What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-26 compared with 2025-02-27 · 100 added, 110 removed, 163 unchanged (56% of the section changed)

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Our services are key in supporting a global energy transition by maximizing production of existing oil and gas reserves, decommissioning end-of-life oil and gas fields and supporting renewable energy developments.

Industry Influences and Market Environment

Demand for our services is primarily influenced by the condition of the oil and gas and the renewable energy markets and, in particular, the level of spending of offshore energy companies on operational activities and capital projects.

The performance of our business is largely affected by the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, global health, and various other factors.

Demand for decommissioning is affected by commodity prices as well as governmental regulations and political forces globally.

Oil prices continue to be volatile but have generally remained robust during 2024.

Global demand for oil continues to experience growth albeit at slower rates, and although we believe the current oil and gas pricing warrants continued customer spending for the industry, higher levels of economic and industry uncertainty may temper such customer spending.

Factors that could threaten the current commodity price environment persist, including regional conflicts, governmental regulations, geopolitical instability and uncertainty, unrest in the Middle East, OPEC+ decisions, the global economy and the demand for oil and gas in China in particular, various governmental and customer sustainability initiatives and continued shifting of resource allocation to renewable energy.

We expect these factors will continue to contribute to commodity price volatility with the potential to temper customer spending for oil and gas projects.

We maximize production of existing oil and gas reserves for our customers primarily in our Well Intervention segment.

Historically, drilling rigs have been the asset class used for offshore well intervention work, and rig day rates are a pricing indicator for our services.

Historically, drilling rigs have been the asset class used for offshore well intervention work, and rig rates are a pricing indicator for our services.

Our customers have used drilling rigs on existing long-term contracts (rig overhang) to perform well intervention work instead of new drilling activities.

Current volumes of work, rig utilization rates, the day rates quoted by drilling rig contractors and existing rig overhang affect the utilization and/or rates we can achieve for our assets and services.

In the current market environment, we continue to see oil and gas companies invest in long-cycle offshore exploration projects in addition to maintain and/or increase production from their existing reserves.

As production enhancement through well intervention is less expensive per incremental barrel of oil than exploration, we expect oil and gas companies to continue to focus on optimizing production of their existing subsea wells in addition to their exploration activities.

Once end-of-life oil and gas wells have depleted their production, we decommission wells and infrastructure in our Well Intervention and Shallow Water Abandonment segments.

Our operations service the life cycle of an oil and gas field and provide P&A and decommissioning services at the end of the life of a field as required by governmental regulations.

We believe that our well intervention vessels have a competitive advantage in performing these services efficiently and with our suite of shallow water assets and capabilities, we are the only provider capable of providing all facets of decommissioning services in the U.S.

Gulf Coast shelf.

The demand for P&A services should grow over the mid- to long-term as the subsea tree base expands, as government regulations continue to place stronger emphasis on decommissioning aged wells worldwide (including subsea trees as well as mature dry tree wells in the shallow waters of the U.S.

Gulf Coast), as customers look to reduce their decommissioning obligations and as customers shift resources to renewable energy.

We support the energy transition to renewable energy primarily in our Robotics segment through our services in offshore wind farm developments, primarily including subsea cable trenching and burial as well as seabed clearance and preparation services.

Demand for our services in the renewable energy market is affected by various factors, including the pace of consumer shift towards renewable energy sources, global electricity demand, technological advancements that increase the generation and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water and other regions, and government subsidies for renewable energy projects and/or other governmental regulations supporting or restricting renewable energy developments, for instance, the 2025 Wind Energy Ban.

We expect growth in our renewables services as the global energy market continues offshore renewable energy developments.

Current volumes of work, rig utilization rates, the rates quoted by drilling rig contractors and existing rig overhang affect the utilization and/or rates we can achieve for our well intervention assets and services.

Once end-of-life oil and gas wells have depleted their production, we P&A and decommission wells and infrastructure in our Well Intervention and Shallow Water Abandonment segments.

We believe that our well intervention vessels have a competitive advantage in performing these services more efficiently than rigs, and with our suite of shallow water assets and capabilities, we are the only provider capable of providing all facets of decommissioning services in the Gulf of America shelf.

