Helmerich & Payne, Inc. (HP)

CIK: 0000046765. SIC: 1381 Drilling Oil & Gas Wells. Latest 10-K as of: 2025-11-21.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1381 Drilling Oil & Gas Wells

SEC company page: https://www.sec.gov/edgar/browse/?CIK=46765. Latest filing source: 0000046765-25-000071.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2025-11-21. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000046765.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-07. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000046765.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0000046765-26-000034.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-07. Report date: 2026-03-31.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10‑Q (“Form 10‑Q”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Form 10-Q are forward-looking statements. Forward-looking statements may be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “predict,” “project,” “target,” “continue,” or the negative thereof or similar terminology, and such statements include, but are not limited to, statements regarding the Acquisition and the anticipated benefits and impact of such transaction, the timing and terms of recommencement of suspended rigs related to the Acquisition, our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management. Forward-looking statements are based upon current plans, estimates, and expectations that are subject to risks, uncertainties, and assumptions, many of which are beyond our control and any of which could cause actual results to differ materially from those expressed in or implied by the forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. The inclusion of such statements should not be regarded as a representation that such plans, estimates, or expectations will be achieved.

Factors that could cause actual results to differ materially from those expressed in or implied by such forward-looking statements include, but are not limited to:

•our ability to achieve the strategic and other objectives relating to the Acquisition;

•the risk that we are unable to integrate KCA Deutag International Limited's ("KCA Deutag") operations in a successful manner and in the expected time period;

•the volatility of future oil and natural gas prices;

•contracting of our rigs and actions by current or potential customers;

•the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing nations (together, “OPEC+”) with respect to production levels or other matters related to the prices of oil and natural gas;

•changes in future levels of drilling activity and capital expenditures by our customers, whether as a result of global capital markets and liquidity, changes in prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs, or increase our capital expenditures and the construction, upgrade or acquisition of rigs;

•changes in worldwide rig supply and demand, competition, or technology;

•possible cancellation, suspension, renegotiation or termination (with or without cause) of our contracts as a result of general or industry-specific economic conditions, mechanical difficulties, performance or other reasons;

•expansion and growth of our business and operations;

•our belief that the final outcome of our legal proceedings will not materially affect our financial results;

•the impact of federal, state and foreign legislative and regulatory actions and policies, affecting our costs and increasing operating restrictions or delay and other adverse impacts on our business;

•environmental or other liabilities, risks, damages or losses, whether related to storms or hurricanes (including wreckage or debris removal), collisions, grounding, blowouts, fires, explosions, other accidents, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;

•the impact of geopolitical developments and tensions, war and uncertainty involving or in the geographic region of oil-producing countries (including the ongoing armed conflicts between Russia and Ukraine, the military conflict with Iran and the associated disruption to the Strait of Hormuz, other conflicts in the Middle East, and any related political or economic responses and counter-responses or otherwise by various global actors or the general effect on the global economy);

Q2 FY26 FORM 10-Q | 31

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•global economic conditions, such as a general slowdown in the global economy, supply chain disruptions, inflationary pressures, the impact of new or additional tariffs, currency fluctuations, and instability of financial institutions, and their impact on the Company;

•our financial condition and liquidity;

•tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;

•the occurrence of security incidents, including breaches of security, or other attack, destruction, alteration, corruption, or unauthorized access to our information technology systems or destruction, loss, alteration, corruption or misuse or unauthorized disclosure of or access to data;

•potential impacts on our business resulting from climate change, greenhouse gas regulations, and the impact of climate change related changes in the frequency and severity of weather patterns;

•potential long-lived asset impairments; and

•our sustainability strategy, including expectations, plans, or goals related to corporate responsibility, sustainability and environmental matters, and any related reputational risks as a result of execution of this strategy.

Additional factors that could cause actual results to differ materially from our expectations or results discussed in the forward‑looking statements are disclosed in our 2025 Annual Report on Form 10‑K under Part I, Item 1A— “Risk Factors” and Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All subsequent written and oral forward‑looking statements, express or implied, are expressly qualified in their entirety by such cautionary statements.

All forward-looking statements speak only as of the date they are made and are based on information available at that time. Because of the underlying risks and uncertainties, we caution you against placing undue reliance on these forward-looking statements. We assume no duty to update or revise these forward‑looking statements based on changes in internal estimates, expectations or otherwise, except as required by law.

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 March 31, 2026, our drilling rig fleet included a total of 337 drilling rigs. Our reportable operating business segments consist of the North America Solutions segment with 203 rigs, the International Solutions segment with 130 rigs, and the Offshore Solutions segment with four offshore platform rigs as of March 31, 2026. Although the Offshore Solutions segment has a fleet of platform rigs, the majority of its revenues are derived from asset-light management contracts. At the close of the second quarter of fiscal year 2026, we had 204 active contracted rigs, of which 138 were under a fixed-term contract and 66 were working well-to-well, compared to 208 contracted rigs at September 30, 2025. 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.

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. Over time, however, E&Ps have become more fiscally disciplined in their level of capital expenditures relative to commodity price fluctuations and the amount of free cash flows that can be returned to their shareholders, which has resulted in more stable and predictable demand for oilfield service businesses, including our operations.

