and analyzing trends in our cash flows from operations over time. Likewise, the Company believes that operating net working capital is useful to investors because it provides a means to evaluate the operating performance of the business using criteria that are used by our internal decision makers. The increase in operating net working capital between fiscal years 2022 and 2021 was primarily driven by higher rig activity and rates. Included in accounts receivable as of September 30, 2022 was $27.8 million of income tax receivables, of which $24.9 million was received subsequent to fiscal year end. The remainder is expected to be collected within the next fiscal year.

Investing Activities

Capital Expenditures Our capital expenditures were $250.9 million, $82.1 million and $140.8 million in fiscal years 2022, 2021 and 2020, respectively. The increase in capital expenditures between fiscal years 2022 and 2021 is driven by higher activity and spending on walking rig conversions. The decrease in capital expenditures between fiscal years 2021 and 2020 was driven by lower maintenance capital expenditures as a result of lower activity. Our fiscal year 2023 capital spending is currently estimated to be between $425 million and $475 million. This estimate includes normal capital maintenance requirements, information technology spending, skidding to walking conversions for a limited number of rigs and plans to reactivate several super-spec rigs.

Purchases & Sales of Short-Term Investments Our net sales of short-term investments during fiscal year 2022 were $79.6 million compared to net purchases of $107.4 million and $40.0 million in fiscal years 2021 and 2020, respectively. The change is driven by our ongoing liquidity management.

Purchases of Long-Term Investments Our net purchases of long-term investments were $29.2 million, $102.5 million and $0.6 million in fiscal years 2022, 2021 and 2020, respectively. The decrease in net purchases between fiscal years 2022 and 2021 is primarily driven by our $100.0 million cornerstone investment in ADNOC Drilling purchased during fiscal year 2021, the $22.0 million of proceeds received from the liquidation of our remaining equity securities in Schlumberger, Ltd, during the fiscal year ended September 30, 2022, offset by the purchase of a $33.0 million cornerstone investment in a convertible note in Galileo Holdco 2 and the purchase of $18.2 million in various geothermal investments during fiscal year 2022. The increase in net purchases between fiscal years 2021 and 2020 is primarily driven by our purchase of ADNOC Drilling equity securities (as mentioned above) during fiscal year 2021 and the absence of such activity in fiscal year 2020.

Sale of Assets Our proceeds from asset sales totaled $62.3 million, $43.5 million and $78.4 million in fiscal year 2022, 2021 and 2020, respectively. The increase in proceeds between fiscal years 2022 and 2021 is mainly driven by higher rig activity which drives higher reimbursement from customers for lost or damaged drill pipe. The increase is also attributable to the sale of our casing running and trucking assets that occurred during the fiscal year ended September 30, 2022. During the fiscal year ended September 30, 2020, we closed on the sale of a portion of our real estate investment portfolio, including six industrial sites, for total consideration, net of selling related expenses, of $40.7 million, which was the primary driver in the decrease in proceeds between fiscal years 2021 and 2020.

Advance Payment for Sale of Property, Plant and Equipment During September 2021, the Company agreed to sell eight FlexRig land rigs with an aggregate net book value of $55.6 million to ADNOC Drilling for $86.5 million. We received the $86.5 million in cash consideration in advance of delivering the rigs.

Financing Activities

Repurchase of Shares We have an evergreen authorization from the Board of Directors (the "Board") for the repurchase of up to four million common shares in any calendar year. The repurchases may be made using our cash and cash equivalents or other available sources. During the fiscal year ended September 30, 2022 and 2020, we repurchased 3.2 million common shares at an aggregate cost of $77.0 million and 1.5 million common shares at an aggregate cost of $28.5 million, respectively, which are held as treasury shares. There were no purchases of common shares in fiscal year 2021.

Dividends We paid dividends of $1.00 per share during fiscal years 2022 and 2021 compared to $2.38 per share during fiscal year 2020. Total dividends paid were $107.4 million, $109.1 million and $260.3 million in fiscal years 2022, 2021 and 2020, respectively. A cash dividend of $0.25 per share was declared on September 7, 2022 for shareholders of record on November 15, 2022, payable on December 1, 2022.

Debt Issuance Proceeds and Costs On September 29, 2021, we issued $548.7 million aggregate principal amount of the 2031 Notes in an offering to persons reasonably believed to be qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act (“Rule 144A”) and to certain non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act (“Regulation S”). Debt issuance fees paid as of September 30, 2021 were $3.9 million.

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Redemption of 4.65% Senior Notes due 2025 On October 27, 2021, we redeemed all of the outstanding 2025 Notes, resulting in a cash outflow of $487.1 million. As a result, the associated make-whole premium of $56.4 million was paid during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 debt extinguishment. The Company financed the redemption of the 2025 Notes with the net proceeds from the offering of the 2031 Notes, together with cash on hand. Additional details are fully discussed in Note 7—Debt.

Credit Facilities

On November 13, 2018, we entered into a credit agreement by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which was amended on November 13, 2019, providing for an unsecured revolving credit facility (as amended, the “2018 Credit Facility”), that was set to mature on November 13, 2024. On April 16, 2021, lenders with $680.0 million of commitments under the 2018 Credit Facility exercised their option to extend the maturity of the 2018 Credit Facility from November 13, 2024 to November 12, 2025. No other terms of the 2018 Credit Facility were amended in connection with this extension. Additionally, on March 8, 2022, we entered into the second amendment to the 2018 Credit Facility, which, among other things, raised the number of potential future extensions of the maturity date applicable to extending lenders from one to two such potential extensions and replaced provisions in respect of interest rate determinations that were based on the London Interbank Offered Rate with provisions based on the Secured Overnight Financing Rate. Lenders with $680.0 million of commitments under the 2018 Credit Facility also exercised their option to extend the maturity of the 2018 Credit Facility from November 12, 2025 to November 11, 2026. The remaining $70.0 million of commitments under the 2018 Credit Facility will expire on November 13, 2024, unless extended by the applicable lender before such date.