We support renewable energy primarily in our Robotics segment through our services in offshore wind farm developments, including subsea cable trenching and burial as well as seabed clearance and preparation services.

Demand for our services in the renewable energy market is affected by various factors, including the level of offshore wind farm projects, the pace of industry shift towards renewable energy sources, global electricity demand, technological advancements that increase the generation and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water and other regions, and government subsidies for renewable energy projects and/or other governmental regulations supporting or restricting renewable energy developments.

Current Market Environment

Commodity prices dropped 20% during 2025 and have been volatile throughout the year.

The current energy market remains uncertain following the ongoing escalation of tariffs and geopolitical tensions globally and their impact on the global economy and energy demands.

The offshore oil and gas market continues to evaluate governmental regulations and changes thereto, including the ongoing effects of the U.K.

government’s Energy Profits Levy, geopolitical instability and uncertainty, regional conflicts and tensions, unrest in the Middle East, Ukraine and Venezuela, and customer spending declines following mergers in the U.K.

These factors have shifted spending decisions of our customers into 2026 and prolonged a supply and demand imbalance for offshore vessels, which has negatively impacted activity levels and rates in regions in which we operate.

The international wind market continues to be robust, with continued activity and sanctioned work primarily in Europe and Asia Pacific.

wind farm activity has decreased and remains uncertain following the 2025 Wind Energy Ban, a Presidential Memorandum issued in the U.S.

in January 2025 temporarily withdrawing wind energy leasing in the U.S.

Outer Continental Shelf.

Business Activity Summary

During 2024, our operating results improved significantly as we continued to execute on our energy transition strategy with significant improvements in utilization and rates in our Well Intervention and Robotics segments.

During 2024, we also executed significant new contracts on the strength of the market and the demand for our services.

These contracts added significant backlog and will provide strong utilization for our vessels and equipment over multiple years.

Notable contracts include:

● Six-month contract with options on the Q4000 in Nigeria, which commenced in the fourth quarter 2024 ;

● Trident extension at improved rates on the Siem Helix 1 for one year through 2025;

● New three-year contracts with Petrobras on the Siem Helix 1 and the Siem Helix 2 at improved rates;

● Two-year contract with Shell in the U.S.

Gulf Coast on the Q5000 for a minimum of 175 days per year;

During 2025, we experienced declined activity levels in the North Sea and Gulf of America with lower customer spending due to the uncertain market environment.

However, we were able to maintain significant backlog that will provide strong utilization for our vessels and equipment over multiple years.

Notable new contracts executed in 2025 include:

● Four-year trenching agreement with NKT in the North Sea;

● Renewables trenching contract with Seaway 7 for estimated 300 days in the North Sea;

● Three-year framework agreement with ExxonMobil for well decommissioning work in the Gulf of America shelf;

● Well Intervention contract in the Gulf of America for a minimum of 150 days over a three-year period;

● Multi-year riserless P&A contract in the North Sea on up to 34 subsea wells;

● Extension of the agreement with HWCG for the HFRS through March 31, 2027;

● Extension of the agreement for the HP I for one year until at least June 1, 2027 .

● Extension of our contract with Shell in Brazil on the Q7000 to a minimum of 400 days.

During 2024, we extended the charters on the Siem Helix 1 , the Siem Helix 2 , the Grand Canyon II and the Shelia Bordelon .

We also entered in or extended various facility leases across all regions.

We completed the redemption of the Convertible Senior Notes due 2026 (the “2026 Notes”) during the first quarter 2024.

In August 2024, we extended the maturity of the Amended ABL Facility to August 2029 and increased the letter of credit basket size in order to facilitate increased bonding needs on the Q4000 Nigeria campaign and various windfarm projects.

We maintain our capital allocation policy of maintaining low levels of Net Debt, maintaining our existing assets, investing in targeted acquisitions that complement and further our strategy, and using Free Cash Flow to return cash to shareholders through share repurchases (See “Results of Operations — Non-GAAP Financial Measures” below for definitions of Net Debt and Free Cash Flow).

During 2025, we executed and/or extended various leases including the charters on the Trym, the North Sea Enabler , and the Patriot , which was delivered to us in January 2026.