Q2 FY26 FORM 10-Q | 32

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In early calendar year 2025, the announcements by the U.S. government regarding the implementation of global tariffs and OPEC+ regarding the planned increase of crude oil supply created continued uncertainty in the global energy markets. More recently, heightened geopolitical tensions in the Middle East including ongoing armed conflict and instability affecting key energy-producing and transit regions, such as the Strait of Hormuz, and ongoing political developments in Venezuela have perpetuated and elevated the level of uncertainty further. These developments have contributed to increased volatility in global crude oil and natural gas prices and have led market participants to reassess supply risks, transportation reliability, and near-term capital allocation decisions. Although we do not anticipate that these announcements and events will have a direct material impact on the Company's operations or financial results, we believe the indirect effects of sustained geopolitical uncertainty, including the potential for supply-side disruptions and transportation risks may support increased drilling activity levels as operators seek to mitigate these potential disruptions and respond to elevated or more volatile commodity prices. Both crude oil and natural gas prices are volatile and global economic conditions heavily influence activity levels in the United States. In our international operations, commodity pricing has an impact on potential activity by our customers; however, other variables have a heavy influence on those activity levels, including disparate country budgets and the need to fund other commitments in certain areas.

During the six months ended March 31, 2026, we received notifications to resume operations on seven rigs in Saudi Arabia scheduled for the first half of calendar year 2026. Of these, six rigs are expected to be operational within that timeframe, while the reactivation date for the seventh rig is yet to be determined. As a result of these resumptions, the total number of operating rigs in the country is projected to reach 23 by the middle of calendar year 2026.

Recent Developments

Assets Held-for-Sale

In October 2025, we committed to a plan to scrap certain rigs and related assets across our operating segments as part of our fleet rationalization strategy. As a result, these assets were reclassified as held-for-sale and, where applicable, written down to fair value less cost to sell. This resulted in non-cash impairment charges of $97.9 million and $2.1 million in the North America Solutions and Offshore Solutions segments, respectively during the six months ended March 31, 2026.

Additionally, in March 2026, we identified an international drilling rig within our International Solutions segment that met the asset held-for-sale criteria and was therefore written down to fair value less cost to sell. This resulted in a non-cash impairment charge of $23.3 million during the six months ended March 31, 2026. During the six months ended March 31, 2026, we also recognized a non-cash impairment c

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2025-11-21. Report date: 2025-09-30.

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.

2025 FORM 10-K | 40

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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. During the second quarter of fiscal year 2025, the naming convention for one of our reportable segments changed from Offshore Gulf of Mexico to Offshore Solutions. Beginning on the Closing Date, Offshore Solutions now includes the results from the acquired KCA Deutag offshore management contract operations. Similarly, our International Solutions segment now includes the results from the acquired KCA Deutag land operations. Operating results related to KCA Deutag's BENTEC™ business unit are included in "Other" along with results from our real estate operations and our wholly-owned captive insurance companies. Our North America Solutions operating segment remains unchanged. For additional information regarding the completion of the Acquisition, refer to Note 3—Business Combination.

As of September 30, 2025, our drilling rig fleet included a total of 367 drilling rigs. Our reportable operating business segments consist of the North America Solutions segment with 223 rigs, the International Solutions segment with 137 rigs, and the Offshore Solutions segment with seven offshore platform rigs as of September 30, 2025. Although the Offshore Solutions segment has a fleet of platform rigs, the majority of its revenues are derived from asset-light management contracts. At the close of fiscal year 2025, we had 208 active contracted rigs, of which 131 were under a fixed-term contract and 77 were working well-to-well, compared to 170 contracted rigs at September 30, 2024. 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.

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 and the amount of free cash flows that can be returned to their shareholders, which has resulted in less volatility within the oilfield service businesses, including our operations.

Earlier in calendar 2025, the announcements by the U.S. government regarding the implementation of global tariffs and OPEC+ regarding the planned increase of crude oil supply created continued uncertainty in the global energy markets. More recently, heightened geopolitical tensions in the Middle East have perpetuated and elevated the level of uncertainty further. Although we do not anticipate that these announcements and events, particularly the tariff announcements and the armed conflict in the Middle East, will have a direct material impact on the Company's operations or financial results, we believe the indirect effects could potentially lead to reduced activity in fiscal year 2026 as operators evaluate activity levels commensurate with commodity prices. Both crude oil and natural gas prices are volatile and global economic conditions heavily influence activity levels in the United States. In our international operations, commodity pricing has an impact on potential activity by our customers; however, other variables have a heavy influence on those activity levels, including disparate country budgets and the need to fund other commitments in certain areas.

Subsequent to September 30, 2025, we received notifications for seven rigs to resume operations in Saudi Arabia during the first half of calendar year 2026. With the rig resumptions, the total operating rig count in country will increase to 24 total rigs by the middle of calendar year 2026.

Recent Developments

KCA Deutag Acquisition

On the Closing Date, H&P completed the Acquisition of KCA Deutag pursuant to the Purchase Agreement. H&P paid aggregate cash consideration of approximately $2.0 billion, which consisted of the share purchase price of $0.9 billion and $1.1 billion which was used to contemporaneously repay or redeem certain of KCA Deutag existing debt, including, as applicable, the payment of all accrued and unpaid interest, premiums, and fees. The cash consideration was funded through a combination of net proceeds from the Company’s September 2024 senior notes offering, net proceeds from the funding of the Company’s Term Loan Credit Agreement, cash on hand, and monetization of our investment in ADNOC Drilling.

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KCA Deutag is a diverse global drilling company. The company derives a significant portion of its revenues and cash flow from its land operations and has a substantial land drilling presence in the Middle East with additional operations in South America, Europe, and Northern Africa. In addition to its land operations, the company has asset-light offshore management contract operations in the North Sea, Angola, Azerbaijan and Canada. Management contract operations provide services to customer platforms where the customer owns the drilling rig. KCA Deutag’s BENTEC™ (formally Kenera) business unit comprises manufacturing and engineering operations with four facilities serving the energy industry.

Subsequent to the announcement of the Acquisition in July 2024 through September 2025, KCA Deutag and the Company have received notifications of contract suspensions for rigs from the legacy KCA Deutag rig fleet operating in Saudi Arabia. Through September 30, 2025, the Company's total rig suspensions were 27 rigs. Subsequent to the fiscal year ended September 30, 2025, we received resumption notices for seven rigs. The suspended rigs are expected to resume performance in fiscal year 2026.