The 2018 Credit Facility has $750.0 million in aggregate availability with a maximum of $75.0 million available for use as letters of credit. As of September 30, 2022, there were no borrowings or letters of credit outstanding, leaving $750.0 million available to borrow under the 2018 Credit Facility. For a full description of the 2018 Credit Facility, see Note 7—Debt to the Consolidated Financial Statements.

As of September 30, 2022, we had $55.0 million in uncommitted bilateral credit facilities, for the purpose of obtaining the issuance of international letters of credit, bank guarantees, and performance bonds. Of the $55.0 million, $38.1 million of financial guarantees were outstanding as of September 30, 2022. Separately, we had $2.0 million in standby letters of credit and bank guarantees outstanding. In total, we had $40.1 million outstanding as of September 30, 2022. In October 2022, we increased one of our standby letters of credit by $1.9 million.

The applicable agreements for all unsecured debt contain additional terms, conditions and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. At September 30, 2022, 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 2023.

Senior Notes

2.90% Senior Notes due 2031 On September 29, 2021, we issued $550.0 million aggregate principal amount of the 2.90 percent 2031 Notes in an offering to persons reasonably believed to be qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act (“Rule 144A”) and to certain non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act (“Regulation S”). Interest on the 2031 Notes is payable semi-annually on March 29 and September 29 of each year, commencing on March 29, 2022. The 2031 Notes will mature on September 29, 2031 and bear interest at a rate of 2.90 percent annum. In June 2022, we settled a registered exchange offer (the “Registered Exchange Offer”) to exchange the 2031 Notes for new, SEC-registered notes that are substantially identical to the terms of the 2031 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 2031 Notes do not apply to the new notes. One hundred percent of the 2031 Notes were exchanged in the Registered Exchange Offer.

The indenture governing the 2031 Notes contains certain covenants that, among other things and subject to certain exceptions, limit the ability of the Company and its subsidiaries to incur certain liens; engage in sale and lease-back transactions; and consolidate, merge or transfer all or substantially all of the assets of the Company. The indenture governing the 2031 Notes also contains customary events of default with respect to the 2031 Notes.

4.65% Senior Notes due 2025 On December 20, 2018, we issued approximately $487.1 million in aggregate principal amount of the 2025 Notes. The debt issuance cost was being amortized straight-line over the stated life of the obligation, which approximated the effective interest method.

On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 2025 Notes at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. The Company financed the redemption of the 2025 Notes with the net proceeds from the offering of the 2031 Notes, together with cash on hand. The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021.

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On October 27, 2021, we redeemed all of the outstanding 2025 Notes. As a result, the associated make-whole premium of $56.4 million and the write off of the unamortized discount and debt issuance costs of $3.7 million were recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 debt extinguishment and recorded in Loss on Extinguishment of Debt on our Consolidated Statements of Operations during the fiscal year ended September 30, 2022.

Future Cash Requirements

Our operating cash requirements, scheduled debt repayments, interest payments, any declared dividends, and estimated capital expenditures for fiscal year 2023 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. If needed, we may decide to obtain additional funding from our $750.0 million 2018 Credit Facility. We currently do not anticipate the need to draw on the 2018 Credit Facility. Our indebtedness under our unsecured senior notes totaled $550.0 million at September 30, 2022 and matures on September 29, 2031.

As of September 30, 2022, we had a $537.7 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 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.

At September 30, 2022, we had $3.9 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time.

The long‑term debt to total capitalization ratio was 16.6 percent at September 30, 2022 compared to 15.9 percent at September 30, 2021. For additional information regarding debt agreements, refer to Note 7—Debt to the Consolidated Financial Statements.

There were no other significant changes in our financial position since September 30, 2021.

Material Commitments

Our contractual obligations as of September 30, 2022 are summarized in the table below:

(1)Interest on fixed-rate 2031 Notes was estimated based on principal maturities. See Note 7—Debt to our Consolidated Financial Statements.

(2)See Note 5—Leases to our Consolidated Financial Statements.

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

Critical Accounting Policies and Estimates

Accounting policies that we consider significant are summarized in Note 2—Summary of Significant Accounting Policies, Risks and Uncertainties to our Consolidated Financial Statements included in Part II, Item 8—"Financial Statements and Supplementary Data" of this Form 10-K. The preparation of our financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. These estimates and assumptions are evaluated on an ongoing 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.

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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. Assets held-for-sale are reported at the lower of the carrying amount or fair value less estimated costs to sell. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. Certain events, such as unforeseen changes in operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation or result in abandonments. For the fiscal years presented in this Form 10-K, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.

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

Management assesses the potential impairment of our long‑lived assets and finite-lived intangibles whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, change in technology and/or overall changes in general market conditions. If a review of the long‑lived assets and finite-lived intangibles indicates that the carrying value of certain of these assets or asset groups is more than the estimated undiscounted future cash flows, an impairment charge is made, as required, to adjust the carrying value to the estimated fair value. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig’s marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics including utilization. The fair value of drilling rigs is determined based upon either an income approach using estimated discounted future cash flows, a market approach considering factors such as recent market sales of rigs of other companies and our own sales of rigs, appraisals and other factors, a cost approach utilizing new reproduction costs 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 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.