We continue to maintain our capital allocation policy of maintaining low levels of Net Debt, maintaining our existing assets, opportunistically targeting markets that complement and further our strategy, and using Free Cash Flow to return cash to shareholders through share repurchases (See “Results of Operations — Non-GAAP Financial Measures” below for definitions of Net Debt and Free Cash Flow).

Our 2026 performance should be supported by our existing backlog, of which $694 million is for contracts over the next 12 months, as well as expected new contracting and the materialization of work that had been deferred from 2025.

We expect to see continued strong market demand for our Robotics services, in particular our trenching and site preparation offerings.

We anticipate an ongoing challenged market for certain of our assets not under long-term contracts, namely in spot markets for our Well Intervention segment, specifically in the North Sea and on the Q4000 and the Q7000 , and in our Shallow Water Abandonment segment, during which time we expect a soft rate environment and uncertain utilization of those vessels and systems.

Beyond 2026, we anticipate increasing energy consumption will continue to place demand for our services in both the oil and gas and renewable energy sectors.

We believe these needs will continue to increase customer operating expenditure budgets and demand for our production enhancement offerings and decommissioning services internationally, which should grow over the mid- to long-term as the subsea tree base expands and as customers discharge their decommissioning obligations.

We expect long-term growth in our renewables services as the global demand for energy increases and the international energy market continues offshore renewable energy developments.

We expect the demand for shallow water decommissioning services in the Gulf of America to also improve over time as former owners address their decommissioning obligations related to oil and gas properties that have reverted to them following bankruptcies.

Our backlog is represented by signed contracts.

As of December 31, 2025, our consolidated backlog totaled $1.3 billion, of which $694 million is expected to be performed in 2026.

As of December 31, 2024, our various contracts with Shell and ExxonMobil globally, our contracts with Trident Energy and Petrobras in Brazil, our contracts with Talos in the U.S.

Gulf Coast represented approximately 90% of our total backlog.

As of December 31, 2023, our consolidated backlog totaled $850 million.

Backlog is not necessarily a reliable indicator of revenues derived from our contracts as services are often added but may sometimes be subtracted;

contracts may be renegotiated, deferred, canceled and in many cases modified while in progress;

and reduced rates, fines and penalties may be imposed by our customers.

As of December 31, 2025, our various contracts with Shell and Subsea 7 globally, our contracts with Petrobras in Brazil, our contracts with Talos in the Gulf of America, and our new multi-year agreements with NKT and CNR in the North Sea collectively represented approximately 82% of our total backlog.

As of December 31, 2024, our consolidated backlog totaled $1.4 billion.

Backlog is not necessarily a reliable indicator of revenues derived from our contracts as (i) services are often added but may sometimes be subtracted;

(ii) contracts may be renegotiated, deferred, canceled and in many cases modified while in progress;

and (iii) reduced rates, fines and penalties may be imposed by our customers.

Furthermore, our contracts are in certain cases cancelable without penalty.

If there are cancellation fees, the amount of those fees can be substantially less than amounts reflected in backlog.

In 2025, we expect to continue our strong performance, supported by new contracting in 2024 at improved rates that increased backlog and driven by increasing demand for our decommissioning services internationally and continued growth in the offshore renewables trenching market.

We expect the demand for shallow water decommissioning services in the U.S.

Gulf Coast to improve as oil and gas properties revert to former owners due to bankruptcies, who are expected to address their decommissioning obligations.

RESULTS OF OPERATIONS

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EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other data prepared in accordance with GAAP.

We define EBITDA as earnings before income taxes, net interest expense, gains and losses on equity investments, net other income or expense, and depreciation and amortization expense.

Non-cash impairment losses on goodwill and other long-lived assets are also added back if applicable.

To arrive at our measure of Adjusted EBITDA, we exclude gains or losses on disposition of assets, acquisition and integration costs, gains or losses related to convertible senior notes, the change in fair value of contingent consideration and the general provision (release) for current expected credit losses, if any.

We define EBITDA as earnings before income taxes, net interest expense, net other income or expense, and depreciation and amortization expense.