At the time the Acquisition was announced, we initially expected to realize approximately $25 million in synergies. Since that time, we have been able to conduct a more detailed analysis of possible synergies, and we also launched a broader review of our enterprise cost structure. We now anticipate realizing in excess of our original expectations from the combination of synergies associated with the Acquisition and other permanent cost-saving initiatives (such as our workforce reduction plan discussed in Note 16—Restructuring Charges) and expect our general and administrative expenses will be reduced by $50 million relative to our pro forma annualized expectations. We believe these cost-saving efforts will become increasingly evident in the forthcoming quarters.

Subsequent to September 30, 2025, we announced the rebranding of KCA Deutag’s Kenera business unit to BENTEC™. The BENTEC™ name, already recognized in the market, will now represent all products and services previously associated with Kenera and its sub-brands. Accordingly, throughout this document and in future references, Kenera will be referred to as BENTEC™.

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, 2025 and 2024, our contract drilling backlog was $7.0 billion and $1.5 billion, respectively. The increase in backlog at September 30, 2025 compared to 2024 is primarily due to the completion of the Acquisition. The total backlog figures for the International Solutions and Offshore Solutions reporting segments, as of September 30, 2025 include $3.4 billion and $2.3 billion, respectively, are attributable to our recently acquired subsidiary, KCA Deutag. Approximately 22.6 percent of the September 30, 2025 total backlog is reasonably expected to be fulfilled in fiscal year 2026.

The following table sets forth the total backlog by reportable segment as of September 30, 2025 and 2024:

(in billions)

September 30, 2025

September 30, 2024

Firm contracts1:

North America Solutions

$

0.5 

$

0.7 

International Solutions

3.4 

0.8 

Offshore Solutions

0.9 

— 

$

4.8 

$

1.5 

Optional contract extension periods:

International Solutions2

0.7 

— 

Offshore Solutions

1.5 

— 

2.2 

— 

Total backlog

$

7.0 

$

1.5 

(1)These amounts do not include anticipated contract renewals or expected performance bonuses.

(2)Included in the International Solutions reportable segment's optional backlog balance at September 30, 2025 is $478.5 million of expected revenue from certain contracts in Saudi Arabia that have been temporarily suspended and are expected to gradually resume operations. The information presented in the table above reflects the fact that we expect these contracts to be extended for a period of time at least equal to the suspension period.

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The early termination of a contract or suspension of operations 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. The agreements within our recently acquired subsidiary, KCA Deutag, contain provisions for optional early termination or suspension without any associated early termination fees. Early terminations could cause the actual amount of revenue earned to significantly 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 fully realized as fixed‑term contracts and, in certain instances, these contracts can be terminated without an early termination payment or suspended without standby or force majeure compensation.” 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 could have a material adverse effect on our business, financial condition and results of operations." within this Form 10-K. Subsequent to September 30, 2025, we received an early termination notice for one of our rigs operating within the International Solutions segment. As a result, our total backlog as of September 30, 2025 reflects approximately $34.9 million of revenue that we no longer expect to recognize in future periods.

Results of Operations for the Fiscal Years Ended September 30, 2025 and 2024

The Company's results presented for the fiscal year ended September 30, 2025 reflect a full 365 days of legacy H&P operations and 258 days of KCA Deutag operations, as the Acquisition was completed on January 16, 2025.

Consolidated Results of Operations

Net Income (Loss) Attributable to Helmerich & Payne Inc. We recorded a loss of $163.7 million ($1.66 loss per diluted share) for the fiscal year ended September 30, 2025 compared to income of $344.2 million ($3.43 per diluted share) for the fiscal year ended September 30, 2024.

Operating Revenue Consolidated operating revenues were $3.7 billion and $2.8 billion during fiscal years 2025 and 2024, respectively. The increase was primarily driven by the completion of the Acquisition, resulting in an additional $1.0 billion of revenue during the fiscal year ended September 30, 2025.

Direct Operating Expenses, Excluding Depreciation and Amortization Direct operating expenses in fiscal year 2025 were $2.5 billion, compared to direct operating expenses of $1.6 billion in fiscal year 2024. The increase was primarily driven by the completion of the Acquisition, resulting in an additional $789.7 million in direct operating expenses during the fiscal year ended September 30, 2025.

Other Operating Expenses Other operating expenses were $56.0 million and $4.5 million during fiscal years 2025 and 2024, respectively. The increase was primarily driven by the completion of the Acquisition, resulting in an additional $51.3 million of costs associated with BENTEC™'s manufacturing and engineering operations.

Depreciation and Amortization Depreciation and amortization expense was $625.1 million in fiscal year 2025 and $397.3 million in fiscal year 2024. The increase was primarily driven by the completion of the Acquisition, resulting in an additional $212.2 million in depreciation and amortization expense during the fiscal year ended September 30, 2025. Depreciation and amortization includes amortization of intangible assets of $50.6 million and $6.4 million and abandonments of equipment of $2.9 million and $6.5 million in fiscal years 2025 and 2024, respectively.

Research and Development Expense Research and development expense was $34.1 million and $41.0 million in fiscal years 2025 and 2024, respectively. The decrease was primarily driven by an asset acquisition completed during the fiscal year ended September 30, 2024, along with reductions in project scope implemented as part of the Company’s cost-reduction initiatives.

Selling, General and Administrative Expense Selling, general and administrative expenses increased to $287.1 million in the fiscal year ended September 30, 2025 compared to $244.9 million in the fiscal year ended September 30, 2024. The increase in fiscal year 2025 is primarily driven by the completion of the Acquisition, resulting in an additional $48.3 million in selling, general and administrative expenses during the fiscal year ended September 30, 2025.