We self‑insure a significant portion of expected losses relating to workers’ compensation, general liability, employer’s liability and automobile liability. Generally, deductibles range from $1 million to $10 million per occurrence depending on the coverage and whether a claim occurs outside or inside of the United States. Insurance is purchased over deductibles to reduce our exposure to catastrophic events but there can be no assurance that such coverage will apply or be adequate in all circumstances. Estimates are recorded for incurred outstanding liabilities for workers’ compensation and other casualty claims. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred. Estimates for liabilities and retained losses are based on adjusters’ estimates, our historical loss experience and statistical methods commonly used within the insurance industry that we believe are reliable.

We also engage a third-party actuary to perform a periodic review of our 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 companies finance a significant portion of the physical damage risk on company‑owned drilling rigs as well as casualty deductibles. An actuary reviews the loss reserves retained by the Company and the captives on an annual basis.

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Revenue Recognition

Drilling services revenues are primarily comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. With most drilling contracts, we receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenue associated with the mobilization and demobilization of our drilling 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. The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced or no payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Direct costs incurred for the mobilization, are deferred and recognized on a straight-line basis as the drilling service is provided. While costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.

We also act as a principal for certain reimbursable services and auxiliary equipment provided by us to our clients, for which we incur costs and earn revenues. Many of these costs are variable, or dependent upon the activity that is performed each day under the related contract. Accordingly, reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs during the period to which they relate within the series of distinct time increments. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

Income Taxes

Deferred income taxes are accounted for under the liability method, which takes into account the differences between the basis of the assets and liabilities for financial reporting purposes and amounts recognized for income tax purposes. Our net deferred tax liability balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions. Included in our net deferred tax liability balance are deferred tax assets that are assessed for realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates.

In addition, we operate in several countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions we believe have a greater than 50 percent likelihood of being sustained. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments.

New Accounting Standards

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

Non-GAAP Measurements

Direct Margin

Direct margin is considered a non-GAAP metric. We define "Direct margin" as operating revenues less direct operating expenses. Direct margin is included as a supplemental disclosure because we believe it is useful in assessing and understanding our current operational performance, especially in making comparisons over time. Direct margin is not a substitute for financial measures prepared in accordance with GAAP and should therefore be considered only as supplemental to such GAAP financial measures.

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The following table reconciles direct margin to segment operating income (loss), which we believe is the financial measure calculated and presented in accordance with GAAP that is most directly comparable to direct margin.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Part I of this Form 10‑K as well as the Consolidated Financial Statements and related notes thereto included in Part II, Item 8— “Financial Statements and Supplementary Data” of this Form 10‑K. Our future operating results may be affected by various trends and factors which are beyond our control. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Form 10-K under “Cautionary Note regarding Forward-Looking Statements” and Item 1A— “Risk Factors.” Accordingly, past results and trends should not be used by investors to anticipate future results or trends.

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Executive Summary

Helmerich & Payne, Inc. (“H&P,” which, together with its subsidiaries, is identified as the “Company,” “we,” “us,” or “our,” except where stated or the context requires otherwise) through its operating subsidiaries provides performance-driven drilling solutions and technologies that are intended to make hydrocarbon recovery safer and more economical for oil and gas exploration and production companies. As of September 30, 2021, our drilling rig fleet included a total of 273 drilling rigs. Our reportable operating business segments consist of the North America Solutions segment with 236 rigs, the Offshore Gulf of Mexico segment with seven offshore platform rigs and the International Solutions segment with 30 rigs as of September 30, 2021. At the close of fiscal year 2021, we had 137 contracted rigs, of which 73 were under a fixed-term contract and 64 were working well-to-well, compared to 79 contracted rigs at September 30, 2020. Our long-term strategy remains focused on innovation, technology, safety, operational excellence and reliability. As we move forward, we believe that our advanced uniform rig fleet, technology offerings, financial strength, contract backlog and strong customer and employee base position us very well to respond to continued cyclical and often times volatile market conditions and take advantage of future opportunities.

Market Outlook

Our revenues are derived from the capital expenditures of companies involved in the exploration, development and production of crude oil and natural gas (“E&Ps”). Generally, the level of capital expenditures is dictated by current and expected future prices of crude oil and natural gas, which are determined by various supply and demand factors. Both commodities have historically been, and we expect them to continue to be, cyclical and highly volatile.

With respect to North America Solutions, the resurgence of oil and natural gas production coming from the United States brought about by unconventional shale drilling for oil has significantly impacted the supply of oil and natural gas and the type of rig utilized in the U.S. land drilling industry. The advent of unconventional drilling for oil in the United States began in early 2009 and continues to evolve as E&Ps drill longer lateral wells with tighter well spacing. During this time, we designed, built and delivered to the market new technology AC drive rigs (FlexRig®), substantially growing our fleet. The pace of progress of unconventional drilling over the years has been cyclical and volatile, dictated by crude oil and natural gas price fluctuations, which at times have proven to be dramatic.