To arrive at our measure of Adjusted EBITDA, we exclude gains or losses on disposition of assets, long-lived asset impairment losses, acquisition and integration costs, gains or losses related to convertible senior notes, the change in fair value of contingent consideration and the general provision for (release of) current expected credit losses, if any.

We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from asset sales and insurance recoveries (related to property and equipment), if any.

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Depreciation and amortization

Gain on equity investment

(Gain) loss on disposition of assets, net

Long-lived asset impairment

Acquisition and integration costs

Change in fair value of contingent consideration

General provision (release) for current expected credit losses

General provision for (release of) current expected credit losses

Losses related to convertible senior notes

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Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities.

All material intercompany transactions between the segments have been eliminated in our consolidated financial statements, including our consolidated results of operations.

All material intercompany transactions between the segments have been eliminated in our consolidated financial statements.

The following table details various financial and operational highlights for the periods presented (dollars in thousands):

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(1) Represents the number of vessels, Robotics assets or Shallow Water Abandonment systems as of the end of the period, including spot vessels and those under term charters, and excluding acquired vessels prior to their in-service dates, vessels managed on behalf of third parties and vessels or assets disposed of and/or taken out of service.

(2) Represents the average utilization rate, which is calculated by dividing the total number of days the vessels, Robotics assets or Shallow Water Abandonment systems generated revenues by the total number of calendar days in the applicable period.

Utilization rates of chartered Robotics vessels in 2024 and 2023 included 371 and 310 spot vessel days, respectively, at near full utilization.

(3) Consists of ROVs, trenchers and IROV boulder grabs.

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Shallow Water Abandonment

The following table sets forth significant financial statement items below the gross profit (loss) line (in thousands):

Year Ended December 31,

Long-lived asset impairment

Selling, general and administrative expenses

Net interest expense

Losses related to convertible senior notes

Other expenses, net

Income tax provision

Net Revenues.

Our consolidated net revenues increased by 5% in 2024 as compared to 2023, reflecting higher revenues in our Well Intervention, Robotics and Production Facilities business segments, offset in part by lower revenues in our Shallow Water Abandonment segment.

Our Well Intervention revenues increased by 17% in 2024 as compared to 2023, primarily reflecting higher overall utilization and rates.

Utilization increased on the Q4000 and the Q5000 during 2024 as both vessels underwent their regulatory dry docks in 2023.

The Q7000 had higher utilization and higher integrated project rates during 2024 as compared to 2023.

The Seawell ‘s contract in the western Mediterranean, which completed in June 2024, has provided higher rates and utilization during 2024 as compared to 2023.

The Well Enhancer in the North Sea had lower utilization as compared to the prior year as the vessel underwent a scheduled dry dock during the first quarter 2024 and both vessels saw a fourth quarter seasonal slowdown in 2024 whereas the vessels were nearly fully utilized in 2023.

Our North Sea revenues also included a contract cancellation fee of approximately $14 million related to work that had been scheduled for 2025.

The Siem Helix 1 had higher revenues during 2024 as compared to 2023 due to Trident contract extensions with higher rates.

The Siem Helix 2 had lower utilization during 2024 as the vessel commenced its unpaid vessel acceptance period at the end of December 2024 on its new contract with Petrobras.

Our Robotics revenues increased by 15% in 2024 as compared to 2023, primarily reflecting higher chartered vessel days and trenching and ROV activities.

Chartered vessel activity increased to 1,901 days during 2024 as compared to 1,699 days during 2023, although chartered vessel days in 2024 included approximately 64 days of standby utilization at reduced rates.

Overall ROV and trencher utilization increased to 69% in 2024 from 62% during 2023 and included 835 days of integrated vessel trenching in 2024 as compared to 807 days in 2023.

Our Shallow Water Abandonment revenues in 2024 decreased by 32% in 2024 as compared to 2023.

The decrease in revenues was due to lower activity levels and an overall softer U.S.

Gulf Coast shelf market in 2024, resulting in lower vessel and system utilization during 2024 as compared to 2023.

Overall vessel utilization was 60% during 2024 as compared to 74% during 2023.