Acquisition Transaction Costs During the fiscal year ended September 30, 2025, we recognized approximately $54.7 million in acquisition transaction costs associated with the Acquisition. These non-recurring costs are primarily related to third-party legal, advisory and valuation services. See Note 3—Business Combination for additional details related to the Acquisition.

Asset Impairment Charges During the fiscal year ended September 30, 2025, we recorded asset impairment charges of $194.0 million primarily driven by a non-cash goodwill impairment charge of $192.2 million associated with our International Solutions and BENTEC™ reporting units. See Note 6—Goodwill and Intangible Assets for additional details related to the impairment charges.

Restructuring Charges During the fiscal year ended September 30, 2025, we recorded restructuring charges of $12.1 million primarily driven by a one-time severance payments to involuntarily terminated employees.

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Interest and Dividend Income Interest and dividend income was $35.2 million and $41.2 million in fiscal years 2025 and 2024, respectively. The decrease primarily reflects the liquidation of our investment in ADNOC Drilling during the year ended September 30, 2025, which resulted in no dividend income for the period compared to $11.1 million in dividend income recognized during the year ended 2024, partially offset to high market interest rates in fiscal year 2025.

Interest Expense Interest expense totaled $107.8 million in fiscal year 2025 and $29.1 million in fiscal year 2024. The increase was primarily driven by interest expense associated with our September 2024 senior notes offering and Term Loan Credit Agreement. For additional information regarding debt agreements, refer to Note 7—Debt to the Consolidated Financial Statements.

Gain (Loss) on Investment Securities During the fiscal year ended September 30, 2025, we recognized an aggregate loss of $22.4 million on investment securities. The aggregate loss consisted primarily of a $29.6 million loss on our investment in Galileo, due to an allowance for credit loss on the convertible note, driven by heightened liquidity constraints and changes in governance, which led management to conclude that the fair value of the investment was not recoverable and a $12.4 million loss on our sale of equity securities in ADNOC Drilling, of which $8.4 million is associated with the change in the fair value of the investment and $4.0 million relates to transaction fees associated with the sale of the securities. The loss was partially offset by $15.4 million and $5.0 million of gains on various geothermal equity investments and our investment in Tamboran, respectively, due to changes in the fair value of the investments. 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 investment 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 a $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.

Income Taxes We had an income tax expense of $85.8 million in fiscal year 2025 compared to an income tax expense of $136.9 million in fiscal year 2024. The effective income tax rate was (115.8) percent in fiscal year 2025 compared to 28.5 percent in fiscal year 2024. The effective rates differ from the U.S. federal statutory rate (21.0 percent for the fiscal years 2025 and 2024) primarily due to non-deductible goodwill impairment, other 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 8—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:

(in thousands, except operating statistics)

2025

2024

% Change

Operating revenues

$

2,362,327 

$

2,445,946 

(3.4)

%

Direct operating expenses

1,322,697 

1,366,471 

(3.2)

Depreciation and amortization

351,813 

366,446 

(4.0)

Research and development

34,140 

41,293 

(17.3)

Selling, general and administrative expense

68,047 

61,113 

11.3 

Acquisition transaction costs

41 

— 

— 

Asset impairment charges

1,507 

— 

— 

Restructuring charges

4,121 

— 

— 

Segment operating income

$

579,961 

$

610,623 

(5.0)

Financial Data and Other Operating Statistics1:

Direct margin (Non-GAAP)2

$

1,039,630 

$

1,079,475 

(3.7)

Revenue days3

53,523 

55,387 

(3.4)

Average active rigs4

147 

151 

(2.6)

Number of active rigs at the end of period5

144 

151 

(4.6)

Number of available rigs at the end of period

223 

228 

(2.2)

Reimbursements of "out-of-pocket" expenses

$

290,591 

$

294,375 

(1.3)

(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 for owned and leased rigs with recognized revenue 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 During fiscal year ended September 30, 2025, operating revenue decrease by $83.6 million compared to the same period in 2024. This decrease was mainly driven by reduced activity levels.

Direct Operating Expenses Direct operating expenses decreased by $43.8 million during fiscal year ended September 30, 2025. The decrease was primarily driven by reduced activity levels.

Depreciation and Amortization Depreciation and amortization expense decreased to $351.8 million during the fiscal year ended September 30, 2025 as compared to $366.4 million during the fiscal year ended September 30, 2024. The decrease was primarily driven by $12.7 million of accelerated depreciation in fiscal year 2024 for components on rigs that were scheduled for conversion.

Research and Development Expense Research and development expense decreased to $34.1 million during the fiscal year ended September 30, 2025 as compared to $41.3 million during the fiscal year ended September 30, 2024. The decrease was primarily driven by an asset acquisition completed during the fiscal year ended September 30, 2024, along with reductions in project scope implemented as part of the Company’s cost-reduction initiatives.

Selling, General and Administrative Expenses Selling, general and administrative expenses increased to $68.0 million during the fiscal year ended September 30, 2025 as compared to $61.1 million during the fiscal year ended September 30, 2024. The increase was primarily driven by a $10.0 million increase in credit loss expense related to a long-term note receivable.