Throughout this time, the length of the lateral section of wells drilled in the United States has continued to grow. The progression of longer lateral wells has required many of the industry’s rigs to be upgraded to certain specifications in order to meet the technical challenges of drilling longer lateral wells. The upgraded rigs meeting those specifications are commonly referred to in the industry as super-spec rigs and have the following specific characteristics: AC drive, minimum of 1,500 horsepower drawworks, minimum of 750,000 lbs. hookload rating, 7,500 psi mud circulating system, and multiple-well pad capability.

The technical requirements of drilling longer lateral wells often necessitate the use of super-spec rigs and even when not required for shorter lateral wells, there is a strong customer preference for super-spec due to the drilling efficiencies gained in utilizing a super-spec rig. As a result, there has been a structural decline in the use of non-super-spec rigs across the industry. However, as a result of having a large super-spec fleet, we gained market share and became the largest provider of super-spec rigs in the industry. As such, we believe we are well positioned to respond to various market conditions.

In early March 2020, the increase in crude oil supply resulting from production escalations from the Organization of the Petroleum Exporting Countries and other oil producing nations ("OPEC+") combined with a decrease in crude oil demand stemming from the global response and uncertainties surrounding the COVID-19 pandemic resulted in a sharp decline in crude oil prices. Specifically, during calendar year 2020, crude oil prices fell from approximately $60 per barrel to the low-to-mid-$20 per barrel range, lower in some cases, which resulted in customers decreasing their 2020 capital budgets nearly 50 percent from calendar year 2019 levels. There was a corresponding dramatic decline in the demand for land rigs, such that the overall rig count for calendar year 2020 averaged roughly 430 rigs, significantly lower than in calendar year 2019, which averaged approximately 940 rigs.

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We experienced much of our rig count decline during the second and third quarters of fiscal year 2020 as our North American Solutions active rig count declined from 195 rigs at December 31, 2019 to a low of 47 rigs in August 2020. However, during the fourth quarter of fiscal year 2020, the market experienced a stabilization of crude oil prices in the $40 per barrel range and subsequently crude oil prices moved toward $50 per barrel as our customers set their capital budgets for calendar year 2021. More recently, crude oil prices have continued to increase, reaching more than $70 per barrel. That said, however, we do not expect rig activity to move in tandem with crude oil prices to the same extent as it has historically. This is primarily due to a large portion of our customers having a more disciplined approach to their operations and capital spending. We expect a majority will maintain their activity levels in accordance with their capital budgets for 2021, which were set during a time when crude oil prices were lower and will not adjust spending levels higher as crude oil prices move higher. Along with stabilization of crude prices during the fourth quarter of fiscal year 2020, our rig activity began to increase, and increased more significantly during the first and second quarters of fiscal year 2021. Our North America Solutions active rig count has more than doubled from 47 rigs in August 2020 to 127 rigs at September 30, 2021. We do anticipate further increases in our rig count for the remainder of calendar year 2021 as customers prepare for 2022 operations based upon the expectation that the level of capital spending will be higher in calendar year 2022 than it was in calendar year 2021.

Utilization for our super-spec FlexRig® fleet peaked in late calendar year 2018 with 216 of 221 super-spec rigs working (98 percent utilization); however, the subsequent decline in the demand for land rigs resulted in customers idling a large portion of our super-spec FlexRig® fleet. At September 30, 2021, we had 105 idle super-spec rigs out of our FlexRig® fleet of 230 super-spec rigs (54 percent utilization).

Collectively, our other business segments, Offshore Gulf of Mexico and International Solutions, are exposed to the same macro commodity price environment affecting our North America Solutions segment; however, activity levels in the International Solutions segment are also subject to other various geopolitical and financial factors specific to the countries of our operations. While we do not expect much change in our Offshore Gulf of Mexico segment, we see opportunities for improvement in our International Solutions segment, but those will likely occur on a more extended timeline compared to what we have experienced in the North America Solutions segment.

H&P recognizes the uncertainties and 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 a significant financial impact on the Company, including increased costs as a result of labor shortages and logistics constraints. The global response to coping with the pandemic resulted in a drop in demand for crude oil, which, when combined with a more than adequate supply of crude oil, resulted in a sharp decline in crude oil prices, causing our customers to have pronounced pullbacks in their operations and planned capital expenditures. The direct impact of COVID-19 on H&P's operations has created some challenges that we believe the Company is adequately addressing to ensure a robust continuation of our operations albeit at a lower activity level.

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. We are adhering to Center for Disease Control guidelines for evaluating actual and potential COVID-19 exposures and we are complying with local governmental jurisdiction policies and procedures where our operations reside; in some instances, policies and procedures are more stringent in our foreign operations than in our North America operations and this resulted in a complete suspension, for a certain period of time, of all drilling operations in at least one foreign jurisdiction.

In the United States, 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.

Since the COVID-19 outbreak began, no rigs have been fully shut down (other than temporary shutdowns for disinfecting) and such measures to disinfect facilities have not had a significant impact on service. We believe our service levels are unchanged from pre-pandemic levels.

From a financial perspective, we believe the Company is well positioned to continue as a going concern even through a more protracted disruption caused by COVID-19, oil oversupply and low oil prices. We have taken measures to reduce costs and capital expenditures to levels that better reflect a lower activity environment. The actions we took during fiscal year 2020 included a reduction to the annual dividend of approximately $200 million, a reduction of approximately $145 million in the fiscal year 2020 capital spend, a reduction of over $50 million in fixed operational overhead, and a reduction of selling, general and administrative expenses of more than $25 million on an annualized basis. The culmination of these cost-saving initiatives resulted in a $16 million restructuring charge during fiscal year 2020. Further, we took additional steps in fiscal year 2021 to reduce our cost structure. These measures will result in an estimated annualized savings of more than $10 million with the full benefit expected to be realized in calendar year 2022. We anticipate further cost reductions going forward; however, implementation of future cost initiatives will be incremental and are anticipated to be realized over the next few quarters. These cost reduction measures could lead to additional restructuring charges in future periods.