Our consolidated net revenues decreased by 5% in 2025 as compared to 2024, reflecting lower revenues in our Well Intervention and Production Facilities business segments, offset in part by higher revenues in our Robotics and Shallow Water Abandonment segments.

Our Well Intervention revenues decreased by 12% in 2025 as compared to 2024, primarily reflecting overall lower utilization, offset in part by higher rates during 2025.

Utilization declined primarily due to the stacking of the Seawell in the North Sea during the entirety of 2025 whereas the vessel had 86% utilization during 2024.

Utilization also declined as the Q4000 , the Q5000 and the Q7000 collectively underwent 131 docking days during 2025 as compared to 10 days on the Sea Helix 1 during 2024.

Additionally, revenues in 2024 included $14 million of contract cancellation fees related to work that had been planned for 2025.

Revenue decreases were offset in part by higher rates on the Well Enhancer , and in Brazil in 2025.

Our Robotics revenues increased by 9% in 2025 as compared to 2024, primarily reflecting increased trenching on third party vessels and higher project rates on our vessel activities, offset in part by lower overall vessel and ROV utilization during 2025.

Robotics generated 483 days of trenching on third-party vessels during 2025 as compared to 167 days during 2024.

However, vessel utilization decreased to 1,808 days (including 75 spot vessel days at full utilization) during 2025 as compared to 1,901 days (including 371 spot vessel days at full utilization) during 2024.

Included in vessel days are integrated vessel trenching days, which decreased to 635 days in 2025 as compared to 835 days in 2024, and site clearance vessel days, which increased to 503 days as compared to 325 days in 2024.

Overall ROV utilization decreased to 59% during 2025 as compared to 69% during 2024.

Our Shallow Water Abandonment revenues increased by 7% in 2025 as compared to 2024.

The increase in revenues was primarily due to higher utilization on our systems and on the Epic Hedron heavy lift barge.

P&A systems and CT systems achieved 2,686 days of utilization, or 28%, during 2025 as compared to 2,281 days of utilization, or 24%, during 2024.

Our Production Facilities revenues increased slightly in 2024 as compared to 2023, primarily reflecting higher oil and gas production and lower number of shut-in days on our owned oil and gas wells, offset in part by lower rates on the HFRS, which were reduced in the second half 2024 when the Q4000 left the U.S.

Gulf Coast to execute the Nigeria project.

Utilization on the Epic Hedron heavy lift barge was 58% during 2025 as compared to 44% during 2024.

Vessel utilization (excluding heavy lift) declined to 53% during 2025 as compared to 61% during 2024.

Our Production Facilities revenues decreased by 18% in 2025 as compared to 2024, primarily reflecting lower oil and gas production volumes with the Thunder Hawk field being shut in during 2025 after having had approximately seven months of production in 2024.

The Droshky field had lower production in 2025 as compared to 2024 and realized oil prices were lower by 12% year over year.

Gross Profit (Loss).

Our consolidated 2024 gross profit increased by $19.2 million as compared to 2023, primarily reflecting increased profits from our Well Intervention, Robotics and Production Facilities business segments, offset in part by losses from our Shallow Water Abandonment segment.

Our Well Intervention gross profit increased by $63.4 million in 2024 as compared to 2023, primarily reflecting higher segment revenues and increased activity levels and included a contract cancellation fee of approximately $14 million.

Our Robotics gross profit increased by $27.7 million in 2024 as compared to 2023, primarily reflecting higher revenues and higher profit margin projects during 2024.

Our Shallow Water Abandonment gross loss was $0.8 million in 2024 as compared to a gross profit of $71.3 million in 2023, primarily reflecting lower segment revenues without a commensurate cost reduction.

Our Production Facilities gross profit increased slightly in 2024 as compared to 2023, primarily reflecting higher segment revenues.

Change in Fair Value of Contingent Consideration.

The change in fair value of contingent consideration reflects an improvement in Helix Alliance’s results during 2023.

We entered into an agreement and set the final earnout during the fourth quarter 2023, which was paid on April 3, 2024 (Note 3).

Our consolidated 2025 gross profit decreased by $60.4 million as compared to 2024, primarily reflecting reduced profitability from our Well Intervention, Robotics and Production Facilities business segments, offset in part by increased profitability from our Shallow Water Abandonment segment.