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International Solutions

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

(in thousands, except operating statistics)

2025

2024

% Change

Operating revenues

$

802,426 

$

193,975 

313.7 

%

Direct operating expenses

718,822 

169,033 

325.3 

Depreciation and amortization

218,817 

10,863 

1,914.3 

Selling, general and administrative expense

17,232 

9,427 

82.8 

Acquisition transaction costs

1,585 

— 

— 

Asset impairment charges

132,720 

— 

— 

Restructuring charges

4,945 

— 

— 

Segment operating income (loss)

$

(291,695)

$

4,652 

(6,370.3)

Financial Data and Other Operating Statistics1:

Direct margin (Non-GAAP)2

$

83,604 

$

24,942 

235.2 

Revenue days3

19,985 

4,614 

333.1 

Average active rigs4

55 

13 

323.1 

Number of active rigs at the end of period5

61 

16 

281.3 

Number of available rigs at the end of period

137 

27 

407.4 

Reimbursements of "out-of-pocket" expenses

$

34,045 

$

8,482 

301.4 

(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 for owned and leased rigs with recognized revenue 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 $802.4 million and $194.0 million in the fiscal years ended September 30, 2025 and 2024, respectively. The $608.5 million increase in operating revenue was primarily driven by an additional $542.4 million in revenue generated from expanded operations following the Acquisition. Additionally, the increase in operating revenues was attributable to increased FlexRig® activity levels in Saudi Arabia from the commencement of operations for rigs previously awarded during fiscal year 2024.

Operating Expenses Direct operating expenses increased to $718.8 million during the fiscal year ended September 30, 2025 as compared to $169.0 million during the fiscal year ended September 30, 2024. This increase was primarily driven by the completion of the Acquisition, resulting in an additional $443.8 million in direct operating expenses during the fiscal year ended September 30, 2025. Additionally, the increase in direct operating expenses was attributable to start-up costs associated with our increased FlexRig® activity levels in Saudi Arabia from the commencement of operations for rigs previously awarded during fiscal year 2024.

Depreciation and Amortization Expense Depreciation expense increased to $218.8 million during the fiscal year ended September 30, 2025 compared to $10.9 million during the fiscal year ended September 30, 2024. The increase was primarily driven by the completion of the Acquisition, resulting in an additional $180.9 million in depreciation and amortization expense during the fiscal year ended September 30, 2025.

Asset Impairment Charges During the fiscal year ended September 30, 2025, we recorded a non-cash goodwill impairment charge of $132.7 million associated with our International Solutions reporting unit. See Note 6—Goodwill and Intangible Assets for additional details related to the goodwill impairment charges.

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Offshore Solutions

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

(in thousands, except operating statistics)

2025

2024

% Change

Operating revenues

$

520,394 

$

106,207 

390.0 

%

Direct operating expenses

430,135 

82,668 

420.3 

Depreciation and amortization

32,461 

7,530 

331.1 

Selling, general and administrative expense

4,619 

3,594 

28.5 

Acquisition transaction costs

2,971 

— 

— 

Restructuring charges

266 

— 

— 

Segment operating income

$

49,942 

$

12,415 

302.3 

Financial Data and Other Operating Statistics1:

Direct margin (Non-GAAP)2

$

90,259 

$

23,539 

283.4 

Revenue days3

1,095 

1,111 

(1.4)

Average active rigs4

3 

3 

— 

Number of active rigs at the end of period5

3 

3 

— 

Number of available rigs at the end of period

7 

7 

— 

Reimbursements of "out-of-pocket" expenses

$

86,662 

$

31,717 

173.2 

(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 for owned and leased rigs with recognized revenue 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 $520.4 million and $106.2 million in the fiscal year ended September 30, 2025 and 2024, respectively. The increase in operating revenue was primarily driven by an additional $407.1 million in revenue generated from expanded operations following the Acquisition.

Direct Operating Expenses Direct operating expenses increased to $430.1 million during the fiscal year ended September 30, 2025 as compared to $82.7 million during the fiscal year ended September 30, 2024. The increase was primarily driven by the completion of the Acquisition, resulting in an additional $345.9 million in direct operating expenses during the fiscal year ended September 30, 2025.

Depreciation and Amortization Expense Depreciation expense increased to $32.5 million during the fiscal year ended September 30, 2025 compared to $7.5 million during the fiscal year ended September 30, 2024. The increase was primarily driven by the completion of the Acquisition, resulting in an additional $25.7 million in depreciation and amortization expense during the fiscal year ended September 30, 2025.

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Other Operations

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

(in thousands)

2025

2024

% Change

Operating revenues

$

152,870 

$

71,630 

113.4 

%

Direct operating expenses

181,634 

69,756 

160.4 

Depreciation and amortization

5,711 

1,627 

251.0 

Research and development

353 

— 

— 

Selling, general and administrative expense

7,086 

1,606 

341.2 

Acquisition transaction costs

1,517 

— 

— 

Asset impairment charges

59,466 

— 

— 

Restructuring charges

500 

— 

— 

Operating loss

$

(103,397)

$

(1,359)

(7,508.3)

Operating Revenues We continue to use our Captive insurance companies to fund SIRs and deductibles for our domestic workers’ compensation, general liability, automobile liability claims programs, medical stop-loss program, and certain international casualty and rig property programs. Operating revenues of $152.9 million and $71.6 million during the fiscal years ended September 30, 2025 and 2024, respectively, primarily consisted of $69.2 million and $61.2 million, respectively, in intercompany premium revenues recorded by the Captives. These revenues were eliminated upon consolidation. During the fiscal year ended September 30, 2025, operating revenues also consisted of $72.3 million from BENTEC™ manufacturing and engineering operations, of which, $17.1 million is related to intercompany revenues that were eliminated upon consolidation.

Direct Operating Expenses Direct operating expenses of $181.6 million and $69.8 million during the fiscal years ended September 30, 2025 and 2024, respectively, primarily consisted of $39.9 million and $11.4 million, respectively, in adjustments to accruals for estimated losses allocated to the Captives, rig and casualty insurance premiums of $42.7 million and $37.6 million, respectively, and medical stop loss expenses of $20.7 million and $15.5 million, respectively. The change to accruals for estimated losses is primarily due to actuarial valuation adjustments by our third-party actuary. During the fiscal year ended September 30, 2025, direct operating expenses also consisted of $68.4 million from BENTEC™ manufacturing and engineering operations of which, $17.1 million is related to intercompany revenues that were eliminated upon consolidation.