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At September 30, 2021, the Company had cash and cash equivalents and short-term investments of $1.1 billion and availability under the 2018 Credit Facility (as defined herein) of $750 million. On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 4.65% unsecured senior notes due 2025 (the "2025 Notes") at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. On September 29, 2021, we issued $550.0 million aggregate principal amount of our 2.90% unsecured senior notes due 2031 (the "2031 Notes"). The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021. The proceeds from the offering of the 2031 Notes were used to redeem the 2025 Notes. On October 27, 2021, we redeemed all of the outstanding 2025 Notes. The associated make-whole premium and accrued interest of $58.1 million and the write off of the unamortized discount and debt issuance costs of $3.7 million will be recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 redemption. Subsequent to the redemption, our near-term liquidity was approximately $1.3 billion. We currently do not anticipate the need to draw on the 2018 Credit Facility. See “—Liquidity and Capital Resources—Senior Notes—2.90% Senior Notes due 2031” below and Note 7—Debt to our Consolidated Financial Statements for more information.

As part of the Company's normal operations, we regularly monitor the creditworthiness of our customers and vendors, screening out those that we believe have a high risk of failure to honor their counter-party obligations either through payment or delivery of goods or services. We also perform routine reviews of our accounts receivable and other amounts owed to us to assess and quantify the ultimate collectability of those amounts. At September 30, 2021 and September 30, 2020, the Company had a net allowance against its accounts receivable of $2.1 million and $1.8 million, respectively.

The nature of the COVID-19 pandemic is inherently uncertain, and as a result, the Company is unable to reasonably estimate the duration and ultimate impacts of the pandemic, including the timing or level of any subsequent recovery. As a result, the Company cannot be certain of the degree of impact on the Company’s business, results of operations and/or financial position for future periods.

Recent Developments

Treasury and Investments

Senior Notes Offering and Redemption of 4.65% Senior Notes due 2025

On September 29, 2021, we completed our offering of $550.0 million aggregate principal amount of the 2031 Notes. We received net proceeds from the offering of the 2031 Notes of approximately $545.1 million, after deducting the initial purchasers’ discounts and commissions and offering expenses. In October 2021, the net proceeds from the offering were principally used to redeem all $487.1 million aggregate principal amount of our outstanding 2025 Notes. See “—Liquidity and Capital Resources—Senior Notes—2.90% Senior Notes due 2031” below and Note 7—Debt to our Consolidated Financial Statements for more information.

On September 27, 2021, the Company delivered a conditional notice of optional full redemption for all of the outstanding 4.65% unsecured senior notes due 2025 (the "2025 Notes") at a redemption price calculated in accordance with the indenture governing the 2025 Notes, plus accrued and unpaid interest on the 2025 Notes to be redeemed. On September 29, 2021, we issued $550.0 million aggregate principal amount of our 2.90% unsecured senior notes due 2031 (the "2031 Notes"). The Company’s obligation to redeem the 2025 Notes was conditioned upon the prior consummation of the issuance of the 2031 Notes, which was satisfied on September 29, 2021. The proceeds from the offering of the 2031 Notes were used to redeem the 2025 Notes. On October 27, 2021, we redeemed all of the outstanding 2025 Notes. The associated make-whole premium and accrued interest of $58.1 million and the write off of the unamortized discount and debt issuance costs of $3.7 million will be recognized during the first fiscal quarter of 2022 contemporaneously with the October 27, 2021 redemption. See “—Liquidity and Capital Resources—Senior Notes—4.65% Senior Notes due 2025” below and Note 7—Debt to our Consolidated Financial Statements for more information.

Credit Facility Maturity Extension

On April 16, 2021, lenders with $680.0 million of commitments under the 2018 Credit Facility exercised their option to extend the maturity of the 2018 Credit Facility from November 13, 2024 to November 12, 2025. No other terms of the 2018 Credit Facility were amended in connection with this extension. The remaining $70.0 million of commitments under the 2018 Credit Facility will expire on November 13, 2024, unless extended by the applicable lender before such date.

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ADNOC and Helmerich & Payne Strategic Alliance

During September 2021, the Abu Dhabi National Oil Company ("ADNOC") and its subsidiary ADNOC Drilling Company P.J.S.C ("ADNOC Drilling") and the Company jointly announced a strategic alliance, through which ADNOC Drilling acquired eight of our FlexRig® land rigs for $86.5 million. Following this transaction, H&P made a $100.0 million cornerstone investment in ADNOC Drilling's initial public offering subject to a three-year lock up period. Our investment is classified within Investments in our Consolidated Balance Sheets as of September 30, 2021. ADNOC Drilling’s IPO completed on October 3, 2021 and our $100.0 million investment represents 159.7 million shares of ADNOC Drilling, equivalent to a one percent ownership stake.

We will account for our investment in ADNOC Drilling prospectively, after the IPO date of October 3, 2021, as a marketable equity security with a readily determinable fair value. Fair value will be measured using a market approach on a recurring basis and is categorized using the fair value hierarchy. Any changes in such values will be reflected in net income. The availability of inputs observable in the market depends on a variety of factors, including the type of instrument, whether the instrument is actively traded and other characteristics particular to the transaction, which includes the effect of the lock-up period.