Our Well Intervention gross profit decreased by $70.0 million in 2025 as compared to 2024, primarily reflecting lower overall revenues, offset in part by lower vessel costs on the Seawell due to the vessel being warm-stacked in 2025 and higher cost deferrals related to the dockings during 2025.

Our Robotics gross profit decreased by $6.5 million in 2025 as compared to 2024, primarily reflecting lower margins on certain projects due to the mix of contracting, offset in part by higher revenues during 2025.

Our Shallow Water Abandonment gross profit was $17.9 million in 2025 as compared to a gross loss of $0.8 million in 2024, primarily reflecting higher overall revenues and higher margin contracting during 2025.

Our Production Facilities gross profit decreased by $2.6 million in 2025 as compared to 2024, primarily due to lower revenues, offset in part by lower workover costs on the Thunder Hawk field during 2025.

Long-Lived Asset Impairment.

The $18.1 million non-cash impairment loss in 2025 was attributable to the impairment of the remaining net book value of the Thunder Hawk field (Note 5).

Selling, General and Administrative Expenses.

Our selling, general and administrative expenses were $91.7 million in 2024 as compared to $94.4 million in 2023, primarily reflecting a net decrease in compensation related costs offset partially by an increase in other facilities and professional fees in 2024.

Our selling, general and administrative expenses were $75.9 million in 2025 as compared to $91.7 million in 2024, primarily reflecting decreases in employee compensation-related costs during 2025.

Net Interest Expense.

Our net interest expense totaled $22.6 million in 2024 as compared to $17.3 million in 2023, primarily reflecting higher debt levels and rates on our $300 million Senior Notes due 2029 (the “2029 Notes”) in 2024 as compared to our 2026 Notes in 2023, offset in part by higher interest income on our invested cash (Note 7).

Our net interest expense totaled $22.8 million in 2025 as compared to $22.6 million in 2024, primarily reflecting lower interest income on our invested cash (Note 7).

Losses Related to Convertible Senior Notes.

The losses during 2024 and 2023 were primarily associated with the retirement of our 2026 Notes (Note 7).

The losses during 2024 were associated with the redemption of our Convertible Senior Notes due 2026 (the “2026 Notes”) (Note 7).

Other Expense, Net.

Net other expense was $3.9 million in 2024 as compared to $3.6 million in 2023.

Net other expense during 2024 primarily reflects a $2.4 million increase in the value of incentive credits granted to the seller of P&A equipment acquired in 2023 (Note 4) and foreign currency losses due to the weakening of the British pound and Brazilian real in 2024.

Net other expense during 2023 primarily reflects foreign currency losses related to the devaluation of the Nigerian naira on our naira cash holdings, offset in part by foreign currency gains due to the strengthening of the British pound in 2023.

Net other expense was $1.4 million in 2025 as compared to $3.9 million in 2024, primarily reflecting a $2.4 million charge in 2024 associated with the increase in the value of incentive credits issued to the seller of P&A equipment acquired in 2023.

Income Tax Provision.

Income tax provision was $11.7 million for 2025 as compared to $26.4 million for 2024.

The effective tax rates for 2024 and 2023 were 32.2% and 244.2%, respectively.

These variances were primarily attributable to the increase in income before taxes as well as the earnings mix between our higher and lower tax rate jurisdictions.

The effective tax rate for 2025 was impacted by certain discrete items, additional foreign tax credit benefits and the jurisdictional mix of earnings.

The effective rate for 2024 was impacted by the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event.

Comparison of Years Ended December 31, 2024 and 2023

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Net working capital measures short-term liquidity and is important for predicting cash flow and debt requirements.

Net working capital at December 31, 2023 included $85.0 million of Alliance earnout consideration that was paid in cash on April 3, 2024.

Long-Term Debt

Long-term debt in the table above, presented net of unamortized debt discount and debt issuance costs, includes our MARAD Debt, the 2026 Notes and the 2029 Notes and excludes current maturities of $9.2 million and $48.3 million, respectively, at December 31, 2024 and 2023.