Asset Impairment Charges During the fiscal year ended September 30, 2025, we recorded a non-cash goodwill impairment charge of $59.5 million associated with our BENTEC™ reporting unit. See Note 6—Goodwill and Intangible Assets for additional details related to the goodwill impairment charges.

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

A discussion of our results of operations for the fiscal year ended September 30, 2024 compared to the fiscal year ended September 30, 2023 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, 2024, filed with the SEC on November 8, 2024.

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 Acquisition. 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.

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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, 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.

Net working capital (defined as current assets less current liabilities) was $650.6 million and $745.1 million as of September 30, 2025 and September 30, 2024, respectively.

As of September 30, 2025 and 2024, we had cash and cash equivalents of $196.8 million and $217.3 million and short-term investments of $21.5 million and $292.9 million, respectively. Our cash flows for the fiscal years ended September 30, 2025, 2024 and 2023 are presented below:

Year Ended September 30,

(in thousands)

2025

2024

2023

Net cash provided by (used in):

Operating activities

$

542,950 

$

684,663 

$

833,682 

Investing activities

(1,925,342)

(458,748)

(322,584)

Financing activities

66,661 

986,507 

(463,869)

Effect of exchange rate changes on cash, cash equivalents and restricted cash

12,971 

— 

— 

Net increase (decrease) in cash and cash equivalents and restricted cash

$

(1,302,760)

$

1,212,422 

$

47,229 

Operating Activities

Cash flows provided by operating activities were approximately $543.0 million, $684.7 million, and $833.7 million for the fiscal year ended September 30, 2025, 2024, and 2023 respectively. The change in cash provided by operating activities between fiscal years 2025 and 2024 is primarily driven by start-up costs associated with our commencement of our operations in Saudi Arabia and acquisition transaction costs associated with the Acquisition. The decrease in cash provided by operating activities between fiscal years 2024 and 2023 was primarily driven by lower activity levels partially offset by higher average pricing levels. Net cash flows provided by (used) related to the change in working capital was $(79.8) million, $(38.4) million and $34.5 million as of September 30, 2025, 2024 and 2023, respectively.

Investing Activities

Capital Expenditures Our capital expenditures were $426.4 million, $495.1 million and $395.5 million in fiscal years 2025, 2024 and 2023, respectively. The decrease in capital expenditures is driven by lower equipment overhauls and certain long-term projects including skidding to walking rig conversions. Our fiscal year 2026 capital spending is currently estimated to be between $280.0 million and $320.0 million. This estimate includes normal capital maintenance requirements, planned rig-related equipment upgrades and reactivation-related capital across the global fleet of operating drilling rigs.

Net Sales of Short-Term Investments Our net sales of short-term investments during fiscal year 2025 were $261.3 million compared to net sales of $3.5 million and $14.3 million in fiscal years 2024 and 2023, respectively. The increase in activity is driven by $193.3 million of net proceeds received from the liquidation of shares in ADNOC Drilling and our ongoing liquidity management. 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.

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Net Purchases and Sales of Long-Term Investments Our net sales of long-term investments during fiscal year 2025 were $28.7 million compared to net purchases of $9.1 million and $20.7 million in fiscal years 2025, 2024 and 2023, respectively. During the year ended September 30, 2025, the increase in net sales activity is primarily driven by $27.1 million and $4.9 million of proceeds received from the liquidation of one of our equity security investments and one of our debt security investments, respectively. Our activity during the fiscal year ended September 30, 2024, was driven by $9.1 million in purchases of investments in various debt and equity securities. Our activity during the fiscal year ended September 30, 2023, was driven by purchases of 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.

Payment for the Acquisition of Business, Net of Cash Received During fiscal year 2025, H&P completed the Acquisition by paying approximately $2.0 billion in cash. This included acquiring $199.4 million in cash and cash equivalents, resulting in a net cash payment of $1.8 billion. For additional information regarding the completion of the Acquisition, refer to Note 3—Business Combination.

Sale of Assets Our proceeds from asset sales totaled $45.8 million, $46.4 million and $70.1 million in fiscal year 2025, 2024 and 2023, respectively. The decrease in proceeds compared to fiscal year 2023 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 $1.00 per share during the fiscal year 2025. Comparatively, we paid dividends of $1.68 and $1.94 per share in 2024 and 2023, respectively. Total dividends paid were $100.7 million, $168.5 million and $201.5 million in fiscal years 2025, 2024 and 2023, respectively.

Debt Issuance Proceeds and Costs On January 16, 2025, we received $400.0 million of proceeds from the Term Loan Credit Agreement. During fiscal year 2025, the Company repaid $200.0 million of the outstanding balance on the Term Loan Credit agreement. 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 and $13.3 million relates to other financing arrangements. For additional information regarding debt agreements, refer to Note 7—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 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 of $247.2 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 senior notes, comprised of the following tranches (collectively, the “Notes”): $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. Interest on the Notes is payable semi-annually on June 1 and December 1 of each year, commencing on June 1, 2025.

On January 16, 2025, H&P completed the Acquisition, and the Company used the net proceeds of the Notes, together with the proceeds of its term loan credit agreement (discussed below) and cash on hand, to finance the purchase price for the Acquisition, to repay or redeem certain of KCA Deutag’s outstanding indebtedness, and to pay related fees and expenses. For additional information regarding the completion of the Acquisition, refer to Note 3—Business Combination.