This alliance is intended to further drive ADNOC Drilling's growth and expansion as well as enhance their rig-based operational performance by providing them access to our world-class FlexRig® fleet and leveraging our expertise and technologies. Additionally, this alliance facilitates our goal of allocating capital international, particularly in the Middle East and North Africa region, by accelerating our access to the attractive and fast-growing Abu Dhabi market as a key platform for further regional expansion.

The eight rigs had an aggregate net book value of $55.6 million and were recorded as assets held-for-sale in our Consolidated Balance Sheets as of September 30, 2021. The rigs' fair value less estimated cost to sell of $29.0 million, including approximately $24.0 million of cash costs to be incurred, approximated their net book values at September 30, 2021. Two of the eight rigs were already located in the U.A.E where ADNOC Drilling is domiciled with the remaining six rigs to be shipped from the United States. As part of the sales agreement, the rigs will be delivered and commissioned in stages over a twelve-month period subject to acceptance upon successful completion of final inspection on customary terms and conditions. No rigs have been delivered to ADNOC Drilling as of September 30, 2021.

Property, Plant and Equipment

Sale of Offshore Rig

During the first quarter of fiscal year 2021, we closed on the sale of an offshore platform rig within our Offshore Gulf of Mexico operating segment for total consideration of $12.0 million with an aggregate net book value of $2.8 million, resulting in a gain of $9.2 million, which is included within (gain) loss on sale of assets on our Consolidated Statements of Operations during the fiscal year ended September 30, 2021.

Assets Held-for-Sale

In March 2021, the Company's leadership continued the execution of the current strategy, which was initially introduced in 2019, focusing on operating various types of highly capable upgraded rigs and phasing out the older, less capable fleet. As a result, the Company has undertaken a plan to sell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the majority of which were previously decommissioned, written down and/or held as capital spares. The book values of those assets were written down to $13.5 million, which represents the fair value less estimated cost to sell, and were reclassified as held-for-sale in the second and third quarter of fiscal year 2021. As a result, we recognized a non-cash impairment charge of $56.4 million, during the fiscal year ended September 30, 2021, in the Consolidated Statement of Operations. During the year ended September 30, 2021, we completed the sale of a portion of the assets with a net book value of $6.5 million that were originally classified as held-for-sale during the second and third quarter of fiscal year 2021.

During the fiscal year ended September 30, 2021, we formalized a plan to sell assets related to two of our lower margin service offerings, trucking and casing running services, which contributed approximately 2.8 percent to our consolidated revenue during fiscal year 2021, all within our North America Solutions segment. The combined net book values of these assets of $23.2 million were written down to their combined fair value less estimated cost to sell of $8.8 million, and were reclassified as held-for-sale in the Consolidated Balance Sheets as of September 30, 2021. As a result, we recognized a non-cash impairment charge of $14.4 million in the Consolidated Statement of Operations during the year ended September 30, 2021.

Subsequent to September 30, 2021, we closed on the sale of these assets in two separate transactions. The sale of our trucking services was completed on November 3, 2021 while the sale of our casing running services was completed on November 15, 2021 for combined cash consideration less costs to sell of $5.8 million in addition to the possibility of future earnout revenue.

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Restructuring

During the second quarter of fiscal year 2021, we reorganized our IT operations and moved select IT functions to a managed service provider. Costs incurred as of September 30, 2021 in connection with the restructuring are primarily comprised of one-time severance benefits to employees who were involuntarily terminated. The termination date of some of the employees extend beyond September 30, 2021, and such employees are required to render service through their respective termination date in order to receive the one-time severance benefit. During the third quarter of fiscal year 2021, we commenced a voluntary separation program at our local office in Argentina for which we incurred one-time severance charges for employees who were voluntarily terminated. Total costs incurred related to our IT reorganization and our Argentina separation program were $1.5 million for the fiscal year ended September 30, 2021.

Additionally, we continue to take measures to lower our cost structure based on activity levels. During fiscal year 2021, we incurred $4.5 million in one-time moving related expenses primarily due to the downsizing and relocation of our Houston assembly facility and various storage yards used for idle rigs. This together with additional restructuring activities that could result from our in-process cost management review could result in additional restructuring charges throughout the year.

Contract Backlog

Drilling contract backlog is the expected future dayrate revenue from executed contracts. We calculate backlog as the total expected revenue from fixed-term contracts and do not include any anticipated contract renewals or expected performance bonuses as part of its calculation. Additionally, contracts that currently contain month-to-month terms are represented in our backlog as one month of unsatisfied performance obligations. In addition to depicting the total expected revenue from fixed-term contracts, backlog is indicative of expected future cash flow that the Company expects to receive regardless of whether a customer honors the fixed-term contract to expiration of a contract or decides to terminate the contract early and pay an early termination payment. In the event of an early termination payment, the timing of the recognition of backlog and the total amount of revenue may differ; however, the overall associated cash flow is preserved. As such, management finds backlog a useful metric for future planning and budgeting, whereas investors consider it useful in estimating future revenue and cash flows of the Company. As of September 30, 2021 and 2020, our contract drilling backlog was $572.0 million and $658.0 million, respectively. These amounts do not include any anticipated contract renewals or expected performance bonuses. The decrease in backlog at September 30, 2021 from September 30, 2020 is primarily due to prevailing market conditions causing a decline in the number of longer term drilling contracts executed. Approximately 22.9 percent of the September 30, 2021 total backlog is reasonably expected to be fulfilled in fiscal year 2023 and thereafter.