Long-term debt in the table above, presented net of unamortized debt discount and debt issuance costs, includes the 2029 Notes and the MARAD Debt, excluding current maturities of $9.6 million and $9.2 million, respectively, at December 31, 2025 and 2024.

For information relating to our long-term debt, see Note 7 to our consolidated financial statements included in Item 8 .

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Our liquidity at December 31, 2025 included $445.2 million of cash and cash equivalents and $110.9 million of available borrowing capacity under the Amended ABL Facility (Note 7) and excluded $2.5 million of pledged cash.

Our liquidity at December 31, 2023 included $332.2 million of cash and cash equivalents and $99.3 million of available borrowing capacity under the Amended ABL Facility.

The reduction in availability on the facility at December 31,2024 was attributable to higher letter of credit usage in order to support the Nigeria project on the Q4000 .

In the current market environment, we expect strong ongoing operating performance and cash flows.

Our liquidity at December 31, 2024 included $368.0 million of cash and cash equivalents and $66.6 million of available borrowing capacity under the Amended ABL Facility and excluded $5.0 million of pledged cash.

We believe that our cash on hand, internally generated cash flows and availability under the Amended ABL Facility will be sufficient to fund our operations and expected capital spending, service our debt and other obligations, and execute our share repurchase program over at least the next 12 months.

Although we expect lower levels of availability on the Amended ABL Facility while the Q4000 performs work in Nigeria due to fewer eligible receivables and higher letter of credit usage, we currently do not anticipate borrowing under the Amended ABL Facility and expect to only use the facility for the issuance of letters of credit.

A period of weak industry activity may make it difficult to comply with the covenants and other restrictions in our debt agreements.

Our failure to comply with the covenants and other restrictions could lead to an event of default.

Decreases in our borrowing base may limit our ability to fully access the Amended ABL Facility.

We currently do not anticipate borrowing under the Amended ABL Facility except for the issuance of letters of credit.

The following table provides summary data from our consolidated statements of cash flows (in thousands):

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Operating Activities

The increase in our operating cash flows for 2024 as compared to 2023 primarily reflects higher operating income, lower regulatory recertification costs for our vessels and systems and working capital inflows.

Operating cash outflows during 2024 included net interest expense and taxes paid of $25.4 million and $14.1 million, respectively.

Operating cash outflows during 2024 also included $58.3 million of the $85.0 million earnout payment on April 3, 2024, representing the amount in the excess of the $26.7 million initial fair value of earnout consideration at the Alliance acquisition date.

Regulatory recertification spend on our vessels and systems amounted to $35.4 million and $62.5 million, respectively, during the comparable year over year periods.

Cash flows provided by operating activities for 2025 decreased as compared to 2024 despite the absence of an earnout payment, primarily reflecting lower earnings, higher regulatory certification costs on our vessels and systems and net working capital outflows.

Our operating cash outflows during 2024 included $58.3 million of the $85.0 million earnout payment on April 3, 2024.

Regulatory certification costs, which are considered part of our capital spending program but are classified in operating cash flows, were $52.0 million in 2025 compared to $35.4 million in 2024.

Investing Activities

Cash flows used in investing activities for 2024 increased as compared to 2023 primarily due to higher capital expenditures with increased activity in our Robotics segment.

Cash flows used in investing activities for 2025 decreased as compared to 2024 primarily due to lower capital expenditures in our Well Intervention and Robotics segments.

Financing Activities

Net cash outflows from financing activities for 2025 primarily reflect the repurchases of $30.2 million in our common stock under the 2023 Repurchase Program and related excise tax payments, principal repayment of $9.2 million related to the MARAD Debt and payments in satisfaction of tax obligations upon vesting of share-based awards.

Net cash outflows from financing activities for 2024 primarily reflect cash outflows of $60.7 million related to the 2026 Notes, $26.7 million of the $85.0 million earnout payment, the principal repayment of $8.7 million related to the MARAD Debt and $29.6 million in repurchases of our common stock under the 2023 Repurchase Program.

These outflows were offset in part by $4.4 million of cash inflows from the proportionate settlement of the 2026 Capped Calls.