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 use commercially reasonable efforts to file with the SEC, and cause to be declared effective, a registration statement with respect to an offer to exchange each series of the Notes for freely tradable notes (“Registered Notes”) having terms identical in all material respects to each such series of Notes (the “Registered Exchange Offer”). Accordingly, on May 15, 2025, the Company filed a registration statement on Form S-4 with the SEC, which was declared effective on May 28, 2025. On May 28, 2025, the Company launched the Registered Exchange Offer, which expired on July 10, 2025. Substantially all of the Notes were tendered and exchanged for Registered Notes in the Exchange Offer.

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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 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 as amended (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, among the Company, Morgan Stanley Senior Funding, Inc. (“MSSF”), as administrative agent, and the other lenders party thereto. On the Closing Date, the Company drew an aggregate principal amount of $400.0 million under the Term Loan Credit Agreement for purposes of financing the Acquisition. 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. On January 16, 2025, H&P completed the Acquisition, and the Company used the proceeds from the Term Loan Credit Agreement, together with the net proceeds from the Notes, and cash on hand, to finance the purchase price for the Acquisition, to repay or redeem certain of KCA Deutag's outstanding indebtedness, and to pay related fees and expenses. For additional information regarding the completion of the Acquisition, refer to Note 3—Business Combination. During the fiscal year ended September 30, 2025, the Company repaid $200.0 million of the outstanding balance on the Term Loan Credit Agreement. As such, the outstanding balance as of September 30, 2025, was $200.0 million. In October 2025, we repaid $10.0 million, decreasing the outstanding balance on the Term Loan Credit Agreement to $190.0 million.

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, 2025, the spread over SOFR was 1.375 percent and commitment fees were 0.175 percent. As of September 30, 2025, the interest rate on the Term loan was 5.610 percent per annum. The weighted average variable interest rate on all amounts outstanding under the Term Loan was 5.750 percent the year ended September 30, 2025.

2024 Oman Facility

In connection with the completion of the Acquisition, KCA Deutag Energy LLC (“KCAD Energy”) became a wholly-owned subsidiary of the Company. On April 25, 2024, KCAD Energy entered into the 2024 Oman Facility, which is fully drawn.

The 2024 Oman Facility provides for term loan borrowings of $45.5 million. During the fiscal year ended September 30, 2025, our 2024 Oman Facility was amended to bear interest payable quarterly at a fixed rate of 6.00 percent per annum for two years and thereafter, at a rate that is the higher of (x) 5.00 percent and (y) the reference rate specified in the 2024 Oman Facility plus 1.75 percent. On February 9, 2025, we received the final draw down of $1.4 million. During the fiscal year ended September 30, 2025, the Company repaid $2.6 million of the outstanding balance on the facility. Of the $43.1 million borrowings outstanding at September 30, 2025, a total of $3.4 million is payable within one year. These secured bank loans are wholly denominated in Omani rial. The value of these borrowings in Omani rial is OMR 17.6 million. The commitments under the 2024 Oman Facility mature December 31, 2034.

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There is an annual financial covenant in the 2024 Oman Facility that requires KCAD Energy to maintain a debt service coverage ratio of at least 1.20:1.00. The 2024 Oman Facility and related agreements contain additional terms, conditions, restrictions and covenants that we believe are usual and customary in secured debt arrangements for companies of similar size and credit quality.

2023 Oman Facility

In connection with the completion of the Acquisition, KCAD Energy became a wholly-owned subsidiary of the Company. On June 19, 2023, KCAD Energy entered into the 2023 Oman Facility, which is fully drawn.

The 2023 Oman Facility provides for term loan borrowings of $45.6 million. During the fiscal year ended September 30, 2025, our 2023 Oman Facility was amended to bear interest payable quarterly at a fixed rate of 6.00 percent per annum for two years and thereafter, at a rate that is the higher of (x) 5.00 percent and (y) the reference rate specified in the 2023 Oman Facility plus 1.75 percent. During the fiscal year ended September 30, 2025, the Company repaid $2.6 million of the outstanding balance on the facility. Of the $39.8 million borrowings outstanding at September 30, 2025, a total of $3.4 million is payable within one year. These secured bank loans are wholly denominated in Omani rial. The value of these borrowings in Omani rial is OMR 17.6 million. The commitments under the 2023 Oman Facility mature December 31, 2033.

There is an annual financial covenant in the 2023 Oman Facility that requires KCAD Energy to maintain a debt service coverage ratio of at least 1.20:1.00. The 2023 Oman Facility and related agreements contain additional terms, conditions, restrictions and covenants that we believe are usual and customary in secured debt arrangements for companies of similar size and credit quality.

Amended Credit Facility

On August 14, 2024, the Company entered into an Amended and Restated Credit Agreement (the "Amended Credit Facility") with the lenders party thereto (the "Revolving Credit Agreement Lenders"), the issuing lenders party thereto and Wells Fargo ("Wells Fargo") as administrative agent, swingline 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. $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 .001 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 .005, or (iii) the one-month adjusted SOFR rate plus .01. 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, 2025, 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, 2025, 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, 2025, we had $400.0 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 $400.0 million, $186.4 million was outstanding as of September 30, 2025.

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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, 2025, 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 2026 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, 2025 and is 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. Our indebtedness under our unsecured term loan credit agreement totaled $200.0 million at September 30, 2025 and matures in January 2027. Our indebtedness under our secured term loan credit agreements totaled $82.9 million at September 30, 2025, of which $6.9 million is due within one year, and the remaining balance is required to be paid on a quarterly basis through the respective maturity dates of December 2033 and December 2034. This debt is allocated specifically to finance the ongoing rig construction activities in Oman.

As of September 30, 2025, we had a $624.0 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.

As of September 30, 2025, we have recorded approximately $23.9 million of unrecognized tax benefits, interest, and penalties. We believe approximately $6.9 million of the unrecognized tax benefits, interest, and penalties will be recognized as of December 31, 2025, as the result of payment of an assessed amount. 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.