Fixed-term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term. As a result of the 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, opted to renegotiate or early terminate existing drilling contracts. Such renegotiations included requests to lower the contract dayrate in exchange for additional terms, temporary stacking of the rig, and other proposals. We recognized $7.7 million and $73.4 million in early termination revenue associated with term contracts for the fiscal years ended September 30, 2021 and 2020, respectively.

The following table sets forth the total backlog by reportable segment as of September 30, 2021 and 2020, and the percentage of the September 30, 2021 backlog reasonably expected to be fulfilled in fiscal year 2023 and thereafter:

The early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. In some limited circumstances, such as sustained unacceptable performance by us, no early termination payment would be paid to us. Early terminations could cause the actual amount of revenue earned to vary from the backlog reported. See Item 1A—"Risk Factors—Our current backlog of drilling services and solutions revenue may continue to decline and may not be ultimately realized as fixed‑term contracts and may, in certain instances, be terminated without an early termination payment” within this Form 10-K regarding fixed term contract risk. Additionally, see Item 1A—"Risk Factors—The impact and effects of public health crises, pandemics and epidemics, such as the COVID-19 pandemic, have adversely affected and are expected to continue to adversely affect our business, financial condition and results of operations" within this Form 10-K.

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Results of Operations for the Fiscal Years Ended September 30, 2021 and 2020

Consolidated Results of Operations

All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Except as specifically discussed, the following results of operations pertain only to our continuing operations.

Net Loss We reported a loss from continuing operations of $337.5 million ($3.14 loss per diluted share) from operating revenues of $1.2 billion for the fiscal year ended September 30, 2021 compared to a loss from continuing operations of $496.4 million ($4.62 loss per diluted share) from operating revenues of $1.8 billion for the fiscal year ended September 30, 2020. Included in the net loss for the fiscal year ended September 30, 2021 is income of $11.3 million ($0.10 per diluted share) from discontinued operations. Including discontinued operations, we recorded a net loss of $326.2 million ($3.04 loss per diluted share) for the fiscal year ended September 30, 2021 compared to a net loss of $494.5 million ($4.60 loss per diluted share) for the fiscal year ended September 30, 2020.

Revenue Consolidated operating revenues were $1.2 billion in fiscal year 2021 and $1.8 billion in fiscal year 2020, including early termination revenue of $7.7 million and $73.4 million in each respective fiscal year. Excluding early termination revenue, operating revenue decreased $0.5 billion in fiscal year 2021 compared to fiscal year 2020. The decrease in fiscal year 2021 from fiscal year 2020 was driven by lower activity, lower early termination revenue, and lower average rig pricing.

Direct Operating Expenses, Excluding Depreciation and Amortization Direct operating expenses in fiscal year 2021 were $1.0 billion, compared with $1.2 billion in fiscal year 2020. The decrease in fiscal year 2021 from fiscal year 2020 was primarily attributable to the previously mentioned lower activity levels, partially offset by fixed overhead costs and higher rig recommissioning expenses, as we reactivated rigs across fiscal year 2021.

Depreciation and Amortization Depreciation and amortization expense was $419.7 million in fiscal year 2021 and $481.9 million in fiscal year 2020. The decrease in depreciation and amortization during fiscal year ended September 30, 2021 compared to fiscal year ended September 30, 2020 was primarily attributable to the lower carrying cost of our impaired assets as well as ongoing low levels of capital expenditures. Depreciation and amortization includes amortization of intangible assets of $7.2 million in fiscal years 2021 and 2020, and abandonments of equipment of $2.0 million and $4.0 million in fiscal years 2021 and 2020, respectively.

Research and Development For the fiscal years ended September 30, 2021 and 2020, we incurred $21.7 million and $21.6 million, respectively, of research and development expenses.

Selling, General and Administrative Expense Selling, general and administrative expenses increased to $172.2 million in the fiscal year ended September 30, 2021 compared to $167.5 million in the fiscal year ended September 30, 2020. The $4.7 million increase in fiscal year 2021 compared to fiscal year 2020 is primarily due to higher accrued variable compensation expense and professional service fees.

Asset Impairment During the fiscal year ended September 30, 2021, we undertook a plan to sell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the majority of which were previously decommissioned, written down and/or held as capital spares. This resulted in an impairment charge of $56.4 million ($43.3 million, net of tax, or $0.40 per diluted share. During the fiscal year ended September 30, 2021, we formalized a plan to sell assets related to two of our lower margin service offerings, trucking and casing running services, all within our North America Solutions segment. The combined book values of these assets were written down to $8.8 million, which represents their combined fair value less cost to sell, and were reclassified as held-for-sale in the Consolidated Balance Sheets as of September 30, 2021. As a result, we recognized a non-cash impairment charge of $14.4 million ($10.9 million, net of tax, or $0.10 per diluted share). Comparatively, during the fiscal year ended September 30, 2020, we recorded an asset impairment charge of $563.2 million ($437.5 million, net of tax, or $5.21 per diluted share) resulting from impairment of several assets including rotational inventory, property, plant and equipment, and goodwill.