Net cash inflows from financing activities for 2023 primarily reflect net proceeds of $292.0 million from the issuance of $300.0 million 2029 Notes and of $15.6 million from the proportionate settlement of the 2026 Capped Calls, offset in part by cash outflows of $230.7 million related to the repurchase of the 2026 Notes, $30.4 million related to the maturity of the Convertible Senior Notes due 2023, the principal repayment of $8.3 million related to the MARAD Debt and $12.0 million in repurchases of our common stock under the 2023 Repurchase Program.

Material Cash Requirements

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Long-term debt and other contractual commitments

The following table summarizes (in thousands) the principal amount of our long-term debt and related debt service costs as well as other contractual commitments, which include commitments for property and equipment and operating lease obligations, as of December 31, 2024 and the portions of those amounts that are short-term (due in less than one year) and long-term (due in one year or greater) based on their stated maturities.

Our property and equipment commitments include contractually committed amounts to purchase and service certain property and equipment (inclusive of commitments related to regulatory recertification and dry dock as discussed below) but do not include expected capital spending that is not contractually committed as of December 31, 2024.

The following table summarizes (in thousands) the principal amount of our long-term debt and related debt service costs as well as other contractual commitments, which include commitments for operating lease obligations and property and equipment, as of December 31, 2025 and the portions of those amounts that are short-term (due in less than one year) and long-term (due in one year or greater) based on their stated terms.

Our property and equipment commitments include contractually committed amounts to purchase and service certain property and equipment (inclusive of commitments related to regulatory certification and dry dock as discussed below) but do not include expected capital spending that is not contractually committed as of December 31, 2025.

Interest related to debt

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(1) Operating leases include vessel charters and facility and equipment leases, including commitments related to leases executed but not yet commenced.

At December 31, 2024, our commitment related to long-term vessel charters totaled approximately $835.5 million, of which $434.3 million was related to the non-lease (services) components that are not included in operating lease liabilities in the consolidated balance sheet as of December 31, 2024 .

At December 31, 2025, our commitment related to long-term vessel charters that have commenced totaled approximately $724.9 million, of which $366.9 million was related to the non-lease (services) components that are not included in operating lease liabilities in the consolidated balance sheet as of December 31, 2025 .

Other material cash requirements

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We have decommissioning obligations associated with our oil and gas properties (Note 15).

Those obligations, which are presented on a discounted basis on the consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk Field oil and gas properties and $37.1 million (undiscounted) for Droshky oil and gas properties as of December 31, 2024, none of which is expected to be paid during the next 12 months.

We are entitled to receive $30.0 million (undiscounted) from Marathon Oil Corporation as certain decommissioning obligations associated with Droshky oil and gas properties are fulfilled.

Those obligations, which are presented on a discounted basis on the consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk field oil and gas properties and $37.1 million (undiscounted) for Droshky field oil and gas properties as of December 31, 2025.

We are entitled to receive $30.0 million (undiscounted) from Marathon Oil Corporation as certain decommissioning obligations associated with Droshky field oil and gas properties are fulfilled.

Regulatory certification and dry dock.

Our vessels and systems are subject to certain regulatory recertification requirements that must be satisfied in order for the vessels and systems to operate.

Recertification may require dry dock and other compliance costs on a periodic basis, usually every 30 months.

Our vessels and systems are subject to certain regulatory certification requirements that must be satisfied in order for the vessels and systems to operate.

Certification may require dry dock and other compliance costs on a periodic basis, usually every 30 months.

Although the amount and timing of these costs may vary and are dependent on the timing of the certification renewal period, they generally range between $0.2 million to $15.0 million per vessel and $0.5 million to $5.0 million per system.

We expect the sources of funds to satisfy our material cash requirements to primarily come from our ongoing operations and existing cash on hand, but may also come from availability under the Amended ABL Facility and access to capital markets.

We expect the sources of funds to satisfy our material cash requirements to primarily come from our ongoing operations and existing cash on hand.

Although not currently expected to be utilized, we also have availability under the Amended ABL Facility and access to capital markets.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

19 unchanged sentences

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

What changed 10-K

Item 7. Management’s Discussion and Analysis