Material Commitments

Our contractual obligations as of September 30, 2025 are summarized in the table below:

Obligations due by fiscal year

(in thousands)

Total

2026

2027

2028

2029

2030

Thereafter

Long-term debt

2,082,880 

6,859 

206,859 

356,860 

8,577 

360,862 

1,142,863 

Interest1

510,300 

89,387 

83,990 

70,176 

66,994 

52,240 

147,513 

Operating leases2

158,086 

31,067 

17,672 

15,888 

14,677 

12,777 

66,005 

Purchase obligations3

124,840 

124,840 

— 

— 

— 

— 

— 

Total contractual obligations

$

2,876,106 

$

252,153 

$

308,521 

$

442,924 

$

90,248 

$

425,879 

$

1,356,381 

(1)Interest on fixed-rate unsecured senior 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, 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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Fair Value Estimates in Business Combination Accounting

In addition to the critical accounting policies and estimates previously disclosed, due to the Acquisition, we also consider estimates used in applying the acquisition method of accounting in accordance with ASC Topic 805, Business Combinations, to be part of our critical accounting policies and estimates due to the high degree of judgment and complexity in its application. The acquisition method of accounting involves the allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed. This allocation process involves the use of estimates and assumptions made in connection with estimating the fair value of assets acquired and liabilities assumed including cash flows expected to be derived from the use of the asset, the timing of such cash flows, the remaining useful life of assets, estimated asset replacement costs, and applicable discount rates. Acquisition accounting allows for up to one year to obtain the information necessary to finalize the fair value of all assets acquired and liabilities assumed at January 16, 2025. During September 2025, we finalized the allocation of the purchase price. Refer to Note 3—Business Combination to the accompanying Consolidated Financial Statements for additional information about accounting for the Acquisition.

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. Except for the property, plant and equipment acquired in connection with the Acquisition, there were no significant changes to the determinations of useful lives or salvage values during the fiscal years presented in this Form 10-K. 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.

During the third fiscal quarter of 2025, due primarily to the sustained decline in our share price and market capitalization, we identified indicators of potential impairment of goodwill and performed an interim impairment test. We estimated the fair value of each reporting unit using a market approach, incorporating significant unobservable, or Level 3, inputs, as defined by the fair value hierarchy. We employed a combination of the guideline public company method and the guideline transactions method, leveraging company comparisons and analyst reports from the energy industry, which supported a range of fair values derived from annualized earnings before interest, income taxes, depreciation and amortization ("EBITDA") multiples between 2.5x and 5.5x for guideline public companies and between 3.4x and 7.6x for guideline transactions. We then derived an estimated fair value of each reporting unit based on an EBITDA multiple at or below the peer-median trading multiple.

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Based on our interim goodwill impairment test as of June 30, 2025, we concluded that the International Solutions and BENTEC™ (formally Kenera) reporting units' carrying value exceeded their respective estimated fair value. As a result, we recorded a non-cash goodwill impairment charge of $128.4 million and $44.9 million, respectively, which represented a full impairment of the goodwill allocated to these reporting units. The estimated fair values of our H&P Technologies and Offshore Solutions reporting units as of June 30, 2025 exceeded their respective carrying values by approximately 76 percent and 20 percent, respectively. During the three months ended September 30, 2025, primarily as a result of measurement period adjustments, we recorded an additional $4.4 million and $14.5 million in impairment expense related to the International Solutions and BENTEC™ reporting units, respectively. Our annual review of goodwill during the fourth fiscal quarter of 2025 did not result in any additional impairments.

Due to the goodwill impairment described above, we also considered whether there was an indicator of impairment of our long-lived assets (including our finite-lived intangible assets) as of June 30, 2025. Although our market capitalization has decreased due to factors in the equities market, we believe there has not been a material change in our long-term cash flow projections, significant change in the business environment, or loss of one or more significant customers that would indicate potential impairment of our long-lived assets which, unlike goodwill, are evaluated for impairment based on undiscounted future cash flows. Based on these considerations, we concluded there were no indicators of impairment as it related to our long-lived assets as June 30, 2025. These determinations were based on conditions at the time; should circumstances change, our conclusions could materially differ. Our annual review of long-lived assets during the fourth fiscal quarter of 2025 did not identify any impairment indicators.

See Note 6—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 America. 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, SIRs and 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 SIRs and 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.

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 SIRs, 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.

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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 U.S. GAAP and should therefore be considered only as supplemental to such U.S. 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 U.S. GAAP that is most directly comparable to direct margin.

(in thousands)

Year Ended September 30, 2025

Year Ended September 30, 2024

NORTH AMERICA SOLUTIONS

Segment operating income

$

579,961 

$

610,623 

Add back:

Depreciation and amortization

351,813 

366,446 

Research and development

34,140 

41,293 

Selling, general and administrative expense

68,047 

61,113 

Acquisition transaction costs

41 

— 

Asset impairment charges

1,507 

— 

Restructuring charges

4,121 

— 

Direct margin (Non-GAAP)

$

1,039,630 

$

1,079,475 

INTERNATIONAL SOLUTIONS

Segment operating income (loss)

$

(291,695)

$

4,652 

Add back:

Depreciation and amortization

218,817 

10,863 

Selling, general and administrative expense

17,232 

9,427 

Acquisition transaction costs

1,585 

— 

Asset impairment charges

132,720 

— 

Restructuring charges

4,945 

— 

Direct margin (Non-GAAP)

$

83,604 

$

24,942 

OFFSHORE SOLUTIONS

Segment operating income

$

49,942 

$

12,415 

Add back:

Depreciation and amortization

32,461 

7,530 

Selling, general and administrative expense

4,619 

3,594 

Acquisition transaction costs

2,971 

— 

Restructuring charges

266 

— 

Direct margin (Non-GAAP)

$

90,259 

$

23,539