Restructuring Charges During the fiscal years ended September 30, 2021 and 2020, we incurred $5.9 million and $16.0 million, respectively, in restructuring charges. The charges incurred during the fiscal year ended September 30, 2021 included $1.5 million in one-time severance benefits paid to employees who were voluntarily or involuntarily terminated primarily as a result of the reorganization of our IT operations coupled with charges of $4.5 million primarily related to the relocation of our Houston assembly facility and the downsizing of our storage yards used for idle rigs. The charges incurred during the fiscal year ended September 30, 2020 were primarily comprised of $19.5 million in one-time severance benefits to employees who were voluntarily or involuntarily terminated, offset by a benefit of $3.5 million related to forfeitures and modifications of stock-based compensation awards.

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Interest and Dividend Income Interest and dividend income was $10.3 million and $7.3 million in fiscal years 2021 and 2020, respectively. The increase in interest and dividend income in fiscal year 2021 was primarily due to $3.2 million of interest income received from the U.S. Department of the Treasury related to a tax refund, partially offset by lower interest rates.

Interest Expense Interest expense totaled $24.0 million in fiscal year 2021 and $24.5 million in fiscal year 2020. Interest expense is primarily attributable to fixed‑rate debt outstanding.

Income Taxes We had an income tax benefit of $103.7 million in fiscal year 2021 compared to an income tax benefit of $140.1 million in fiscal year 2020. The effective income tax rate was 23.5 percent in fiscal year 2021 compared to 22.0 percent in fiscal year 2020. The effective rates differ from the U.S. federal statutory rate (21.0 percent for fiscal years 2021 and 2020) due to non-deductible permanent items, state and foreign income taxes, and adjustments to the deferred state income tax rate.

Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated, and necessary allowances are provided. The carrying values of the net deferred tax assets are based on management’s judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future. See Note 8—Income Taxes to our Consolidated Financial Statements for additional income tax disclosures.

Discontinued Operations Expenses incurred within the country of Venezuela are reported as discontinued operations. Our wholly-owned subsidiaries, 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 2021 and 2020 is primarily a result of the impact of exchange rate fluctuations due to the remeasurement of an uncertain tax liability.

North America Solutions

The following table presents certain information with respect to our North America Solutions reportable segment:

(1)These operating metrics allow investors to analyze the various components of segment financial results in terms of activity, utilization and other key results.  Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results.  Beginning in the first quarter of fiscal year 2021, these operating metrics replaced previously used per day metrics. As a result, prior year comparative information is also provided above.

Segment Gross Margin The North America Solutions segment gross margin was $252.9 million for the fiscal year ended September 30, 2021 compared to $532.1 million for the fiscal year ended September 30, 2020. The decrease was primarily driven by lower activity levels, lower early termination revenue, lower average rig pricing, and higher rig recommissioning expenses. Revenues were $1.0 billion and $1.5 billion in fiscal year 2021 and 2020, respectively. The decrease in operating revenue is primarily due to the factors mentioned above. Included in revenues for fiscal year 2021 is early termination revenue of $5.8 million

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compared to $68.8 million during fiscal year 2020. Fixed‑term contracts customarily provide for termination at the election of the customer, with an early termination payment to be paid to us if a contract is terminated prior to the expiration of the fixed term (except in limited circumstances including sustained unacceptable performance by us). Direct operating expenses decreased to $773.5 million during the fiscal year ended September 30, 2021 as compared to $942.3 million during the fiscal year ended September 30, 2020 primarily due to the factors mentioned above.

Depreciation Depreciation expense decreased to $392.4 million during the fiscal year ended September 30, 2021 as compared to $438.0 million during the fiscal year ended September 30, 2020. The decrease is primarily attributable to the absence of depreciation on the 71 rigs that were reclassified as held-for-sale during the second and third quarters of fiscal year 2021 and rig impairments during fiscal year 2020, in addition to ongoing low levels of capital expenditures.

Asset Impairment Charge During the fiscal year ended September 30, 2021, we undertook a plan to sell 71 Domestic non-super-spec rigs, all within our North America Solutions segment, the majority of which were previously decommissioned, written down and/or held as capital spares. This resulted in an impairment charge of $56.4 million ($43.3 million, net of tax, or $0.40 per diluted share. During the fiscal year ended September 30, 2021, we formalized a plan to sell assets related to two of our lower margin service offerings, trucking and casing running services, all within our North America Solutions segment. The combined net book values of these assets were written down to $8.8 million, which represents their combined fair value less cost to sell, and were reclassified as held-for-sale in the Consolidated Balance Sheets as of September 30, 2021. As a result, we recognized a non-cash impairment charge of $14.4 million ($10.9 million, net of tax, or $0.10 per diluted share). Comparatively, during the fiscal year ended September 30, 2020, we recorded an impairment charge of $406.5 million ($313.7 million, net of tax, or $3.76 per diluted share) resulting from our impairment of our Domestic Conventional, FlexRig3, and FlexRig4 asset groups, in addition to our in-progress drilling equipment, rotational inventory and goodwill.

Restructuring Charges For the fiscal years ended September 30, 2021 and 2020, we incurred $3.9 million and $7.0 million, respectively, in restructuring charges. The charges incurred during the fiscal year ended September 30, 2021 primarily included charges of $3.8 million related to the relocation of the Houston assembly facility and the downsizing of storage yards used for idle rigs. The charges incurred during the fiscal year ended September 30, 2020 were primarily comprised of $10.0 million in one-time severance benefits to employees who were voluntarily or involuntarily terminated, offset by a benefit of $3.0 million related to forfeitures and modifications of stock-based compensation awards.

Offshore Gulf of Mexico

The following table presents certain information with respect to our Offshore Gulf of Mexico reportable segment: