VAL Valaris Ltd - 10-K

RISK FACTORS SUMMARY

An investment in our securities involves a high degree of risk. You should consider carefully all of the risks described below, together with the other information contained in this Form 10-K, before making a decision to invest in our securities. If any of the following events occur, our business, financial condition and operating results may be materially adversely affected. In that event, the trading price of our securities could decline, and you could lose all or part of your investment.

Risks Related to the Business Combination

• Our pending Business Combination may be delayed or not occur at all for a variety of reasons.

• Efforts to complete the Business Combination could disrupt our relationships with third parties and employees, divert management's attention, or result in negative publicity or legal proceedings.

• The Business Combination Agreement contains provisions that limit our ability to pursue alternatives to the Business Combination.

• The Business Combination Agreement restricts our business activities.

Risks Related to Our Business, Operations, Financing Arrangements and Market Conditions

• The success of our business depends on the level of activity in offshore oil and natural gas exploration, development and production, which can be significantly affected by volatile oil and natural gas prices.

• The offshore contract drilling industry is highly competitive and cyclical.

• Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future.

• Our business will be materially adversely affected if we are unable to secure contracts on economically favorable terms or if option periods in existing contracts are not exercised as expected.

• Our customers may be unable or unwilling to fulfill their contractual commitments to us, including their obligations to pay for losses, damages or other liabilities.

• The loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, could materially adversely affect our business.

• Our long-term contracts are subject to the risk of cost increases.

• Our network and systems are subject to cybersecurity risks and technical disruptions.

• Rig reactivation, upgrade and enhancement projects are subject to risks, including delays and cost overruns.

• We make significant expenditures for a variety of reasons, including to maintain our competitiveness.

• Failure to recruit and retain skilled personnel could adversely affect our business.

• Our use of a shared service center creates risks relating to the processing of transactions and recording of financial information.

• AI presents risks and challenges that can impact our business.

• We may not realize the expected benefits of our ARO joint venture, and joint venture investments could be adversely affected by our joint venture partners’ actions, financial condition and liquidity and disputes between us and our joint venture partners.

• Our business involves operating hazards, and our insurance and indemnities from our customers may not be adequate to cover any potential losses.

• Geopolitical events and violence could materially adversely affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.

• Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.

• Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility with regard to the management of our personnel.

• Significant equipment or part shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could materially adversely affect us.

• Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in our operating revenues.

• Our ability to pay our operating and capital expenses and make payments due on our debt depends on many factors beyond our control.

• The agreements governing our debt contain various covenants that impose restrictions on us and certain of our subsidiaries.

• We may experience risks associated with future mergers, acquisitions or dispositions of businesses or assets, including our drilling rigs, or other strategic transactions.

• The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute the holders of our Common Shares.

Regulatory, Legal and Tax Risks

• Failure to comply with anti-corruption and anti-bribery statutes could result in fines, criminal penalties and drilling contract terminations.

• Increasing regulatory complexity could adversely impact our operations and reduce demand.

• Compliance with or breach of environmental laws can be costly and limit our operations.

• The U.S. Internal Revenue Service (“IRS”) may not agree with the conclusion that we should be treated as a foreign corporation for U.S. federal tax purposes.

• Governments may pass laws that subject us to additional taxation or may challenge our tax positions.

• Our consolidated effective income tax rate may vary substantially over time.

• We are subject to litigation that could have a material adverse effect on us.

• We are a Bermuda company, and it may be difficult enforcing judgments against us, our directors and officers.

• Our bye-laws restrict shareholders from bringing legal action against our officers and directors and provisions in our bye-laws could delay or prevent a change in control of our company.

• Legislation enacted in Bermuda as to Economic Substance may affect our business.

• Our business could be affected as a result of activist investors.

Risks Related to Our International Operations

• Our non-U.S. operations involve risks not typically associated with U.S. operations, and we are subject to additional risks associated with the expansion into new geographic markets.

Sustainability Risks

• Regulation of GHG, consumer preferences for alternative fuels and electric powered vehicles and climate change could have a negative impact on our business.

• Increased scrutiny from stakeholders and others regarding our sustainability practices, initiatives and reporting responsibilities could result in additional costs or risks.

Item 1A.    Risk Factors

Risks Related to the Business Combination

Our pending Business Combination may be delayed or not occur at all for a variety of reasons, some of which are outside of the parties’ control, and if these conditions are not satisfied, the Business Combination Agreement may be terminated and the Business Combination may not be completed.

On February 9, 2026, Valaris and Transocean (Valaris and Transocean, collectively, the “Parties” and each, a “Party”), entered into a business combination agreement (the “Business Combination Agreement”), providing for the combination of the two Parties (the “Business Combination”). Pursuant to the Business Combination Agreement, and on the terms and subject to the conditions thereof, Transocean will acquire all of the issued and outstanding common shares of Valaris in exchange for shares of Transocean at an exchange ratio of 15.235 Transocean shares for each Valaris share. The Business Combination will be effected by way of a court-approved scheme of arrangement between Valaris and the holders of the Valaris shares pursuant to section 99 of the Companies Act 1981 of Bermuda, as amended. Following the consummation of the Business Combination, Transocean’s existing shareholders and Valaris’ existing shareholders will own approximately 53% and 47%, respectively, of the combined company on a fully diluted basis assuming conversion to shares of Transocean’s exchangeable bonds due 2029.

Completion of the Business Combination is subject to customary closing conditions, including (1) the receipt of the requisite approvals of the Valaris shareholders and the Transocean shareholders, (2) the granting of the sanction order on terms consistent with the Business Combination Agreement, (3) the Transocean shares issued pursuant to the Business Combination Agreement having been approved for listing on the NYSE, (4) certain regulatory approvals having been obtained or any applicable waiting period having expired or been terminated, (5) no governmental authority within applicable jurisdictions having enacted or issued any law or order preventing or prohibiting the consummation of the Business Combination and (6) the absence of a Transocean Material Adverse Effect or a Valaris Material Adverse Effect (as each are defined in the Business Combination Agreement). Therefore, the Business Combination Agreement may not be completed or may not be completed as timely as expected.

In addition, the Business Combination Agreement also contains certain customary termination rights in favor of each Party, including for the failure to receive the requisite approvals of the Valaris shareholders and Transocean shareholders. A Party may terminate the Business Combination Agreement, prior to the receipt of the requisite approval of the other Party’s shareholders, if the other Party shall have made an Adverse Recommendation Change (as defined in the Business Combination Agreement). Either Valaris or Transocean may terminate the Business Combination Agreement if the effective time shall not have occurred on or prior to February 9, 2027 (as such date may be extended in accordance with the terms of the Business Combination Agreement).

Failure to complete the Business Combination could adversely affect our business and the market price of our common shares in a number of ways, including:

• The market price of our common shares may decline to the extent that the current market price reflects an assumption that the Business Combination will be consummated;

• If the Business Combination Agreement is terminated under certain circumstances specified in the Business Combination Agreement, we would be required to pay a termination fee of approximately $173.0 million to Transocean, and in other specified circumstances where the Business Combination Agreement is terminated following the failure to obtain the requisite shareholder approval and the above referenced termination fee is not otherwise payable, if Valaris shareholders failed to approve the transactions contemplated by the Business Combination Agreement, Valaris will be required to reimburse Transocean’s transaction expenses up to $58 million;

• We have incurred, and will continue to incur, significant expenses for professional services in connection with the Business Combination Agreement for which we will have received little or no benefit if the Business Combination Agreement is not consummated; and

• A failed Business Combination Agreement may result in negative publicity and/or give a negative impression of us in the investment community, with our customers and our other stakeholders.

Efforts to complete the Business Combination could disrupt our relationships with third parties and employees, divert management’s attention, or result in negative publicity or legal proceedings, any of which could negatively impact our operating results and ongoing business.

We have expended, and continue to expend, significant management time and resources in an effort to complete the Business Combination, which may have a negative impact on our ongoing business and operations. Uncertainty regarding the outcome of the Business Combination and our future could disrupt our business relationships with our existing and potential customers, suppliers and other business partners, who may attempt to negotiate changes in existing business relationships or consider entering into business relationships with parties other than us, or terminate or amend contracts. Uncertainty regarding the outcome of the Business Combination could also adversely affect our ability to recruit and retain key personnel and other employees. The pendency of the Business Combination may also result in negative publicity and a negative impression of us in the financial markets, and may lead to litigation against us and our directors and officers. Such litigation could be distracting to management and, may, in the future, require us to incur significant costs. Such litigation could result in the Business Combination being delayed and/or enjoined by a court of competent jurisdiction, which could prevent the Business Combination from becoming effective. The occurrence of any of these events individually or in combination could have a material and adverse effect on our business, financial condition and results of operations.

The Business Combination Agreement contains provisions that limit our ability to pursue alternatives to the Business Combination which could discourage a potential competing acquiror from making an alternative transaction proposal.

The Business Combination Agreement contains provisions that subject Valaris to certain restrictions on its ability to solicit an alternative acquisition proposal from third parties, to provide non-public information to third parties and to engage in discussions with third parties regarding alternative acquisition proposals, subject to customary exceptions. Each Party is required to call a meeting of its shareholders to obtain the required approval of such Party’s shareholders described above and, subject to certain exceptions, to recommend that their respective shareholders approve such proposals. Neither Party has the ability to terminate to accept a Superior Proposal (as defined in the Business Combination Agreement).

Additionally, if the Business Combination Agreement is terminated and we determine to seek another business combination, we may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the Business Combination.

While the Business Combination Agreement is in effect, we are subject to restrictions on our business activities.

The Business Combination Agreement generally requires us to operate our business in the ordinary course consistent with past practices. It also imposes customary interim operating covenants that restrict us from taking specified actions, subject to certain exceptions, until the Business Combination is completed or until the Business Combination Agreement is terminated, including, but not limited to, our ability to amend our organizational documents; declare dividends or repurchase shares; encumber assets; make acquisitions or dispositions; incur or guarantee indebtedness; enter into, or amend, any material contract.

Risks Related to Our Business, Operations, Financing Arrangements and Market Conditions

The success of our business depends on the level of activity in offshore oil and natural gas exploration, development and production, which can be significantly affected by volatile oil and natural gas prices.

The success of our business depends on the level of activity in offshore oil and natural gas exploration, development and production. Oil and natural gas prices, and market expectations of these prices, significantly affect the level of drilling activity. Historically, when operator capital spending declines, utilization and day rates also decline.

Numerous factors may affect oil and natural gas prices and the level of demand for our services, including:

• regional and global economic conditions and changes therein, including recessions,

• oil and natural gas supply and demand, which is affected by worldwide economic activity and population growth,

• expectations regarding future energy prices,

• the desire and ability of OPEC+, its members and certain other oil-producing nations, such as Russia, to reach further agreements to set and maintain production levels and pricing and to implement existing and future agreements, including the ability of OPEC+ to successfully coordinate and enforce production quotas,

• the availability of capital for oil and natural gas participants, including our customers, and capital allocation decisions by our customers, including the relative economics of offshore development versus alternative prospects,

• the level of production by non-OPEC+ countries,

• the worldwide military or political environment, including the Russia-Ukraine conflict and the conflicts in the Middle East and any related political or economic responses, global macroeconomic effects of trade disputes and increased tariffs, such as those imposed since February 2025, or that may be imposed, by the U.S., and sanctions and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas or geographic areas in which we operate, or acts of terrorism,

• U.S. and non-U.S. tax policy, including the U.K. windfall tax on oil and gas producers in the British North Sea,

• advances in exploration and development technology, including with respect to onshore shale,

• costs associated with exploring for, developing, producing and delivering oil and natural gas,

• the rate of discovery of new oil and natural gas reserves and the rate of decline of existing oil and gas reserves,

• investors reducing, or ceasing to provide, funding to the oil and natural gas industry in response to initiatives to limit or otherwise address climate change,

• laws and government regulations that limit, restrict or prohibit exploration and development of oil and natural gas in various jurisdictions, or materially increase the cost of such exploration and development,

• the development and exploitation of alternative fuels or energy sources, resulting in reduced capital spending by our customers on oil and natural gas projects, and increased demand for electric-powered products, including electric-powered vehicles,

• disruption to exploration and development activities due to hurricanes and other adverse weather conditions and the risk thereof,

• natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills, and

• the occurrence or threat of epidemic or pandemic diseases and any government response to such occurrence or threat.

Higher commodity prices may not necessarily translate into increased activity, however, and even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their expectations for future oil and natural gas prices, the cost of exploration efforts, extended periods of price volatility, their lack of success in exploration efforts and re-allocating capital expenditures for alternative fuels, energy sources or renewable energy projects.

These factors could cause our revenues and profits to decline and limit our future growth prospects. Any significant decline in day rates or utilization of our drilling rigs could materially adversely affect our financial position, operating results and cash flows. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and obtain insurance coverage that we consider adequate or are otherwise required by our contracts.

The offshore contract drilling industry is highly competitive and cyclical.

Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, safety records and competency are key factors in determining which qualified contractor is awarded a contract. Rig availability, location, condition and technical capabilities, as well as operating efficiency, operating integrity, industry standing and customer relations, can also be significant factors in the determination. If we are not able to compete successfully, our revenues and profitability may decline.

Demand for offshore contract drilling services is highly cyclical, which is primarily driven by the demand for drilling rigs and the available supply of drilling rigs. Demand for drilling rigs is driven by the levels of offshore exploration and development conducted by oil and natural gas companies, which is beyond our control and may fluctuate substantially from year-to-year and from region-to-region.

Prolonged periods of reduced demand or excess rig supply have required us, and may in the future require us, to idle, sell or scrap rigs and enter into low day rate contracts or contracts with unfavorable terms. There can be no assurance that the current demand for drilling rigs will increase in the future or that any short-term improvement to market conditions will be sustained. Any decline in demand for drilling rigs or oversupply of drilling rigs could materially adversely affect our financial position, operating results or cash flows.

Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future.

As of February 17, 2026 and February 18, 2025, our contract backlog was approximately $4.7 billion and $3.6 billion, respectively. This amount reflects the remaining firm contractual terms multiplied by the applicable contractual day rate. The contractual revenue may be higher than the actual revenue we ultimately receive because of a number of factors, including rig downtime or suspension of operations.

Several factors could cause rig downtime or a suspension of operations, many of which are beyond our control, including the early termination, repudiation or renegotiation of contracts, breakdowns of equipment, work stoppages, including labor strikes, shortages of material or skilled labor, surveys or inspections by government and maritime authorities, inability to obtain the requisite permits or approvals, periodic classification surveys, severe weather, strong ocean currents or harsh operating conditions, the occurrence or threat of epidemic or pandemic diseases, and any government response to such occurrence or threat and force majeure events.

Our customers may seek to terminate , repudiate or renegotiate our drilling contracts for various reasons, including in the event of damage or a total loss of the drilling rig, the suspension or interruption of operations for extended periods due to breakdown of major rig equipment, failure to comply with performance conditions or equipment specifications, the failure of the customer to receive final investment decision (FID) with respect to projects for which the drilling rig was contracted or other reasons and “force majeure” events beyond the control of either party or other specific conditions. Generally, our drilling contracts permit early termination of the contract by the customer for convenience (without cause), exercisable upon advance notice to us, and in certain cases without making an early termination payment to us. In cases where customers are required to make an early termination payment, such payments would provide some level of compensation to us for the lost revenue from the contract but in many cases would not fully compensate us for all of the lost revenue. There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.

A decline in oil and natural gas prices and any resulting downward pressure on utilization may cause some customers to consider early termination of select contracts despite having to pay onerous early termination fees in certain cases. Customers may request to renegotiate the terms of existing contracts, or they may request early termination or seek to repudiate contracts. In addition, financially distressed customers may seek to negotiate reduced termination fees as part of a restructuring package. Furthermore, as contracts expire, we may be unable to secure new contracts for our drilling rigs. Therefore, revenues recorded in future periods could differ materially from our current backlog. Our inability to realize the full amount of our contract backlog or to secure a new contract with substantially similar terms on a timely basis could materially adversely affect our financial position, operating results or cash flows.

Our business will be materially adversely affected if we are unable to secure contracts on economically favorable terms or if option periods in existing contracts are not exercised as expected.

Our ability to renew expiring contracts or obtain new contracts and the terms of any such contracts will depend on market conditions. For example, as of February 17, 2026, we had three drillships that are preservation stacked. Our customers’ decisions to exercise option periods resulting in additional work for the rig under contract also depend on market conditions. We may be unable to renew our expiring contracts, including contracts expiring due to a failure by the customer to exercise option periods, or obtain new contracts for any of our uncontracted drilling rigs or the drilling rigs under contracts that have expired or have been terminated. In addition, the day rates under any new contracts or any renegotiated contracts may be substantially below the existing day rates, which could materially adversely affect our financial position, operating results or cash flows. If customers do not exercise option periods under contracts that we currently expect to be exercised, we may face increased idle time associated with the related rigs, as we may have difficulty securing additional work to cover the option periods. In addition, we may choose to stack idle rigs that are not under contract, which would require us to incur stacking costs for such rigs.

Our customers may be unable or unwilling to fulfill their contractual commitments to us, including their obligations to pay for losses, damages or other liabilities.

Some of our customers may be subject to liquidity risk that could lead them to seek to repudiate, cancel or renegotiate our drilling contracts or fail to fulfill their commitments to us under those contracts. These risks are heightened in periods of depressed market conditions. Our drilling contracts provide for varying levels of indemnification and allocation of liabilities between our customers and us with respect to loss or damage to property and injury or death to persons arising from the drilling operations we perform. Under our drilling contracts, liability with respect to personnel and property customarily is allocated so that we and our customers each assume liability for our respective personnel and property. Our customers have historically assumed most of the responsibility for, and indemnified us from loss, damage or other liability resulting from, pollution or contamination, including clean-up and removal, and third-party damages arising from operations under the contract when the source of the pollution originates from the well or reservoir, including those resulting from blowouts or cratering of the well. However, we regularly are required to assume a limited amount of liability for pollution damage caused by our negligence, which liability generally has caps for ordinary negligence, with much higher caps or unlimited liability where the damage is caused by our gross negligence or willful misconduct. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to fulfill their indemnification obligations to us for such losses. In addition, under the laws of certain jurisdictions, such indemnities under certain circumstances are not enforceable if the cause of the damage was our gross negligence or willful misconduct. This could result in us having to assume liabilities in excess of those agreed in our contracts due to customer balance sheet or liquidity issues or applicable law.

The loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, could materially adversely affect our business.

We provide our services to major international, government-owned and independent oil and natural gas companies. During 2025, our five largest customers accounted for 49% of consolidated revenues, a significant percentage of our operating cash flows, with our largest customer representing 13% of our consolidated revenues. Our financial position, operating results or cash flows may be materially adversely affected if any of our higher day rate contracts were terminated or renegotiated on less favorable terms or if a major customer terminates its contracts with us, fails to renew its existing contracts with us, requires renegotiation of our contracts or declines to award new contracts to us.

Some of our customers have consolidated and could continue to consolidate and could use their size and purchasing power to achieve economies of scale and pricing concessions. Such customer consolidation could result in reduced capital spending by such customers, decreased demand for our drilling services, loss of competitive position and negative pricing impacts. Some of our customers have also deferred the timing of their offshore projects as a result of a focus on capital discipline, including the deployment of additional cash to share repurchase and dividend programs, the limited availability of production equipment and protracted regulatory approvals. If we cannot maintain service and pricing levels for existing customers or replace such revenues with increased business activities from other customers, our financial position, operating results and cash flows could be materially adversely affected.

Our long-term contracts are subject to the risk of cost increases, which could adversely impact our profitability.

In general, our costs increase as the demand for contract drilling services and skilled labor increase, which may materially adversely affect our financial position, operating results or cash flows. Our long-term contracts are subject to inflationary factors such as increases in skilled labor costs, material costs and overhead costs. While some of our contracts include cost escalation provisions that allow changes to our day rate based on stipulated cost increases or decreases, the timing and amount earned from these day rate adjustments may differ from our actual increase in costs and many contracts do not allow for such day rate adjustments. During times of reduced demand, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels in a particular geographic location and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity a drilling rig is performing and the age and condition of the equipment, as well as the impact of supply chain disruptions and inflation on the costs of parts and materials. Contract preparation expenses vary based on the scope and length of contract preparation required.

Our network and systems, including rig operating systems and critical data, are subject to cybersecurity risk and technical disruptions.

Our business depends on technologies, systems and networks, including both operational technology and information technology (“IT”), to conduct our offshore operations and help run our financial and onshore operations functions, including the collection of payments from customers, payments to vendors and employees and storage of company records. Some of these systems are managed or provided by third-party service providers, including cloud platform or cloud software providers. These systems are subject to growing risks associated with cybersecurity incidents and technical disruptions. These risks include, but may not be limited to, human error, power outages, computer, telecommunication and satellite failures, natural disasters, fraud or malice, social engineering or phishing attacks, viruses or malware, and other cyberattacks, such as denial-of-service or ransomware attacks. Entities or groups, including private and nation state actors, have mounted cyberattacks on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. In addition, the U.S. government has issued public warnings that indicate energy assets and companies might be targeted by nation state threat actors. Geopolitical tensions may increase the risk of cybersecurity threats.

Laws and regulations governing cybersecurity and data privacy and the unauthorized disclosure of confidential or protected information pose increasingly complex compliance challenges and potential costs, and any failure to comply with these cybersecurity and data privacy requirements or other applicable laws and regulations in this area could result in significant regulatory or other penalties and legal liability. Disruption to our operations and damage to our reputation could materially adversely affect our financial position, operating results or cash flows.

While we have a cybersecurity program to assess, identify and manage risks from cybersecurity threats, there is no guarantee such efforts will be successful in preventing or detecting any given threat. The cybersecurity threat landscape is rapidly evolving, and threat actors may leverage previously unknown vulnerabilities to perpetrate attacks, as well as sophisticated anti-forensics techniques to evade detection. We may be unable to anticipate evolving techniques, implement adequate cybersecurity barriers or other preventative measures, or respond, mitigate the risks from and recover from an incident without operational impact, and thus it is impossible for us to entirely mitigate this risk. Further, the use of AI by us or by third-party service providers may create new cybersecurity vulnerabilities, including those which may not be recognized at the time, and malicious actors may employ AI to aid in launching more sophisticated and effective cyber-attacks. We regularly defend against, respond to and mitigate risks from cybersecurity incidents, which to date have not had a material impact on our operations; however, there is no assurance that such impacts will not be material in the future.

Cybersecurity incidents or system failures affecting either us or our third-party service providers can cause disruptions of our ability to conduct our operations, including disruptions of certain systems on our rigs, which could result in injury to people, our or our customers' assets, or the environment, disruptions of our ability to conduct our financial and onshore operating functions, including disruptions in our ability to make or receive payments, loss of intellectual property, proprietary information, customer and vendor data or other sensitive information, corruption or unauthorized release of our or our customer’s data. As a result, we may experience loss of revenue, reputational harm and ransom demands and could be subject to legal or regulatory claims or proceedings, including enforcement actions under data privacy or disclosure regulations, which may result in significant expenditures, fines or liabilities. In addition, we may incur large expenditures to investigate or remediate, to recover data, to repair or replace networks or information systems, or to protect against similar future events. The impact of any such cybersecurity incident or system failure could materially adversely affect our financial position, operating results or cash flows.

Rig reactivation, upgrade and enhancement projects are subject to risks, including delays and cost overruns, which could materially adversely affect our financial position, operating results or cash flows.

The costs required to reactivate a stacked rig and return the rig to drilling service are significant. Depending on the length of time that a rig has been stacked, we may incur significant costs to restore the rig to drilling capability, which may also include capital expenditures due to, among other things, technological obsolescence or an equipment overhaul of the rig. Stacked drilling rigs require expenditures to return these rigs to drilling service. In the future, market conditions may not justify these types of expenditures or enable us to operate our rigs profitably during the remainder of their economic lives. In addition, we may not recover the expenditures incurred to reactivate rigs through the associated drilling contract or otherwise. We can provide no assurance that we will have access to adequate or economical sources of capital to fund the return of stacked rigs to drilling service.

During periods of increased rig reactivation, upgrade and enhancement projects, shipyards and third-party equipment vendors may be under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays, equipment failures increased costs and/or quality deficiencies. Furthermore, drilling rigs may face start-up or other operational complications following completion of upgrades or maintenance. Other unexpected difficulties, including equipment failures, design or engineering problems, could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.

Rig reactivation, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns, including the following: failure of third-party equipment to meet quality and/or performance standards, delays in equipment deliveries or shipyard construction, shortages of materials or skilled labor, disruptions occurring as the result of pandemics and/or epidemics and related public health measures implemented by governments worldwide, damage to shipyard facilities, including damage resulting from fire, explosion, flooding, severe weather, terrorism, war or other armed hostilities, unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment, unanticipated actual or purported change orders, strikes, labor disputes or work stoppages, financial or operating difficulties of equipment vendors or the shipyard while enhancing, upgrading, improving or repairing a rig or rigs, unanticipated cost increases, foreign currency exchange rate fluctuations impacting overall cost, inability to obtain the requisite permits or approvals, client acceptance delays, disputes with shipyards and suppliers, latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, claims of force majeure events, and additional risks inherent to shipyard projects in a non-U.S. location. These risks could result in the cancellation or termination of drilling contracts for which the drilling rig was contracted or reduce the likelihood that such drilling rigs will receive a drilling contract if not already contracted.

We make significant expenditures to meet customer requirements, maintain our fleet to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to expand our fleet, and we may be required to make significant expenditures to maintain our competitiveness.

We make substantial expenditures to maintain our fleet. These expenditures could increase as a result of changes in offshore drilling technology, the cost of labor and materials, customer requirements, fleet size, the cost of replacement parts for existing drilling rigs, the geographic location of the drilling rigs, length of drilling contracts, governmental regulations, maritime regulations and technical standards relating to safety, security or the environment, and industry standards.

Changes in offshore drilling technology, customer requirements for new or upgraded equipment, and competition within our industry may require us to make significant capital expenditures. In addition, changes in governmental regulations relating to decarbonization, environmental, emissions, safety or equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may require us to make additional unforeseen capital expenditures. In addition, commitments made by us, or our customers, to reduce emissions, or decarbonize, may require us to upgrade or retrofit our drilling rigs with additional equipment, less carbon intensive equipment or instrumentation. As a result, we may be required to take our drilling rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment. In the future, market conditions may not justify these expenditures or enable us to operate our drilling rigs profitably during the remainder of their economic useful lives.

Additionally, in order to expand our fleet, we may require additional capital in the future. If we are unable to fund capital requirements with cash flows from operations or proceeds from sales of non-core assets, we may be required to either incur additional borrowings or raise capital through the sale of debt or equity securities. Our ability to access the capital markets may be limited by our financial condition at the time, by restrictive covenants in our debt agreements, bye-laws and regulations and by adverse market conditions resulting from, among others, general economic conditions, contingencies and uncertainties that are beyond our control. Similarly, when lenders and institutional investors reduce, and in some cases cease to provide, funding to industry borrowers, the liquidity and financial condition of us and our customers can be adversely impacted. If we raise funds by issuing equity securities, existing shareholders may experience dilution, and if we raise funds by issuing additional debt securities, we may have to pledge additional assets as collateral. Our failure to obtain the funds for necessary future capital expenditures could materially adversely affect our business and on our financial position, operating results or cash flows.

Failure to recruit, develop and retain skilled personnel could materially adversely affect our business.

We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business, and further rig reactivations will require that we hire additional skilled personnel. Competition for the labor required for drilling operations and construction projects is intense, leading to shortages of qualified personnel in the industry. During periods of intensified competition, it is more difficult and costly to recruit, train and retain qualified employees, including in foreign countries that require a certain percentage of national employees. The most recent prolonged industry downturn and resulting reductions in offshore personnel wages further reduced the number of qualified personnel available. Hiring qualified and experienced personnel with the specialized skills and qualifications required to operate an offshore drilling rig is difficult due to the competitive labor market and lack of experience. In periods of intense competition for labor, we may be required to increase existing levels of compensation and benefits to attract and retain a skilled workforce.

In addition, new personnel that we hire may need to undergo training to develop the skills needed to perform their job duties. There can be no assurance that our training programs will be adequate for these purposes, which could expose us to operational hazards and risks. We may also incur additional training costs to ensure that new or promoted personnel have the right skills and qualifications.

We also are subject to potential legislative or regulatory action that may impact working conditions, paid time off or other conditions of employment. These conditions could further increase our costs or limit our ability to fully staff and operate our drilling rigs.

The increases in employment costs cause an increase in operating expenses, with a resulting reduction in net income, and our ability to fully staff and operate our drilling rigs may be negatively affected.

Our use of a shared service center creates risks relating to the processing of transactions and recording of financial information, which could materially adversely affect our financial condition, operating results or cash flows.

We have implemented a shared service center program pursuant to which we have outsourced certain finance, human resources, supply chain and IT functions. As part of this program, we outsource certain accounting, payroll, human resources, supply chain and IT functions to a third-party service provider. The party that we utilize for these services may not be able to handle the volume of activity or perform the quality of service necessary to support our operations. The failure of the third party to fulfill its obligations could disrupt our operations. In addition, the use of a shared service environment, including our reliance on a third-party provider, may create risks relating to the processing of transactions and recording of financial information. We could experience a lapse in the operation of internal controls due to turnover, lack of legacy knowledge and inappropriate training associated with the use of a third-party provider, which could result in significant deficiencies or material weaknesses in our internal control over financial reporting and materially adversely affect our financial position, operating results or cash flows.

AI presents risks and challenges that can impact our business.

AI presents operational, legal and reputational risks that could impact our business, including breaches of privacy or security incidents related to the use of AI. As we integrate, AI tools into our operations and business functions, there is no assurance that we will realize the anticipated benefits or properly implement such technology. Our third-party service providers may also incorporate AI into their services without disclosing such use to us or fail to disclose risks presented by their use of AI. There is a risk that AI tools used by us or by our service providers could produce inaccurate or unexpected results or behaviors that could result in operational disruptions and harm our business, customers or reputation. In addition, we, or our AI service providers, may not meet existing or rapidly evolving regulatory or industry standards with respect to privacy and data protection, compliance, and transparency, among others, which could inhibit our or our service providers’ ability to maintain an adequate level of functionality or service. Our competitors or other third parties may incorporate AI in their business operations more quickly or more successfully than we do, which may negatively impact our ability to compete effectively. Our internal governance, policies, procedures, and controls relating to the development, integration, and use of AI, including by third-party service providers, may be insufficient or may not operate as intended, particularly as AI technologies and regulatory expectations continue to evolve. Additionally, the rapidly evolving global legal landscape around AI, including the EU Artificial Intelligence Act and proposed and enacted U.S. federal and state laws and regulations, may expose us to claims, inquiries, demands and proceedings by private parties and global regulatory authorities and subject us to legal liability as well as reputational harm. Existing laws and regulations may be interpreted in ways that would affect our business operations and the ways in which we use AI. Any of these outcomes could impair our ability to compete effectively, damage our reputation, result in the loss of our or our customers’ property or information and/or materially adversely affect our financial position, operating results or cash flows.

We may not realize the expected benefits of our ARO joint venture.

ARO, our 50/50 unconsolidated ARO joint venture and a provider of offshore drilling services, faces many of the same risks as we face. Operating through ARO, in which we have a shared interest, may result in our having less control over many decisions made with respect to projects, operations, safety, utilization, internal controls and other operating and financial matters. ARO may not apply the same controls and policies that we follow to manage our risks, and ARO’s controls and policies may not be as effective. As a result, operational, financial and control issues may arise, including the inability to produce timely and accurate financial statements, which could materially adversely affect our financial position, operating results or cash flows. Additionally, in order to establish or preserve our relationship with our joint venture partner we may agree to risks and contributions of resources that are proportionately greater than the returns we could receive, which could reduce our income and return on our investment in ARO compared to what we may traditionally require in other areas of our business.

ARO’s income and accounts receivable are concentrated with Saudi Aramco. The loss of this customer, or a substantial decrease in demand by this customer for ARO’s services, would have a material adverse effect on ARO’s business, results of operations and financial condition, which could materially adversely affect our financial position, operating results or cash flows.

We have issued a 10-year shareholder notes receivable to ARO (the “Notes Receivable from ARO”), which are governed by the laws of Saudi Arabia. In the event of a dispute with ARO over the repayment of the Notes Receivable from ARO, our ability to enforce the payment obligations of ARO or to exercise other remedies are subject to several significant limitations, including that our ability to accelerate outstanding amounts under the Notes Receivable from ARO is subject to the consent of Saudi Aramco and that the Notes Receivable from ARO are governed by the laws of Saudi Arabia, and we are limited to the remedies available under Saudi law. In addition, our Notes Receivable from ARO are subordinated and junior in right of payment to ARO’s term loan described below, and as such, we may not be repaid the interest or principal amounts of the Notes Receivable from ARO. Further, we may not receive cash interest from ARO for an extended period of time, or at all. For example, the 2025 interest owed by ARO on the Notes Receivable from ARO of $24.1 million was paid in kind in December 2025 by increasing the principal balance of the Notes Receivable from ARO.

We expect to agree to extend the maturity of the Notes Receivable from ARO to facilitate its capital allocation priorities, in particular its newbuild jackup rig program. Notwithstanding any extension of the maturity, in the event that ARO does not repay the Notes Receivable from ARO when they become due, we would require the prior consent of our joint venture partner to enforce ARO's payment obligations.

We have a potential obligation to fund ARO for newbuild jackup rigs. The s hareholder agreement governing the joint venture (the "Shareholder Agreement") specifies that ARO shall purchase 20 newbuild jackup rigs. The first two newbuild jackups were ordered in January 2020. The first rig, Kingdom 1, was delivered in the fourth quarter of 2023 and the second rig, Kingdom 2, was delivered in the second quarter of 2024. In October 2024 and November 2025, ARO ordered the third newbuild jackup, Kingdom 3, and the fourth newbuild jackup, Kingdom 4, respectively. There can be no assurance that the new jackup rigs will begin operations as anticipated.

The joint venture partners intend for the newbuild jackup rigs to be financed from ARO's available cash on hand or from operations and/or funds available from third-party financing. In October 2023, ARO entered into a $359.0 million term loan to finance the remaining payments due upon delivery of the first two newbuild jackups and for general corporate purposes. Further, in the event ARO has insufficient cash or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Beginning with the delivery of the second newbuild, each partner's commitment is reduced by the lesser of the actual cost of each newbuild rig or $250.0 million, on a proportionate basis. Following the delivery of Kingdom 2, our commitment to fund the newbuild program has been reduced to $1.1 billion. Any required capital contributions we make could negatively impact our liquidity position and financial condition.

In connection with Saudi Aramco’s suspension of certain drilling contracts, the VALARIS 143, VALARIS 147 and VALARIS 148 contracts were terminated during the year ended December 31, 2024. Upon termination of these contracts, the bareboat charter agreements between us and ARO were also terminated and the rigs were returned to us and stacked. If additional drilling contracts between us and ARO are suspended or terminated in the future and we are unable to secure new contracts with substantially similar terms on a timely basis, our financial position, operating results or cash flows could be materially adversely affected.

As a result of these risks, it may take longer than expected for us to realize the expected returns on our investment in ARO or such returns may ultimately be less than anticipated. Additionally, if we are unable to make any required contributions, our ownership in ARO could be diluted which could hinder our ability to effectively manage ARO and could materially adversely affect our financial position, operating results or cash flows.

Joint venture investments could be adversely affected by our joint venture partners’ actions, financial condition and liquidity and disputes between us and our joint venture partners.

We have made investments in joint ventures other than ARO. Such investments are subject to the risk that the other shareholders of the joint venture, who may have different business or investment strategies than us or with whom we may have a disagreement or dispute, may have the ability to block business, financial, or management decisions (such as the decision to distribute dividends or appoint members of management), which may be crucial to the success of our investment in the joint venture, or could otherwise implement initiatives which may be contrary to our interests. Our partners may be unable, or unwilling, to fulfil their obligations under the relevant agreements regarding such joint ventures (for example by non-contributing working capital or other resources), or may experience financial, operational, or other difficulties that may adversely impact our investment in a particular joint venture. In addition, our partners may lack sufficient controls and procedures which could expose us to risk. If any of the foregoing were to occur, such occurrence could materially adversely affect our financial position, operating results or cash flows.

We may pursue other joint ventures that we believe will enable us to further expand or enhance our business. Any such joint venture would be evaluated on a case-by-case basis, and its consummation would depend upon numerous factors, including identifying suitable opportunities that align with our business strategy, reaching agreement with the potential counterparty on acceptable terms, the receipt of any applicable regulatory and other approvals, and other conditions. Any such joint venture would involve various risks, including among others (1) difficulties related to integrating or managing applicable parts of a joint venture and unanticipated changes in customer and other third-party relationships subsequent to closing, (2) diversion of management’s attention from day-to-day operations, (3) failure to realize anticipated benefits, such as cost savings, revenue enhancements or business synergies, (4) the potential for substantial transaction expenses and (5) potential accounting impairment or actual diminution or loss of value of our investment if future market, business or other conditions ultimately differ from our assumptions at the time any such transaction is consummated.

Our business involves operating hazards, and our insurance and indemnities from our customers or other parties may not be adequate to cover any potential losses.

The drilling of oil and natural gas wells involves numerous operating hazards, such as blowouts, reservoir damage, loss of production, loss of well control, uncontrolled formation pressures, lost or stuck drill strings, equipment failures and mechanical breakdowns, punch throughs, craterings, industrial accidents, fires, explosions, oil spills and pollution. Contract drilling requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and other parties or prosecution by governmental authorities. These hazards can cause personal injury or loss of life, severe damage to, or destruction of, property and equipment, pollution or environmental damage, which could lead to claims by employees, contractors or third parties and suspension of operations and contract terminations. Our drilling rigs are also subject to hazards associated with marine operations, either while docked, on site or during mobilization, such as capsizing, breaking free of moorings, sinking, grounding, allision, collision, piracy, damage from adverse weather and marine life infestations. The Gulf of America and the coasts of Australia are areas subject to hurricanes, typhoons and other adverse weather conditions, and our drilling rigs in these regions may be exposed to damage or a total loss by these storms, some of which may not be covered by insurance. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury to or death of rig personnel. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. Damage to the environment could also result from our operations, particularly through spillage of hydrocarbons, fuel, lubricants or other chemicals and substances used in drilling operations or fires. We may also be subject to property damage, environmental indemnity and other claims by third parties. Drilling involves certain risks associated with the loss of control of a well, such as blowout, cratering, the cost to regain control of or redrill the well and remediation of associated pollution. Our customers may be unable or unwilling to indemnify us against such risks. In addition, a court may decide that certain indemnities in our current or future drilling contracts are not enforceable. The law generally considers contractual indemnity for criminal fines and penalties to be against public policy, and the enforceability of an indemnity as to other matters may be limited.

Our insurance policies and drilling contracts contain rights to indemnity that may not adequately cover our losses, and we do not have insurance coverage or rights to indemnity for all risks. We have two main types of insurance coverage: (1) hull and machinery coverage for physical damage to our property and equipment and (2) P&I with excess liability coverage, which generally covers our liabilities arising from our operations, such as personal injury and property claims, including wreck removal and pollution. We have no hull and machinery insurance coverage for damages caused by named storms in the Gulf of America for our jack-up fleet and only limited coverage for our floater fleet. We also retain the risk for any liability that exceeds our excess liability coverage. Pollution and environmental risks generally are not completely insurable.

If a significant accident or other event occurs that is not fully covered by our insurance or by an enforceable or recoverable indemnity, the occurrence could materially adversely affect our financial position, operating results or cash flows. The amount of our insurance may also be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes annual aggregate policy limits. As a result, we generally retain the risk for any losses in excess of these limits. We currently only carry limited insurance for loss of hire for several of our rigs, and certain other claims may also not be reimbursed, in part or full, by insurance carriers. Any such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain more risk in the future, resulting in higher risk of losses, which could be material. Moreover, we may not be able to maintain adequate insurance in the future at rates that we consider reasonable or be able to obtain insurance against certain risks. Furthermore, our insurance carriers may assert that our insurance policies do not provide coverage for our losses. Our insurance policies also have exclusions of coverage for some losses. Uninsured exposures may include radiation hazards, loss of hire and losses relating to terrorist acts or strikes and some cyber events. As a result of increased costs to insurance companies due to regulatory, geopolitical, reputational or other developments, insurance companies that have historically participated in underwriting risks arising out of oil and natural gas

operations may discontinue that practice, may reduce the insurance capacity they are willing to deploy or demand significantly higher premiums or deductibles to cover these risks. Additionally, a significant number of high cost climate-related insurance claims or natural catastrophes such as hurricanes, floods or windstorms may result in withdrawal of insurance capacity and increasing premiums to oil and natural gas industry companies.

Geopolitical events and violence could materially adversely affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.

Geopolitical events have resulted in military actions, terrorist, pirate and other armed attacks, civil unrest, political demonstrations, mass strikes and government responses to such events. Military action by the U.S. or other nations could escalate, and acts of terrorism, piracy, kidnapping , extortion, acts of war, violence, civil war or general disorder may initiate or continue. Such acts could be directed against us or our assets. Such developments have caused instability in the world’s financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for oil and natural gas and could materially adversely affect the markets for our services, particularly to the extent that such events take place in regions with significant oil and natural gas reserves, refining facilities or transportation infrastructure. For example, the ongoing Russia-Ukraine conflict and the conflicts in the Middle East have led and may continue to lead to an increase in the volatility of global oil and natural gas prices, including as a result of any further increase in the severity of any such conflict. Insurance premiums could increase and coverage for these kinds of events may be unavailable in the future. Any or all of these effects could materially adversely affect our financial position, operating results or cash flows.

Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.

We currently own and operate 11 drilling rigs that are contracted with national oil companies. The terms of these contracts are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability, personal injury and other claims for damages (including consequential damages), or, in certain cases, the risk of early termination of the contract for convenience (without cause), exercisable upon advance notice to us, contractually or by governmental action, without making an early termination payment to us. We can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of drilling rigs contracted to national oil companies with commensurate additional contractual risks.

Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility with regard to the management of our personnel.

Outside of the U.S., we are often subject to collective bargaining agreements that require periodic salary negotiations, which usually result in higher personnel expenses and other benefits. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our profitability or limit our flexibility.

Certain legal obligations require us to contribute certain amounts to retirement funds or other benefit plans and restrict our ability to dismiss employees. Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our financial position, operating results or cash flows.

Significant equipment or part shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could materially adversely affect our financial position, operating results or cash flows.

Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to potential volatility in the quality, prices and availability of such items. Certain high-specification parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider. Consolidation of suppliers may limit our ability to obtain supplies and services when needed at an acceptable cost or at all. A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, including those related to inflation and supply chain disruption, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers by making it cost prohibitive to do so, thus adversely impacting our operations and revenues and/or our operating costs. Delays in the delivery of critical drilling equipment could cause delays in the expected timing of rig reactivation, enhancement or upgrade projects, unscheduled operational downtime, our drilling rigs to be unavailable within the commencement window established by the operator in the contract and subject us to potential termination of the contract for such late delivery of the drilling rig.

Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in our operating revenues.

Our operating and maintenance costs will not necessarily be proportional to changes in our operating revenues. Operating costs are affected by many factors, including inflation, while maintenance costs depend on, among other factors, market conditions for drilling services as well as unplanned downtime events or idle periods between contracts. Costs for operating a rig are therefore generally not correlated to the day rate being earned. As our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. Equipment maintenance costs fluctuate depending upon the age and condition of the equipment, and these costs could increase for short or extended periods as a result of new regulatory or customer requirements. Any of the foregoing could impact our liquidity or may cause us to miss our financial guidance for a given period, which could adversely impact the market price for our Common Shares. In addition, certain of our drilling contracts are partially payable in local currency. The amounts, if any, of local currency received under these drilling contracts may exceed our local currency needs to pay local operating and maintenance costs, leading to an accumulation of excess local currency balances, which, in certain instances, may be subject to either restrictions or other difficulties in converting to U.S. dollars, our functional currency, or to other currencies of the locations where we operate. Excess amounts of local currency may also expose us to the risk of currency exchange losses.

Our ability to pay our operating and capital expenses and make payments due on our debt depends on many factors beyond our control.

Our ability to pay our operating and capital expenses and make payments due on our debt depends on our future performance, which will be affected by financial, business, economic, legislative and other factors, many of which are beyond our control. Our business may not generate sufficient cash flow from operations in the future, which could result in our being unable to fund liquidity needs or repay indebtedness. A range of economic, business and industry factors will affect our financial performance, and many of these factors, such as the condition of our industry, the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as selling assets; reducing or delaying capital investments; seeking to raise additional capital; or restructuring or refinancing all or a portion of our indebtedness at or before maturity.

We cannot be assured that we will be able to accomplish any of these alternatives on terms acceptable to us or at all. In addition, the terms of existing or future debt agreements may restrict us from adopting any of these alternatives. The failure to generate sufficient cash flow or to achieve any of these alternatives could materially adversely affect our ability to fund liquidity needs or pay amounts due under our debt.

The agreements governing our debt, including the Indenture and the 2028 Credit Agreement, contain various covenants that impose restrictions on us and certain of our subsidiaries that may affect our ability to operate our business and to make payments on our debt.

The Indenture, the 2028 Credit Agreement (as each are defined below) and the related agreements governing our indebtedness contain covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to:

• incur additional debt and issue preferred stock;

• incur or create liens;

• redeem and/or prepay certain debt;

• pay dividends on our shares or repurchase shares;

• make certain investments;

• engage in specified sales of assets;

• enter into transactions with affiliates; and

• engage in consolidation, mergers and acquisitions.

In addition, the 2028 Credit Agreement contains financial covenants requiring us to maintain (i) a minimum book value of equity to total assets ratio, (ii) a minimum interest coverage ratio and (iii) a minimum amount of liquidity. Any future indebtedness may also require us to comply with similar or other covenants. These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers, acquisitions and other business opportunities.

Various risks, uncertainties and events beyond our control could affect our ability to comply with these covenants. Failure to comply with any of the covenants in our existing or future financing agreements could result in a default under those agreements and under other agreements containing cross-default provisions. A default would permit lenders to accelerate the maturity for the debt under these agreements and to foreclose upon any collateral securing the debt. Under these circumstances, we might not have sufficient funds or other resources to satisfy all of our obligations. In addition, the limitations imposed by financing agreements on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing, which could materially adversely affect our financial condition, operating results or cash flows and could cause us to become bankrupt or insolvent.

We may experience risks associated with future mergers, acquisitions or dispositions of businesses or assets, including our drilling rigs, or other strategic transactions.

We may pursue mergers, acquisitions or dispositions of businesses or assets, including our drilling rigs, or other strategic transactions that we believe will strengthen, streamline or expand our business, such as the Business Combination. Each such transaction would be dependent upon several factors, including identifying suitable companies, businesses or assets that align with our business strategies, reaching agreement with the potential counterparties on acceptable terms, the receipt of any applicable regulatory and other approvals, and other conditions. These transactions involve various risks, including among others, (1) difficulties related to integrating or managing applicable parts of an acquired business or joint venture and unanticipated changes in customer and other third-party relationships subsequent to closing, (2) diversion of management's attention from day-to-day operations, (3) applicable antitrust laws and other regulations that may limit our ability to acquire targets or require us to divest an acquired business or assets, (4) failure to realize anticipated benefits, such as cost savings, revenue enhancements or strengthening or broadening our business, (5) potentially substantial transaction costs associated with acquisitions, joint ventures or investments if we or a transaction counterparty seeks to exit or terminate an interest in the joint venture or investment, (6) potential adverse impacts on our business and relationships with customers, vendors, contractors, employees or suppliers as a result of proposed or completed transactions, (7) potential accounting impairment or actual diminution or loss of value of our investment if future market, business or other conditions ultimately differ from our assumptions at the time such transaction is consummated, and (8) potential accounting impairment upon the decision to reclassify assets as held for sale.

In connection with the retirements of VALARIS DPS-3, VALARIS DPS-5 and VALARIS DPS-6 (three semisubmersible rigs within the Floaters segment) and VALARIS 102 and VALARIS 145 (two rigs within the Jackups segment), and the classification of VALARIS DPS-1 (a semisubmersible rig within the Floaters segment) as held for sale during 2025, we recognized non-cash losses on impairment of $27.3 million for the year ended December 31, 2025. See " Note 5 - Property and Equipment " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for information regarding the retirements of these assets.

The exercise of all or any number of outstanding warrants or the issuance or settlement of stock-based awards may dilute the holders of our Common Shares.

On April 30, 2021, we issued 75.0 million Common Shares and 5.6 million warrants to purchase 5.6 million Common Shares at an exercise price of $131.88 per share, exercisable for a seven-year period commencing on that date. Additionally, on May 3, 2021, our board of directors approved and ratified the Valaris Limited 2021 Management Incentive Plan (the “MIP”) and reserved 9.0 million of our Common Shares for issuance under the MIP primarily for employees and directors. As of December 31, 2025, there were 6.2 million shares available for issuance under the MIP. The grant and settlement of equity awards in the future, any exercise of the warrants into Common Shares and any sale of Common Shares underlying outstanding warrants will have a dilutive effect to the holdings of our existing shareholders and could have a material adverse effect on the market for our Common Shares, including the price that an investor could obtain for their Common Shares.

Regulatory, Legal and Tax Risks

Failure to comply with anti-corruption and anti-bribery statutes, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010, could result in fines, criminal penalties, drilling contract terminations and materially adversely affect our financial position, operating results or cash flows.

We operate in a number of countries throughout the world, including countries known to have a reputation for corruption and are subject to the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”), the U.S. Treasury Department’s Office of Foreign Assets Control (“OFAC”) regulations, the U.K. Bribery Act (“UKBA”), other U.S. laws and regulations governing our international operations and similar laws in other countries.

Any violation of the FCPA, OFAC regulations, the UKBA or other applicable anti-corruption laws by us, our partners, agents and our and their respective affiliated entities or respective officers, directors, employees and agents could in some cases provide a customer with termination rights and other remedies under the terms of their contracts(s) with us and also result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and could materially adversely affect our financial condition, operating results or cash flows. Further, we may incur significant costs and consume significant internal resources in our efforts to detect, investigate and resolve actual or alleged violations.

Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations and reduce demand for our services.

The offshore contract drilling industry is dependent on demand for services from the oil and natural gas industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations limiting or curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety and other policy reasons. Furthermore, we may be required to make significant capital expenditures or incur substantial additional costs to comply with new governmental laws and regulations. It is also possible that legislative and regulatory activity could materially adversely affect our financial position, operating results or cash flows by limiting drilling opportunities. In recent years, we have seen several significant regulatory changes that have affected the way we operate in the Gulf of America. See “ Item 1 . Business – Governmental Regulations and Environmental Matters .”

Any new or additional regulatory, legislative, permitting or certification requirements in the U.S. and other areas in which we operate, including laws and regulations that have or may impose increased financial responsibility, oil spill abatement contingency plan capability requirements, or additional operational requirements and certifications, could materially adversely affect our financial position, operating results or cash flows.

We anticipate that government regulation in other countries where we operate may follow the U.S. in regard to enhanced safety and environmental regulation, which could also result in governments imposing sanctions on contractors when operators fail to comply with regulations that impact drilling operations. Even if not a requirement in these countries, most international operating companies, and many others, are voluntarily complying with some or all of the U.S. inspections and safety and environmental guidelines when operating outside the U.S. Such additional governmental regulation and voluntary compliance by operators could increase the cost of our operations and expose us to greater liability.

Compliance with or breach of environmental laws can be costly and could limit our operations.

Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment. However, the legislative, judicial and regulatory response to a well incident could substantially increase our and our customers’ liabilities. In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry. See “ Item 1 . Business – Governmental Regulations and Environmental Matters ” and “ Item 3 . Legal Proceedings – Environmental Matters. ”

Sustainability initiatives and high profile and catastrophic environmental events, such as the 2010 Macondo well incident, have led to increased regulation of offshore oil and natural gas drilling. We are adversely affected by restrictions on drilling in the areas in which we operate, including policies and guidelines regarding the approval of drilling permits, restrictions on development and production activities, and directives, judicial decisions and regulations that have and may further impact our operations. From time to time, legislative and regulatory proposals have been introduced, and legal proceedings have been initiated, that would materially limit or prohibit offshore drilling in certain areas, or that would increase the liabilities or costs associated with offshore drilling. If new laws are enacted, or if government actions are taken or judicial decisions are made that restrict or prohibit offshore drilling in our principal areas of operation or that impose environmental or other requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development, or production of oil and natural gas, our financial position, operating results or cash flows could be materially adversely affected.

The IRS may not agree with the conclusion that we should be treated as a foreign corporation for U.S. federal tax purposes.

Although Valaris Limited is incorporated in Bermuda (and thus would generally be considered a “foreign” corporation (or non-U.S. tax resident)), the IRS could assert that we should be treated as a U.S. corporation (and U.S. tax resident) pursuant to the rules under Section 7874 of the Internal Revenue Code. While we do not believe we are a U.S. corporation pursuant to these rules, the rules are complex and the determination is subject to factual uncertainties. If the IRS successfully challenged our status as a foreign corporation, significant adverse tax consequences would result for us and for certain of our shareholders.

Governments may pass laws that subject us to additional taxation or may challenge our tax positions.

There is increasing uncertainty with respect to tax laws, regulations and treaties, and the interpretation and enforcement thereof that may affect our business. For example, the Organization for Economic Cooperation and Development (“OECD”), the EU and certain other countries (including countries in which we operate) enacted substantial changes to numerous long-standing tax principles impacting how large multinational enterprises are taxed. In particular, the OECD’s Pillar Two initiative introduced a 15% global minimum tax applied on a country-by-country basis. Many jurisdictions have already enacted legislation in line with Pillar Two, and the OECD continues to issue additional guidance. Based upon existing legislation and OECD guidance, Pillar Two could increase our future tax obligations in the jurisdictions in which we operate. These evolving rules, as well as any other changes in domestic and international tax rules and regulations, could have a material effect on our effective tax rate.

In addition, our tax positions are subject to audit by U.K., U.S. and other foreign tax authorities. Such tax authorities may, and do from time to time, disagree with our interpretations or assessments of the effects of tax laws, treaties or regulations or their applicability to our corporate structure or certain transactions we have undertaken. Even if we are successful in maintaining our tax positions, we may incur significant expenses in defending our positions and contesting claims asserted by tax authorities. If we are unsuccessful in defending our tax positions, the resulting assessments or rulings could significantly impact our consolidated income taxes in past or future periods.

As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate. We are subject to tax assessments in various jurisdictions, which we are contesting.

As a result of these uncertainties, as well as changes in the administrative practices and precedents of tax authorities or other matters, such as changes in applicable accounting rules, that increase the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements, we cannot provide any assurances as to what our consolidated effective income tax rate will be in future periods. If we are unable to mitigate the negative consequences of any change in law, audit or other matters, this could cause our consolidated income taxes to increase and materially adversely affect our financial position, operating results or cash flows.

Our consolidated effective income tax rate may vary substantially over time.

We cannot provide any assurances as to what our future consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.K., U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or other matters (such as changes in applicable accounting rules) that increase the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. In addition, as a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. In periods of declining profitability, our income tax expense may not decline proportionately with income. Further, we may continue to incur income tax expense in periods in which we operate at a loss. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries, which may result in the imposition of transaction taxes, which could be material. If we are unable to mitigate the negative consequences of any change in law, audit, business activity or other matters, this could cause our consolidated effective income tax rate to increase and materially adversely affect our financial position, operating results or cash flows.

We are subject to litigation that could have a material adverse effect on us.

We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, toxic tort claims, environmental claims or proceedings, employment matters, issues related to employee or representative conduct, governmental claims for taxes or duties, and other litigation that arises in the ordinary course of our business. Although we intend to defend or pursue such matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation could materially adversely affect our financial position, operating results or cash flows because of potential negative outcomes, legal fees, the allocation of management’s time and attention, and other factors.

We could also face increased climate-related litigation with respect to our operations both in the U.S. and around the world. Governmental and other entities in various states, such as California and New York, have filed lawsuits against coal, oil and natural gas companies. These suits allege damages as a result of climate change, and the plaintiffs are seeking unspecified damages and abatement under various legal theories. Similar lawsuits may be filed in other jurisdictions both in the U.S. and globally. Although we are not currently a party to any such lawsuit, these suits present uncertainty regarding the extent to which companies who are not producing oil or natural gas, but who are engaged to provide services to support production activities, such as offshore drilling companies, face an increased risk of liability stemming from climate-related litigation, which risk would also adversely impact the oil and natural gas industry and impact demand for our services.

We are a Bermuda company and it may be difficult to enforce judgments against us or our directors and executive officers.

We are a Bermuda exempted company. As a result, the rights of holders of our Common Shares are governed by Bermuda law and our memorandum of association and bye-laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders of companies incorporated in other jurisdictions. Some of our directors and officers are not residents of the U.S., and a substantial portion of our assets are located outside the U.S. As a result, it may be difficult for investors to effect service of process on those persons in the U.S. or to enforce in the U.S. judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws. It is doubtful whether courts in Bermuda will enforce judgments obtained in other jurisdictions, including the U.S., against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in Bermuda against us or our directors or officers under the securities laws of other jurisdictions.

Our bye-laws restrict shareholders from bringing legal action against our officers and directors.

Our bye-laws contain a broad waiver by our shareholders of any claim or right of action, both individually and on our behalf, against any of our officers or directors. The waiver applies to any action taken by an officer or director, or the failure of an officer or director to take any action, in the performance of his or her duties, except with respect to any matter involving any fraud or dishonesty on the part of the officer or director. This waiver limits the right of shareholders to assert claims against our officers and directors unless the act or failure to act involves fraud or dishonesty.

Provisions in our bye-laws could delay or prevent a change in control of our company, which could materially adversely affect the price of our Common Shares.

Some of the provisions in our bye-laws could delay or prevent a change in control of our company that a shareholder may consider favorable, which could materially adversely affect the price of our Common Shares. Certain provisions of our bye-laws could make it more difficult for a third party to acquire control of our company, even if the change of control would be beneficial to our shareholders. These provisions include:

• authority of our board of directors to determine its size;

• the ability of our board of directors to issue preferred shares without shareholder approval;

• limitations on the removal of directors; and

• limitations on the ability of our shareholders to act by written consent in lieu of a meeting.

In addition, our bye-laws establish advance notice provisions for shareholder proposals and nominations for elections to the board of directors to be acted upon at meetings of shareholders.

Legislation enacted in Bermuda as to Economic Substance may affect our business.

The Economic Substance Act came into effect in Bermuda on January 1, 2019. This law requires a registered entity other than an entity which is resident for tax purposes in certain jurisdictions outside Bermuda that carries as a business any one or more of the “relevant activities” must comply with economic substance requirements. The Economic Substance Act may require in-scope Bermuda entities, which are engaged in such “relevant activities,” to be directed and managed in Bermuda, have an adequate level of qualified employees in Bermuda, incur an adequate level of annual expenditure in Bermuda, maintain physical offices and premises in Bermuda or perform core income-generating activities in Bermuda. The list of “relevant activities” includes carrying on any one or more of: banking, insurance, fund management, financing and leasing, headquarters, shipping, distribution and service center, intellectual property and holding entities. The Economic Substance Act could affect the manner in which we operate our business. To the extent we or any of our Bermuda subsidiaries carry on any relevant activities for the purposes of the Economic Substance Act, we or such subsidiaries will be required to comply with such economic substance requirements. Our compliance with the Economic Substance Act may result in additional costs that could have a material adverse effect on our financial position or results of operations.

Our business could be affected as a result of activist investors.

Publicly traded companies have increasingly become subject to campaigns by activist investors advocating corporate actions such as actions related to sustainability matters, financial restructuring, increased borrowing, dividends, share repurchases or sales of assets or even the entire company. Responding to proxy contests and other actions by such activist investors or others could be costly and time-consuming, disrupt our operations and divert the attention of our board of directors and senior management from the pursuit of our business strategies, which could materially adversely affect our financial position, operating results or cash flows. Additionally, perceived uncertainties as to our future direction as a result of investor activism or changes to the composition of the board of directors may lead to the perception of a change in the direction of our business, instability or lack of continuity, which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our financial position, operating results or cash flows could be materially adversely affected. In addition, the trading price of our shares could experience periods of increased volatility as a result of investor activism.

Risks Related to Our International Operations

Our non-U.S. operations involve additional risks not typically associated with U.S. operations, and we are subject to additional risks associated with the expansion into new geographical markets.

Revenues from non-U.S. operations were 86%, 84% and 80% of our total consolidated revenues for the years ended December 31, 2025, 2024 and 2023, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects, as well as our expansion into new geographical markets, are subject to political, economic and other uncertainties, including:

• terrorist acts, war and civil disturbances,

• expropriation, nationalization, deprivation or confiscation of our equipment or our customer’s property,

• repudiation or nationalization of contracts,

• assaults on property or personnel,

• piracy, kidnapping and extortion demands,

• significant governmental influence over many aspects of local economies and customers,

• unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws,

• work stoppages, such as labor strikes,

• complications associated with repairing and replacing equipment in remote locations,

• limitations on insurance coverage, such as war risk coverage, in certain areas,

• imposition of trade barriers,

• wage and price controls,

• import-export quotas,

• exchange restrictions, currency fluctuations and changes in monetary policy,

• uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America, Southeastern Asia, Eastern Europe or other geographic areas in which we operate,

• changes in the manner or rate of taxation,

• limitations on our ability to recover amounts due,

• increased risk of government and vendor/supplier corruption,

• increased local content requirements,

• the occurrence or threat of epidemic or pandemic diseases and any government response to such occurrence or threat,

• changes in political conditions, and

• other forms of government regulation and economic conditions that are beyond our control.

We historically have maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations such as nationalization, deprivation, expropriation, confiscation, political and war risks. However, there can be no assurance that any particular type of contractual or insurance protection will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. Moreover, we may initiate a self-insurance program through one or more captive insurance subsidiaries. In circumstances where we have insurance protection for some or all of the risks associated with non-U.S. operations, such insurance may be subject to cancellation on short notice, and it is unlikely that we would be able to remove our rig or rigs from the affected area within the notice period. Accordingly, a significant event for which we are uninsured, underinsured or self-insured, or for which we have not received an enforceable contractual indemnity from a customer, could materially adversely affect our financial position, operating results or cash flows.

We are subject to various tax laws and regulations in substantially all countries in which we operate or have a legal presence. Actions by tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or the interpretation or repeal of any of the foregoing or changes in the administrative practices and precedents of tax authorities, adverse rulings in connection with audits or otherwise, or other challenges may have a material impact on our tax expense.

Our non-U.S. operations are also subject to various laws and regulations in the countries in which we operate, including laws and regulations relating to the operation of drilling rigs and the requirements for equipment. We may be required to make significant capital expenditures to operate in such countries, which may not be reimbursed by our customers. Furthermore, regulators in certain jurisdictions, such as Brazil where we have four drillships currently operating, have become more aggressive in their interpretations and enforcement of such laws and regulations. Any adverse rulings or changes in enforcement practices that materially impact our ability to operate in these jurisdictions could cause delays in contract commencement dates, unscheduled operational downtime, reduced or zero day rates or the termination or cancellation of contracts. Governments in some countries are active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding such concessions, the exploration of oil and natural gas and other aspects of the oil and natural gas industry

in their countries. In some areas of the world, government activity has materially adversely affected the amount of exploration and development work performed by major international oil companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures or impose specific quotas for local goods and services, which can increase our operational costs and place us at a competitive disadvantage. There can be no assurance that such laws and regulations or activities will not materially adversely affect our financial position, operating results or cash flows.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by specific customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the U.S., control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose express or de facto economic sanctions or tariffs against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control, economic sanctions and tariffs are complex and frequently changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime, reduced day rates during such downtime and contract cancellations. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, exclusion from government contracts, seizure of shipments and loss of import and export privileges.

Our partners, agents and our and their respective affiliated entities or respective officers, directors, employees and agents may take actions in violation of our policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate. Any such violation could materially adversely affect our financial position, operating results or cash flows.

Sustainability Risks

Regulation of GHG and climate change could have a negative impact on our business.

Governments around the world have recently focused on enacting laws and regulations regarding climate change and regulation of GHG that may impact our operations, profitability and competitiveness. Restrictions on GHG emissions, reporting requirements or other related legislative or regulatory enactments could have an indirect effect in industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently, our offshore contract drilling services. Lawmakers and regulators in the U.S. and certain other jurisdictions where we operate have proposed or enacted regulations requiring reporting of GHG emissions and the restriction thereof, including increased fuel efficiency standards, carbon taxes or cap-and-trade systems, restrictive permitting and incentives for renewable energy. For example, in December 2023, the EPA adopted a final rule enacting a series of actions targeting methane and other emission reductions in natural gas and oil operations, though the effective implementation date has been delayed. Global efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hydrocarbon-based fuels, including plans developed in connection with the Paris climate conference in December 2015, the Katowice climate conference in December 2018 and the UN Climate Change Conferences since 2021. In January 2023, the EU enacted the Corporate Sustainability Reporting Directive to require sustainability reporting across a broad range of sustainability topics for both EU and non-EU companies. In 2025, the EU delayed the reporting timeline for many in-scope companies and, in December 2025, continued to progress on amendments that would limit the number of companies obligated to report under the law. These requirements could apply to us as early as 2028 (for fiscal year 2027) for certain of our EU subsidiaries and at the consolidated entity level in 2029 (for fiscal year 2028). As a result of varying rules adopted by jurisdictions in which we operate, we are increasingly subject to an overlapping patchwork of laws and regulations, including disclosure requirements, which may increase the costs of compliance and the risk of violations.

Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have also been enacted in certain jurisdictions. Additionally, numerous large cities globally and several countries have adopted programs to mandate or incentivize the conversion from internal combustion engine powered vehicles to electric-powered vehicles and placed restrictions on non-public transportation. Such policies or other laws, regulations, treaties and international agreements related to GHG and climate change may negatively impact the price of oil relative to other energy sources, reduce demand for hydrocarbons, limit drilling in the offshore oil and natural gas industry, or otherwise unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs and additional operating restrictions, all of which could materially adversely affect our financial position, operating results or cash flows.

In addition to potential impacts on our business resulting from climate-change legislation or regulations, our business also could be materially adversely affected by climate change-related physical changes, such as changing weather patterns. An increase in severe weather patterns could result in damage to or loss of our drilling rigs, impact our ability to conduct our operations and/or result in a disruption of our customers’ operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of GHG emissions-related agreements, legislation and measures on our financial performance is highly uncertain.

Consumer preferences for alternative fuels and electric-powered vehicles, as part of the global energy transition, may lead to reduced demand for our services.

The increasing penetration of renewable energy into the energy supply mix, the increased production of electric-powered vehicles and improvements in energy storage, as well as changes in consumer preferences, including increased consumer demand for alternative fuels, energy sources and electric-powered vehicles may materially adversely affect the demand for oil and natural gas and our drilling services. This evolving transition of the global energy system from fossil-based systems of energy production and consumption to more renewable energy sources, commonly referred to as the energy transition, could have a material adverse impact on our results of operations, financial position and cash flows. As a result of changes in consumer preferences and uncertainty regarding the pace of the energy transition and expected impacts on oil and natural gas demand, some of our customers may transition their businesses to renewable energy projects and away from oil and natural gas exploration and production, which would result in reduced capital spending by such customers on oil and natural gas projects and in turn reduced demand for our services.

Increased scrutiny from stakeholders and others regarding climate change, as well as our sustainability practices, initiatives and reporting responsibilities, could result in additional costs or risks.

In recent years the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, has promoted the divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves. Such initiatives could ultimately interfere with our access to capital, business activities and operations.

In addition to such initiatives, sustainability matters have more generally been the subject of increased focus by investors, customers, investment funds, political advocacy groups, and other market and industry participants, as well as certain regulators, including in the U.S. and the EU. We publish an annual Sustainability Report, which includes disclosures of our sustainability practices, aspirations, targets and goals. Our disclosures on these matters rely on management’s expectations as of the date when the statements are first made, as well as standards for measuring progress that are still in development and that may change or fail to be realized. These expectations and standards may continue to evolve. Even so, our failure or inability to meet these aspirations, targets, goals or evolving stakeholder expectations for sustainability practices and reporting and even the perception of such failure or inability may potentially harm our reputation and impact employee retention, customer relationships and access to capital, among other matters. For example, certain market participants use third-party benchmarks or scores to measure a company’s sustainability practices in making investment decisions and customers and suppliers may evaluate our sustainability practices or require that we adopt or remove certain sustainability policies as a condition of awarding contracts. By electing to set and share publicly our corporate sustainability standards, our business may face increased scrutiny related to sustainability activities and be unable to satisfy all stakeholders. For example, an increasing number of stakeholders, regulators and lawmakers have expressed or pursued opposing views, legislation and investment expectations with respect to sustainability. As sustainability best-practices and voluntary or mandatory reporting standards continue to develop, we may incur increased costs related to sustainability monitoring, reporting and compliance, especially to the extent these standards are not harmonized or consistent. In addition, it may be difficult or expensive for us to comply with sustainability-linked contracting policies adopted by customers and suppliers, particularly given the complexity of our supply chain, our reliance on third-party manufacturers, and the potential for jurisdictions in which we operate to enact opposing or incompatible regulations. Actions we may take to achieve our sustainability initiatives, including the development and implementation of new emissions-reduction technology, may require increased expenditures, which may materially adversely affect our financial position, operating results or cash flows.

Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in conjunction with " Item 1A . Risk Factors " and our consolidated financial statements and the notes thereto in " Item 8 . Financial Statements and Supplementary Data " of this report.

The discussion of our results of operations and liquidity in this section includes comparisons for the years ended December 31, 2025 and 2024. For a similar discussion, including comparisons for the years ended December 31, 2024 and 2023, see “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 year ended December 31, 2024 , filed with the SEC on February 20, 2025.

INTRODUCTION

Our Business

We are a leading provider of offshore contract drilling services to the international oil and gas industry with operations in almost every major offshore market across six continents. Our fleet of offshore drilling rigs is among the largest in the world and includes one of the highest specification ultra-deepwater fleets, as well as a leading premium jackup fleet. As of February 20, 2026, we own 46 rigs, including 13 drillships, two semisubmersible rigs, 31 jackup rigs and a 50% equity interest in ARO, our 50/50 unconsolidated joint venture with Saudi Aramco, which owns an additional nine rigs.

Our customers include many of the leading international and government-owned oil and gas companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies with global operations. The markets in which we operate include the Gulf of America, South America, the North Sea, the Mediterranean, the Middle East, Africa and Asia Pacific.

We provide drilling services on a day rate contract basis. Under day rate contracts, we provide an integrated drilling service that includes the provision of a drilling rig and rig crews for which we receive a daily rate that may vary between the full rate and zero rate throughout the duration of the contractual term, depending on the operations of the rig. We also may receive lump-sum fees or similar compensation for the mobilization, demobilization and capital upgrades of our rigs. Our customers bear substantially all of the costs of constructing the well and supporting drilling operations as well as the economic risk relative to the success of the well.

Our Industry

The offshore drilling industry is cyclical and primarily influenced by global energy demand, oil and gas supply dynamics and customer capital allocation decisions. Periods of oil oversupply generally place downward pressure on commodity prices, while periods of undersupply can result in higher and more volatile oil prices, influencing investment decisions across the upstream sector. While the oil market is currently in a period of oversupply, industry fundamentals are generally viewed as constructive over the medium to long term. Market participants generally expect the current oil supply imbalance to shift to a structurally tighter market over the next few years, driven by past underinvestment in upstream development and slowing production growth from non-OPEC sources. Industry studies, including those published by the International Energy Agency and the U.S. Energy Information Administration, indicate that substantial upstream investment is required to offset natural field declines and maintain existing production levels.

Against this backdrop, customers continue to emphasize the need for sustained investment in oil and gas to support secure, reliable and affordable energy supply, with increasing focus on offshore developments, particularly in deepwater. Compared to other sources of supply, deepwater projects typically offer large resource potential, competitive project economics and lower carbon intensity per barrel. Despite near-term commodity price uncertainty, customers are continuing to advance long-cycle offshore developments. Industry participants anticipate increased deepwater project sanctioning over the next five years across greenfield, brownfield and exploration opportunities. According to Rystad Energy estimates, approximately 70% of this expected activity is associated with projects with breakeven oil prices below $50 per barrel and over 80% is associated with projects with breakeven prices below $60 per barrel.

Operating results in the offshore drilling industry are directly related to the demand for and the available supply of drilling rigs, each of which affects rig utilization and day rates. While the balance of rig supply and demand can vary somewhat between regions, significant variations between most regions are generally short-term due to rig mobility. Rig attrition in the industry over the last decade, particularly for floaters, has resulted in a smaller global fleet of rigs that is available to meet customer demand.

Inflationary pressures impact our cost base, resulting in increased personnel costs as well as in the prices of goods and services required to operate our rigs or execute capital projects. Additionally, the weakening of the U.S. dollar against foreign currencies may increase costs in certain foreign jurisdictions in which we operate. We expect that our costs will continue to rise in the near term, particularly given the potential impact of increased tariffs on global trade, and although certain of our long-term contracts contain provisions for escalating costs, we cannot predict with certainty our ability to successfully claim recoveries of higher costs from our customers under these contractual stipulations.

Pending Business Combination with Transocean

On February 9, 2026, Valaris and Transocean (Valaris and Transocean, collectively, the “Parties” and each, a “Party”), entered into a Business Combination Agreement under which Transocean will acquire all of the issued and outstanding common shares of Valaris in exchange for shares of Transocean at an exchange ratio of 15.235 Transocean shares for each Valaris share. The Business Combination will be effected by way of a court-approved scheme of arrangement between Valaris and the holders of the Valaris shares pursuant to section 99 of the Companies Act 1981 of Bermuda, as amended. The Transocean shares are expected to be issued in reliance on the exemption from the registration requirements of the U.S. Securities Act of 1933, as amended, provided by Section 3(a)(10) thereof and pursuant to exemptions from registration under any applicable state securities laws. Following the consummation of the Business Combination, Transocean’s existing shareholders and Valaris’ existing shareholders will own approximately 53% and 47%, respectively, of the combined company on a fully diluted basis assuming conversion to shares of Transocean’s exchangeable bonds due 2029.

Completion of the Business Combination is subject to customary closing conditions, including (1) the receipt of the requisite approvals of the Valaris shareholders and the Transocean shareholders, (2) the granting of the sanction order on terms consistent with the Business Combination Agreement, (3) the Transocean shares issued pursuant to the Business Combination Agreement having been approved for listing on the NYSE, (4) certain regulatory approvals having been obtained or any applicable waiting period having expired or been terminated, (5) no governmental authority within applicable jurisdictions having enacted or issued any law or order preventing or prohibiting the consummation of the Business Combination and (6) the absence of a Transocean Material Adverse Effect or a Valaris Material Adverse Effect. Therefore, the Business Combination Agreement may not be completed or may not be completed as timely as expected.

In addition, the Business Combination Agreement also contains certain customary termination rights in favor of each Party, including for the failure to receive the requisite approvals of the Valaris shareholders and Transocean shareholders. In addition, a Party may terminate the Business Combination Agreement, prior to the receipt of the requisite approval of the other Party’s shareholders, if the other Party shall have made an Adverse Recommendation Change (as defined in the Business Combination Agreement). In addition, either Valaris or Transocean may terminate the Business Combination Agreement if the effective time shall not have occurred on or prior to February 9, 2027 (as such date may be extended in accordance with the terms of the Business Combination Agreement). If the Business Combination Agreement is terminated under specified circumstances, including if the Business Combination Agreement is terminated by Valaris for Transocean having made an Adverse Recommendation Change (as defined in the Business Combination Agreement), or for certain other triggering events, Valaris will be required to pay to Transocean a termination fee of $173.0 million.

The foregoing description of the Business Combination Agreement and the transactions contemplated thereby does not purport to be complete and is subject to and qualified in its entirety by reference to the Business Combination Agreement, a copy of which is filed as Exhibit 2.1 with the Current Report on Form 8-K, filed with the SEC on February 10, 2026.

See “ Part I . Item 1A - Risk Factors ” for further discussion about the risks related to the Business Combination.

Backlog

Our contract drilling backlog reflects commitments represented by signed drilling contracts and is calculated by multiplying the contracted operating day rate by the contract period. The contracted day rate excludes certain types of lump sum fees for rig mobilization, demobilization, contract preparation, as well as customer reimbursables and bonus opportunities. Our backlog excludes ARO's backlog but includes backlog from our rigs leased to ARO at the contractual lease rates, which are subject to adjustment under the terms of the shareholder agreement governing the joint venture (the "Shareholder Agreement").

The ARO backlog presented below is 100% of ARO's backlog and is inclusive of backlog on both ARO owned rigs and rigs leased from us. As an unconsolidated 50/50 joint venture, when ARO realizes revenue from its backlog, 50% of the earnings thereon would be reflected in our results in equity in earnings of ARO in our Consolidated Statements of Operations. The earnings from ARO backlog with respect to rigs leased from us will be net of, among other things, payments to us under bareboat charters for those rigs. See " Note 3 - Equity Method Investment in ARO " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data" for additional information.

The following table summarizes our and 100% of ARO's contract backlog of business as of February 17, 2026 and February 18, 2025 (in millions):

February 17, 2026

February 18, 2025

Floaters (1)

Jackups (2)

Other (3)

Total

ARO (4)

(1) The increase for Floaters is primarily due to contract awards and extensions executed for various drillships, which resulted in incremental aggregate backlog of approximately $2.1 billion, partially offset by revenues realized.

(2) The decrease for Jackups is primarily due to revenues realized and the removal of approximately $120.0 million of backlog from VALARIS 120, which completed a drilling program in December 2025 at which time the contract was suspended. We no longer expect future revenues to be realized under that contract, which was previously scheduled through mid-2028. This decrease was partially offset by various contract awards and extensions executed, which resulted in incremental aggregate backlog of approximately $590.0 million.

(3) Other includes the backlog for our managed rig services and the bareboat charter backlog for the jackup rigs leased to ARO in order for ARO to fulfill certain of its drilling contracts with Saudi Aramco. The increase in Other is primarily due to five-year contract extensions for five of our leased rigs, VALARIS 116, VALARIS 140, VALARIS 141, VALARIS 146 and VALARIS 250, which resulted in incremental aggregate backlog of approximately $407.0 million, partially offset by revenues realized.

(4) The increase for ARO is primarily due to five-year contract extensions for the five rigs leased, referenced above, which resulted in incremental aggregate backlog of approximately $1.2 billion, partially offset by revenues realized.

The following table summarizes our and 100% of ARO's contract backlog as of February 17, 2026 and the periods in which revenues are expected to be realized (in millions):

2028 and beyond

Total

Floaters

Jackups

Other

Total

ARO

The amount of actual revenues earned and the actual periods during which revenues are earned will be different from amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including unscheduled repairs, maintenance requirements, weather delays, contract terminations or renegotiations and other factors.

Our drilling contracts generally contain provisions permitting early termination of the contract if the rig is lost or destroyed or by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions. In addition, our drilling contracts generally permit early termination of the contract by the customer for convenience (without cause), exercisable upon advance notice to us, and in certain cases without making an early termination payment to us. There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.

See " Item 1A . Risk Factors - Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future."

BUSINESS ENVIRONMENT

Floaters

Within the floater segment, utilization for the global marketed drillship fleet was approximately 88% at the end of 2025 and included 13 drillships which were not working at year-end due to gaps between contracts. Market conditions are expected to improve as these rigs commence new contracts during 2026, including four Valaris drillships that are scheduled to return to work later in the year following idle periods between contracts. Customers continue to favor technically capable and efficient assets to support complex deepwater developments. Historically, seventh-generation drillships have achieved higher utilization and stronger day rates relative to older assets, a trend that is expected to continue. We believe we are well positioned in the market with 12 of 13 of our drillships being seventh-generation units.

Utilization for benign environment semisubmersibles, such as the remaining semisubmersible in our active fleet, continues to be lower than for drillships, and the outlook for this asset class remains challenging. In response to this market environment, we retired three benign environment semisubmersibles in 2025 and have classified VALARIS DPS-1 as held for sale as of December 31, 2025.

From a supply perspective, rig attrition over the past decade has resulted in a reduced global floater fleet to meet customer demand. The supply of benign environment floaters, such as those in our fleet, has decreased by more than 45% from a peak of approximately 280 rigs in 2014 to 150 rigs as of December 31, 2025. This decrease is primarily attributable to rig retirements, including 14 benign environment floaters retired in 2025. Further, given the expected high construction cost and lack of shipyard capacity, we do not believe that market conditions are supportive of floater newbuild construction for the foreseeable future.

Jackups

Global jackup utilization remains solid, with utilization at the end of 2025 of approximately 89%, driven primarily by national oil companies focused on energy security and infrastructure development. For example, Saudi Aramco recently recalled seven previously-suspended jackups to recommence operations in 2026 and there are other ongoing multi-rig tenders in the Middle East, which should further support the supply and demand balance of the global jackup fleet.

From a supply perspective, as of December 31, 2025, there were 494 jackups in the global fleet, with 29% of the current jackup fleet being more than 40 years of age with limited useful lives remaining. Further, we believe that some of the jackups that are currently idle are not competitive, either due to their age or the length of time stacked. Expenditures required to reactivate some of these rigs may prove cost prohibitive and drilling contractors may instead elect to scrap certain rigs.

RESULTS OF OPERATIONS

For the purposes of our discussion below, we refer to Revenues (exclusive of reimbursable revenues) and Contract drilling expenses (exclusive of depreciation and reimbursable expenses) as "revenues" and "contract drilling expenses", respectively. We typically receive reimbursements from our customers for purchases of supplies, equipment and incremental services provided at their request. These reimbursements and the related costs incurred are recognized on a gross basis within Reimbursable revenues and Reimbursable expenses, respectively. Changes within these line items generally do not have a material effect on our operating results or cash flows.

The following table summarizes our Consolidated Results of Operations for the years ended December 31, 2025 and 2024 (in millions, except percentages):

Years Ended December 31,

Change

% Change

Operating revenues

Revenues (exclusive of reimbursable revenues)

Reimbursable revenues

Total operating revenues

Operating expenses

Contract drilling expenses (exclusive of depreciation and reimbursable expenses)

Reimbursable expenses

Total contract drilling expenses (exclusive of depreciation)

Loss on impairment

Depreciation

General and administrative

Total operating expenses

Equity in earnings (losses) of ARO

Operating income

Other income, net

Provision (benefit) for income taxes

Net income

Net loss attributable to noncontrolling interests

Net income attributable to Valaris

NM - Not meaningful

Overview

Revenues remained relatively flat in 2025 compared to 2024, largely driven by a net decrease of $316.9 million from fewer operating days relative to the prior year, primarily due to certain floaters which completed their contracts since 2024 and have been either warm stacked or retired, partially offset by a net increase of $225.5 million from higher average daily revenues, largely attributable to various rigs working under higher day rate contracts in 2025. Further contributing to the offset were incremental revenues of $72.4 million for VALARIS DS-7, following its reactivation and commencement of a contract in May 2024.

Contract drilling expenses decreased in 2025 compared to 2024, primarily due to lower operating costs of $93.7 million for certain of our floater rigs which have been warm stacked or retired after completing contracts since the end of the second quarter of 2024 and a $18.5 million net decrease in expenses related to VALARIS DS-7, which was largely driven by reactivation costs incurred in the prior year and were partially offset by incremental operating costs in 2025. For the remaining fleet, we had a decrease of $45.2 million from lower mobilization costs compared to the prior year, largely driven by VALARIS 247 and certain other rigs within the fleet which mobilized to commence new contracts during 2024. Further contributing to the decrease was the reversal of a 2024 accrual for a previously disclosed patent license litigation during 2025 due to a favorable outcome. These decreases were partially offset by a net increase of $28.8 million related to higher personnel-related costs on various rigs, largely driven by more operating days within the jackup fleet.

In connection with the retirements of VALARIS DPS-3, VALARIS DPS-5 and VALARIS DPS-6 (collectively, the "Retired Semis") and VALARIS 102 and VALARIS 145 (collectively, the "Retired Jackups"), and the classification of VALARIS DPS-1 as held for sale, we recognized non-cash losses on impairment of $27.3 million in 2025. See " Note 5 - Property and Equipment " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for information regarding the retirement of these assets.

Depreciation expense increased in 2025 compared to 2024, primarily due to new assets placed in service, including those related to rigs that underwent capital upgrades.

General and administrative expenses decreased in 2025 compared to 2024, primarily due to $19.0 million of lower professional fees, partially related to a non-recurring $7.4 million cost recovery award recognized in 2025 related to fees incurred for the patent license litigation discussed above.

Other income, net, increased in 2025 compared to 2024, primarily due to an aggregate $115.4 million of pre-tax gains recognized in 2025 related to the sales of VALARIS 247, VALARIS 75 and an office in Angola. This increase was partially offset by unfavorable foreign currency exchange rate fluctuations of $28.1 million, lower interest income of $15.3 million and higher interest expense of $14.0 million.

Rig Counts, Utilization and Average Daily Revenue

The following table summarizes the total and active offshore drilling rigs for Valaris and ARO as of December 31, 2025 and 2024:

Total Fleet

Floaters (1)

Jackups (2)

Other (3)

Total Valaris

ARO (4)

Active Fleet (5)

Floaters (6)

Jackups (7)

Other (3)

Active Fleet - Valaris

ARO (4)

(1) During 2025, VALARIS DPS-3, VALARIS DPS-5 and VALARIS DPS-6 were sold. VALARIS DPS-1 is included in the Floaters count but was reclassified to held for sale as of December 31, 2025.

(2) During 2025, VALARIS 75, VALARIS 247, VALARIS 102 and VALARIS 145 were sold.

(3) This represents the jackup rigs leased to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. Rigs leased to ARO operate under long-term contracts with Saudi Aramco.

(4) This represents the jackup rigs owned by ARO, which are operating under long-term contracts with Saudi Aramco. This table does not include Kingdom 3 and Kingdom 4, which are newbuild jackups that are under construction in the Middle East.

(5) Active fleet represents rigs that are not preservation stacked or classified as held for sale and includes rigs that are in the process of being reactivated.

(6) During 2025, we classified VALARIS DPS-1 as held for sale, removing it from the active fleet, and sold VALARIS DPS-5.

(7) During 2025, we sold VALARIS 247.

We provide management services in the Gulf of America on two rigs owned by a third-party that are not included in the table above.

Operating results for our contract drilling services segment are largely dependent on two primary revenue metrics: utilization and day rates. The following table summarizes our and ARO's rig utilization and average daily revenue by reportable segment:

Years Ended December 31,

Rig Utilization - Total Fleet (1)

Floaters

Jackups

Other (2)

Total Valaris

ARO

Rig Utilization - Active Fleet (1)

Floaters

Jackups

Other (2)

Total Valaris

ARO

Average Daily Revenue (3)

Floaters

Jackups

Other (2)

Total Valaris

ARO

(1) Rig utilization for the total fleet and active fleet are derived by dividing the operating days by the number of days in the period for the total fleet and active fleet, respectively. Active fleet represents rigs that are not preservation stacked or classified as held for sale and includes rigs that are in the process of being reactivated. Operating days equals the total number of days that rigs have earned and recognized day rate revenue, including days associated with compensated downtime and mobilizations and excluding suspension periods. When revenue is deferred and amortized over a future period, for example, when we receive fees while mobilizing to commence a new contract or while being upgraded in a shipyard, the related days are excluded from operating days.

(2) Includes our two management services contracts and our rigs leased to ARO under bareboat charter contracts.

(3) Average daily revenue is derived by dividing Revenues (exclusive of reimbursable revenues), excluding contract termination fees, by the aggregate number of operating days.

Operating Income by Segment

Our business consists of four operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups, (3) ARO and (4) Other, which consists of management services on rigs owned by third parties and the activities associated with our arrangements with ARO under the bareboat charter arrangements (the "Lease Agreements"). Floaters, Jackups and ARO are also reportable segments.

Our onshore support costs included within contract drilling expenses are not allocated to our operating segments for purposes of measuring segment operating income (loss) and as such, those costs are included in “Reconciling Items." Further, general and administrative expenses and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income (loss) and are included in "Reconciling Items."

Because ARO is a 50/50 unconsolidated joint venture, its full operating results included below are not included within our consolidated results and thus are deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See " Note 3 - Equity Method Investment in ARO " to our consolidated financial statements included in "Item 8 . Financial Statements and Supplementary Data " for additional information.

Segment information for the years ended December 31, 2025 and 2024 is as follows (in millions).

Year Ended December 31, 2025

Floaters

Jackups

ARO

Other

Reconciling Items

Consolidated Total

Operating revenues:

Revenues (exclusive of

reimbursable revenues)

Reimbursable revenues

Total operating revenues

Operating expenses:

Contract drilling expenses

(exclusive of depreciation and

reimbursable expenses)

Reimbursable expenses

Total contract drilling expenses (exclusive of depreciation)

Loss on impairment

Depreciation

General and administrative

Equity in earnings of ARO

Operating income

Year Ended December 31, 2024

Floaters

Jackups

ARO

Other

Reconciling Items

Consolidated Total

Operating revenues:

Revenues (exclusive of

reimbursable revenues)

Reimbursable revenues

Total operating revenues

Operating expenses:

Contract drilling expenses

(exclusive of depreciation and

reimbursable expenses)

Reimbursable expenses

Total contract drilling expenses (exclusive of depreciation)

Loss on impairment

Depreciation

General and administrative

Equity in losses of ARO

Operating income

Floaters

Floater revenues decreased $158.7 million, or 11%, in 2025 compared to 2024, primarily due to a net decrease of $346.6 million from fewer operating days relative to the prior year, primarily due to certain floaters which completed their contracts since the end of the second quarter of 2024 and have either been warm stacked or retired. This decrease was partially offset by $72.4 million of incremental revenues for VALARIS DS-7, following its reactivation and commencement of a new contract in May 2024, and a net increase of $107.6 million from higher average daily revenues for the remaining fleet, resulting from various rigs working under higher day rate contracts during 2025.

Floater contract drilling expenses decreased $164.7 million, or 18%, in 2025 compared to 2024, primarily due to lower operating costs of $93.7 million for certain of our floater rigs which have been warm stacked or retired since the end of the second quarter of 2024 and a $18.5 million net decrease in expenses related to VALARIS DS-7, which was largely driven by reactivation costs incurred in the prior year period and was partially offset by incremental operating costs in 2025. For the remaining fleet, we had a decrease of $17.3 million from lower mobilization costs as a result of certain drillships which mobilized in the prior year. Further contributing to the decrease was the reversal of a 2024 accrual for a previously disclosed patent license litigation recognized in 2025 due to a favorable outcome.

In connection with the retirement of the Retired Semis and the classification of VALARIS DPS-1 as held for sale in 2025, we recognized non-cash losses on impairment of $23.6 million during 2025. See " Note 5 - Property and Equipment " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for information regarding the retirement of these assets.

Jackups

Jackup revenues increased $136.9 million, or 20%, in 2025 compared to 2024, largely driven by a net increase of $79.5 million from higher average daily revenues, primarily due to various rigs working under higher day rate contracts during 2025, and a net increase of $50.6 million from more operating days, primarily attributable to rigs which were preparing for new contracts or undergoing scheduled maintenance activities in the prior year.

Jackup contract drilling expenses increased $9.4 million, or 2%, in 2025 compared to 2024, primarily due to $32.1 million from higher personnel-related costs on various rigs as a result of more operating days during 2025, partially offset by $27.9 million of lower mobilization costs, largely attributable to VALARIS 247, which mobilized from the United Kingdom to Australia during the prior year.

In connection with the retirement of the Retired Jackups in 2025, we recognized a non-cash loss on impairment of $3.7 million during 2025. See " Note 5 - Property and Equipment " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for information regarding the retirement of these assets.

Jackup depreciation expense increased $13.6 million, or 30%, in 2025 compared to 2024, primarily due to new assets placed in service for certain rigs that underwent capital upgrades.

ARO

The operating revenues of ARO reflect revenues earned under drilling contracts with Saudi Aramco for both the ARO-owned jackup rigs and the rigs leased from us. Contract drilling expenses are inclusive of the bareboat charter fees for the rigs leased from us. See " Note 3 - Equity Method Investment in ARO " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for additional information on ARO and related arrangements.

ARO revenues increased $58.5 million, or 11%, in 2025 compared to 2024, primarily due to incremental revenues of $47.5 million from Kingdom 2, which commenced operations in August 2024, and VALARIS 108, which we began leasing to ARO late in the first quarter of 2024. Further contributing to the increase were net increases of $38.4 million from more operating days for the remaining fleet, largely driven by certain rigs which were undergoing maintenance projects in the prior year, and $28.5 million from higher average daily revenues, driven by the commencement of five long-term contract extensions at higher day rates than those earned in the prior year. These increases were partially offset by a decrease of $55.9 million related to the contract terminations for VALARIS 143, VALARIS 147 and VALARIS 148 during 2024.

ARO contract drilling expenses decreased $7.0 million, or 2%, in 2025 compared to 2024, primarily due to a decrease of $55.2 million from lower operating costs for VALARIS 143, VALARIS 147 and VALARIS 148. This decrease was partially offset by $20.3 million of incremental operating costs for Kingdom 2 and VALARIS 108 and $19.4 million of increased bareboat charter lease expenses for five of our leased rigs which commenced long-term bareboat charter lease extensions at higher rates during 2025.

During the year ended December 31, 2024, ARO recorded non-cash losses on impairment totaling $28.4 million with respect to the contract terminations for VALARIS 143, VALARIS 147 and VALARIS 148. See " Note 3 - Equity Method Investment in ARO " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for information regarding the impairment.

ARO depreciation expense increased $25.7 million, or 29%, in 2025 compared to 2024, primarily due to the addition of Kingdom 2 to the fleet and new assets placed in service for certain rigs that underwent capital upgrades.

Other

Other revenues increased $17.8 million, or 12%, in 2025 compared to 2024, primarily due to higher lease revenue of $16.8 million, largely attributable to five long-term bareboat charter lease extensions at higher rates for our leased rigs to ARO which commenced in 2025.

Other contract drilling expenses increased $7.0 million, or 11%, in 2025 compared to 2024, primarily due to higher personnel-related costs and increased repairs and maintenance costs.

Other Income (Expense), Net

The following table summarizes other income (expense), net (in millions):

Years Ended December 31,

Net gain (loss) on sale of property

Interest expense, net

Interest income

Net foreign currency exchange gains (losses)

Net periodic pension and retiree medical income (loss)

Other, net

Net gains on sale of property in 2025 primarily related to the sales of VALARIS 247, VALARIS 75 and an office in Angola, which resulted in aggregate pre-tax gains of $115.4 million. See " Note 5 - Property and Equipment " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for information regarding the rig sales.

Interest expense, net increased by $14.0 million, or 17%, in 2025 compared to 2024, primarily due to lower capitalized interest for VALARIS DS-13 and VALARIS DS-14, which were delivered at the end of 2023 and mobilized to the shipyard in 2024.

Interest income decreased by $15.3 million, or 18%, in 2025 compared to 2024, primarily due to a $15.8 million decrease in interest income earned on our outstanding Notes Receivable from ARO, which was largely driven by the recognition of $13.9 million of non-cash interest income related to an adjustment to the discount on our outstanding Notes Receivable with ARO as part of a net settlement agreement in the prior year period and a lower interest rate as a result of an annual interest rate reset that occurred at the end of 2024.

Net foreign currency exchange losses were $14.3 million in 2025 compared to $13.8 million of gains in 2024, primarily driven by unfavorable exchange rate movements in euros, Brazilian real, British pounds, Mexican pesos and Australian dollars. See " Note 1 - Description of the Business and Summary of Significant Accounting Policies " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for further information on our functional currency.

Provision for Income Taxes

Valaris Limited is domiciled and a resident for tax purposes in Bermuda. Our subsidiaries conduct operations and earn income in numerous countries and are subject to the laws of taxing jurisdictions within those countries. The income of our non-Bermuda subsidiaries is not subject to Bermuda taxation.

Income tax rates and taxation systems in the jurisdictions in which our subsidiaries conduct operations vary and our subsidiaries are frequently subjected to minimum taxation regimes. In some jurisdictions, tax liabilities are based on gross revenues, statutory deemed profits or other factors, rather than on net income, and our subsidiaries are frequently unable to realize tax benefits when they operate at a loss. Accordingly, during periods of declining profitability, our income tax expense may not decline proportionally with income, which could result in higher effective income tax rates. Furthermore, we will continue to incur income tax expense in periods in which we operate at a loss.

Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. As a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in profitability levels and changes in tax laws, our annual effective income tax rate may vary substantially from one reporting period to another.

Effective Tax Rate

During the year ended December 31, 2025, we recorded an income tax benefit of $426.8 million and had an effective income tax rate of (77.3)%. The income tax benefit was primarily related to a net $523.2 million reduction of our valuation allowance, largely driven by changes in the balances of relevant positive and negative evidence considered when assessing the realization of our deferred tax assets in certain operating jurisdictions.

Our 2025 consolidated effective income tax rate includes a discrete tax expense of $153.7 million, primarily attributable to the establishment of a valuation allowance in connection with the retirement of the Retired Semis, partially offset by discrete tax benefit attributable to rig impairments. Excluding the impact of the aforementioned discrete tax items, the consolidated effective income tax rate was (92.2)% as of December 31, 2025.

During the year ended December 31, 2024, we recorded an income tax expense of $0.4 million and had an effective income tax rate of 0.1%. Our 2024 consolidated effective income tax rate includes a discrete tax benefit of $85.8 million, primarily attributable to changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rate was 21.8% for the year ended December 31, 2024.

The changes in our consolidated effective income tax rate excluding discrete tax items during the two-year period result primarily from changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and differences in tax rates in such taxing jurisdictions.

See " Note 10 - Income Taxes " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for additional information.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect to fund our short-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as working capital requirements, from cash and cash equivalents and cash flows from operations. Additionally, we have liquidity available under our senior secured revolving credit agreement, which matures in 2028 (the "2028 Credit Agreement."). We expect to fund our long-term liquidity needs, including contractual obligations and anticipated capital expenditures, from cash and cash equivalents, cash flows from operations, as well as cash to be received from the distribution of earnings from ARO. We may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs, subject to certain restrictions provided within the Business Combination Agreement. However, the Indenture governing our 2030 Second Lien Notes, as defined below, dated as of April 19, 2023 (the "Indenture"), and the 2028 Credit Agreement contain covenants that limit our ability to incur additional indebtedness.

Our cash and cash equivalents as of December 31, 2025 and 2024, were $599.4 million and $368.2 million, respectively. We have no debt principal payments due until 2030 and had $375.0 million available for borrowing, including up to $150.0 million for the issuance of letters of credit, under the 2028 Credit Agreement as of February 13, 2026. See " Note 6 - Debt " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for additional information on the 2028 Credit Agreement and the 8.375% Second Lien Notes due 2030 (the "2030 Second Lien Notes").

Cash Flows and Capital Expenditures

Absent periods where we have significant financing or investing transactions or activities, such as debt or equity issuances, share repurchases, debt repayments, business combinations or asset sales, our primary sources and uses of cash are driven by cash generated from or used in operations and capital expenditures. Our net cash provided by operating activities and capital expenditures were as follows (in millions):

Years Ended December 31,

Net cash provided by operating activities

Capital expenditures

During the year ended December 31, 2025, we generated $546.2 million of cash flow from operating activities primarily due to operating income for the year of $477.0 million, approximately $26.0 million of tax refunds received from the Australian tax authority during the first quarter of 2025 and other changes in working capital. An additional source of cash was $137.9 million of cash proceeds related to the sales of certain assets in 2025. Our primary uses of cash were $343.5 million for maintenance and upgrades of our drilling rigs and $100.0 million for our share repurchase program, which is discussed further below.

During the year ended December 31, 2024, we generated $355.4 million of cash flow from operating activities primarily due to operating income for the year of $352.3 million. Our primary uses of cash were $455.1 million for maintenance and upgrades of our drilling rigs, reactivation costs and costs to mobilize VALARIS DS-13 and VALARIS DS-14 to their stacking location after their delivery. Additionally, we spent $126.4 million under our share repurchase program during the year, which is discussed further below.

We completed our most recent rig reactivation project in the first half of 2024. Generally, most of the reactivation costs are operating expenses, recognized in the income statement, related to de-preservation activities, including reinstalling key pieces of equipment and crew costs. Capital expenditures during reactivations include rig modifications, equipment overhauls and any customer required capital upgrades. We are generally compensated for any customer-specific enhancements.

Based on our current projections, we expect capital expenditures during 2026 to approximate $425.0 million to $475.0 million, primarily relating to maintenance and upgrade projects, including contract-specific capital expenditures. Depending on market conditions, contracting activity and future opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and acquire additional rigs, subject to certain restrictions within the Business Combination Agreement.

We review from time to time possible acquisition opportunities relating to our business, which may include the acquisition of rigs or other businesses. The timing, size or success of any acquisition efforts and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with cash on hand and proceeds from debt and/or equity issuances and may issue equity directly to the sellers. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend on our future operating performance, restrictions to incur additional debt in the Indenture and the 2028 Credit Agreement, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global financial markets and other factors, many of which are beyond our control. In addition, any additional debt service requirements we take on could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to shareholders.

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations that no longer meet our standards for economic returns. While taking into account certain restrictions on the sales of assets under our debt agreements and within the Business Combination Agreement, as part of our strategy, we may act opportunistically from time to time to monetize assets to enhance shareholder value and improve our liquidity profile, in addition to reduce holding costs by selling or disposing of lower-specification or non-core rigs.

We sold the following rigs during the years ended December 31, 2025 and 2024 (in millions):

Rig

Date of Sale

Segment (1)

Net Proceeds (2)

Pre-tax Gain on sale

(Loss on Impairment)

Retired Jackups (3)

December 2025

Jackups

VALARIS 247

August 2025

Jackups

Retired Semis (3)

April 2025

Floaters

VALARIS 75 (4)

January 2025

Jackups

(1) Classification denotes the location of any prior operating results, gain on sale or loss on impairment for the respective rig in our Consolidated Statements of Operations.

(2) Represents gross proceeds less certain selling and transaction costs, including brokerage fees, commissions and other directly related expenses.

(3) The Retired Semis and Retired Jackups were sold for recycling and removed from service during 2025.

(4) Of the proceeds related to the sale of VALARIS 75, approximately $14.0 million was collected upon closing in January 2025, $5.0 million was collected in January 2026, and the remaining $5.0 million is expected to be received on the second anniversary of the closing.

Financing and Capital Resources

2030 Second Lien Notes

In 2023, the Company and Valaris Finance Company LLC (“Valaris Finance,” together, the "Issuers"), issued and sold $1.1 billion in aggregate principal amount of 8.375% Senior Secured Second Lien Notes due 2030 (the "2030 Second Lien Notes"). The 2030 Second Lien Notes mature on April 30, 2030 and bear an interest rate of 8.375% per annum. Interest is payable semi-annually in arrears on April 30 and October 30 of each year. See “ Note 6 - Debt " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for additional information on the 2030 Second Lien Notes.

2028 Credit Agreement

The 2028 Credit Agreement provides for commitments permitting borrowings of up to $375.0 million (which may be increased, subject to the satisfaction of certain conditions and the agreement of lenders to provide such additional commitments, by an additional $200.0 million pursuant to the terms of the 2028 Credit Agreement) and includes a $150.0 million sublimit for the issuance of letters of credit. Valaris Finance and certain other subsidiaries of the Company (together with Valaris Finance, the “Guarantors”) guarantee the Company’s obligations under the 2028 Credit Agreement, and the lenders have a first priority lien on the assets securing the 2028 Credit Agreement. The commitments under the 2028 Credit Agreement became available to be borrowed on April 19, 2023.

See “ Note 6 - Debt " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for additional information on the 2028 Credit Agreement.

Investment in ARO and Notes Receivable from ARO

We expect to receive cash from ARO in the future both from the maturity of our Notes Receivable from ARO and from the distribution of earnings from ARO.

The distribution of earnings to the joint-venture partners is at the discretion of the ARO board of managers, consisting of 50/50 membership of managers appointed by Saudi Aramco and managers appointed by us, with approval required by both shareholders. The timing and amount of any cash distributions to the joint-venture partners cannot be predicted with certainty and will be influenced by various factors, including the liquidity position and capital allocation priorities of ARO. ARO has not made a cash distribution of earnings to its partners since its formation. ARO had cash and cash equivalents of $99.3 million as of December 31, 2025.

The Notes Receivable from ARO, which are governed by the laws of Saudi Arabia, mature during 2027 and 2028. We expect to agree to extend the maturity of the Notes Receivable from ARO to facilitate its capital allocation priorities, in particular its newbuild jackup rig program. Notwithstanding any extension of the maturity, in the event that ARO does not repay the Notes Receivable from ARO when they become due, we would require the prior consent of our joint venture partner to enforce ARO's payment obligations. In 2025, interest owed by ARO on the Notes Receivable from ARO of $24.1 million was paid in kind in December 2025 by increasing the principal balance of the Notes Receivable from ARO.

See " Note 3 - Equity Method Investment in ARO " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for additional information on our investment in ARO and Notes Receivable from ARO.

The following table summarizes the maturity schedule of our Notes Receivable from ARO as of December 31, 2025 (in millions):

Maturity Date

Principal Amount

October 2027

October 2028

Total

Contractual Obligations

The following table summarizes our significant contractual obligations as of December 31, 2025 and the periods in which such obligations are due (in millions):

Payments due by period

2027 and 2028

2029 and 2030

Thereafter

Total

Principal payments on long-term debt

Interest payments on long-term debt

Operating leases

Total contractual obligations (1)

(1) Contractual obligations do not include $136.2 million of unrecognized tax benefits, inclusive of interest and penalties, included within Other liabilities on our Consolidated Balance Sheet as of December 31, 2025. We are unable to specify with certainty whether we would be required to and in which periods we may be obligated to settle such amounts.

In connection with our 50/50 unconsolidated joint venture, we have a potential obligation to fund ARO for newbuild jackup rigs. The Shareholder Agreement specifies that ARO shall purchase 20 newbuild jackup rigs. The joint venture partners intend for the newbuild jackup rigs to be financed from available cash on hand and from ARO's operations and/or funds available from third-party financing. The first two newbuild jackups, Kingdom 1 and Kingdom 2, were delivered and commenced operations in 2023 and 2024, respectively. In October 2023, ARO entered into a $359.0 million term loan to finance the remaining payments due upon delivery of the two rigs and for general corporate purposes. The term loan matures in eight years following the related drawdown under the term loan and requires equal quarterly amortization payments during the term, with a 50% balloon payment due at maturity. The term loan bears interest based on the three-month Secured Overnight Financing Rate ("SOFR") plus a margin ranging from 1.25% to 1.4%. In 2024, ARO entered into a revolving credit facility which provides for borrowings of up to $100.0 million, which was amended in the fourth quarter of 2025 to increase the maximum borrowings to $150.0 million. As of December 31, 2025, there were no amounts outstanding under this facility. Our Notes Receivable from ARO are subordinated and junior in right of payment to both ARO’s term loan and credit facility.

In October 2024 and November 2025, ARO ordered the third and fourth newbuild jackups, Kingdom 3 and Kingdom 4, respectively, for a purchase price of approximately $300.0 million each. ARO paid a 25% down payment upon ordering Kingdom 3 from cash on hand in 2024 and made payments of $43.8 million related to the 25% down payment for Kingdom 4 from cash on hand as of December 31, 2025, with the remaining down payment balance payable in monthly installments through May 2026. ARO expects these newly ordered jackup rigs to be financed from cash on hand or from operations or funds available from third-party financing. In the event ARO has insufficient cash or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Beginning with the delivery of the second newbuild, each partner's commitment is reduced by the lesser of the actual cost of each newbuild rig or $250.0 million, on a proportionate basis. Following the delivery of Kingdom 2, our commitment to fund the newbuild program has been reduced to $1.1 billion. See " Note 3 - Equity Method Investment in ARO " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for additional information on ARO.

Other Commitments

We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. As of December 31, 2025, we were contingently liable for an aggregate amount of $35.4 million under outstanding letters of credit, which guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2025, we had collateral deposits in the amount of $16.3 million with respect to these agreements.

The following table summarizes our other commitments as of December 31, 2025 (in millions):

Commitment expiration by period

2027 and 2028

2029 and 2030

Thereafter

Total

Letters of credit

Tax Assessments

In February 2024, one of our Malaysian subsidiaries received an unfavorable court decision regarding a tax assessment for the 2012-2017 tax years totaling approximately MYR117.0 million (approximately $29.0 million converted at current quarter-end exchange rates), including a late payment penalty. In July 2024, we received a payment demand from the Malaysian tax authority for the full assessment amount. In order to further contest the assessment, we made payments of approximately $8.0 million and $18.0 million in 2025 and 2024, respectively, for aggregate total payments of $26.0 million as of December 31, 2025. These payments are included within Other assets in the Consolidated Balance Sheets. There are no further payments remaining as of December 31, 2025. We have not recorded a liability for uncertain tax positions as of December 31, 2025, related to this assessment based on a more-likely-than-not threshold. We believe our tax returns are materially correct as filed and will vigorously contest this assessment.

During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101.0 million, plus interest, related to the examination of certain of our tax returns for the years 2011 through 2016. During the third quarter of 2019, we made a A$42.0 million payment (approximately $29.0 million at then-current exchange rates) to the Australian tax authorities to litigate the assessment. In December 2024, we reached a settlement agreement with the Australian tax authorities for A$4.0 million (approximately $2.0 million at then-current exchange rates). Accordingly, we released approximately $18.0 million of the uncertain tax position liability previously recognized and recognized a corresponding tax benefit in our Consolidated Statements of Operations for these assessments in 2024. We no longer had a liability for unrecognized tax benefits relating to these assessments as of December 31, 2024. During the first quarter of 2025, we received refunds (including interest) totaling A$42.0 million (approximately $26.0 million at then-current-period exchange rates).

See " Note 10 - Income Taxes " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for additional information on these tax assessments.

Share Repurchase Program

Our board of directors has authorized a share repurchase program under which we may purchase up to $600.0 million of our outstanding common shares. The following table summarizes shares repurchases, aggregate cost and the average per share price (in millions, except average per share price):

Years Ended December 31,

Shares repurchased

Total aggregate cost

Average per share price

As of December 31, 2025, we had approximately $175.0 million available for share repurchases pursuant to the Share Repurchase Program, subject to certain restrictions provided within the Business Combination Agreement.

Effects of Climate Change and Climate Change Regulation

GHG emissions have increasingly become the subject of international, national, regional, state and local attention, and in recent years, the U.S. has taken evolving and divergent positions on GHG regulations and commitments. For example, the U.S. initiated the process of withdrawing from the Paris Agreement in January 2025 and completed its withdrawal in January 2026, after previously reentering it in February 2021. In November 2021, the U.S. and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of clean energy. New regulatory action and/or legislation targeting GHG emissions, or prohibiting, restricting, or delaying oil and gas development activities in certain areas, may be proposed and/or promulgated at the state or local level of the U.S.

In an effort to reduce GHG emissions, governments have implemented or considered legislative and regulatory mechanisms to institute carbon pricing mechanisms, such as the EU’s Emission Trading System, and to impose technical requirements to reduce carbon emissions. Governments have also proposed, implemented or amended new or enhanced disclosure requirements related to climate change matters and GHG emissions that may increase compliance and disclosure costs. In January 2023, the EU enacted the Corporate Sustainability Reporting Directive to require sustainability reporting across a broad range of sustainability topics for both EU and non-EU companies. In 2025, the EU delayed the reporting timeline for many in-scope companies and, in December 2025, continued to progress on amendments that would limit the number of companies obligated to report under the law. These requirements could apply to us as early as 2028 (for fiscal year 2027) for certain of our EU subsidiaries and at the consolidated entity level in 2029 (for fiscal year 2028).

During 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings allowed the agency to proceed with the adoption and implementation of regulations to restrict GHG emissions under existing provisions of the Clean Air Act that establish permitting requirements, including emissions control technology requirements, for certain large stationary sources that are potential major sources of GHG emissions. The EPA has also adopted rules requiring annual monitoring and reporting of GHG emissions from specified sources in the U.S., including, among others, certain onshore and offshore oil and natural gas production facilities, although in 2025, the EPA proposed rules that would rescind the 2009 endangerment finding and, accordingly, rescind regulations promulgated on the basis of that finding. In the absence of federal legislation, almost half of the states have begun to address GHG emissions, primarily through the development or planned development of emission inventories or regional GHG cap-and-trade programs and commitments to contribute to meeting the goals of the Paris Agreement.

Future legislation or regulation of GHG emissions could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. Depending on the particular program, we, or our customers, could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. It is uncertain whether any of these initiatives will be implemented and what the impact of such initiatives would have on our financial condition, operating results and cash flows.

In connection with our sustainability-related efforts, during 2025, we spent approximately $4.1 million. Our sustainability initiatives will continue to require, among other actions, investment in systems and equipment and cooperation with our customers.

MARKET RISK

Interest Rate Risk

Our outstanding debt at December 31, 2025 consisted of our $1.1 billion aggregate principal amount of 2030 Second Lien Notes. We are subject to interest rate risk on our fixed-interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in market interest rates impacting the fair value of the debt.

Our 2028 Credit Agreement provides for commitments permitting borrowings of up to $375.0 million at December 31, 2025. As the interest rates for such borrowings are at variable rates, we are subject to interest rate risk. As of December 31, 2025, we had no outstanding borrowings under the 2028 Credit Agreement.

Our Notes Receivable from ARO bear interest based on the one-year term SOFR rate, set as of the end of the year prior to the year applicable, plus 2.10%. As the Notes Receivable from ARO bear interest on the applicable SOFR rate determined at the end of the preceding year, the rate governing our interest income in 2026 has already been determined. A hypothetical 1% decrease to SOFR would decrease interest income for the year ended December 31, 2026 by $4.0 million based on the principal amount outstanding at December 31, 2025 of $400.7 million.

Foreign Currency Risk

Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S. dollar. We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs from our obligations in the foreign currency or revenue earned differs from costs incurred in the foreign currency. We do not currently hedge our foreign currency risk.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the U.S. requires us to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Our significant accounting policies are included in " Note 1 - Description of the Business and Summary of Significant Accounting Policies " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data. " These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements.

We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results and that require the most difficult, subjective and/or complex judgments regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, income taxes and pension and other post-retirement benefits.

Property and Equipment

As of December 31, 2025, the carrying value of our property and equipment totaled $2.1 billion, which represented 39% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate our estimates, judgments and assumptions relative to the capitalized costs, useful lives and salvage values of our rigs.

We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies require estimates, judgments and assumptions relative to the nature of, and benefits from, expenditures on our assets. We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives. We have identified the significant components of our drilling rigs and ascribed useful lives based on the expected time until the next required overhaul or the end of the expected economic lives of the components.

The judgments and assumptions used in determining the next overhaul or the economic lives of the components of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of the significant components our rigs, would likely result in materially different asset carrying values and operating results.

The useful lives of our drilling rig components are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rig components on a periodic basis, considering operating condition, functional capability and market and economic factors.

Our fleet of 14 floater rigs, excluding our held-for-sale rig, represented 57% of the gross cost and 59% of the net carrying amount of our depreciable property and equipment as of December 31, 2025. Our fleet of 31 jackup rigs represented 40% of the gross cost and 39% of the net carrying amount of our depreciable property and equipment as of December 31, 2025.

Income Taxes

We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As of December 31, 2025, our Consolidated Balance Sheet included a $1,334.5 million net deferred income tax asset, a $59.4 million liability for income taxes currently payable and a $136.2 million liability for unrecognized tax benefits, inclusive of interest and penalties.

The carrying values of deferred income tax assets and liabilities reflect the application of our income tax accounting policies and are based on estimates, judgments and assumptions regarding future operating results and levels of taxable income. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.

We do not provide deferred taxes on the undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we may be subject to additional income taxes.

The carrying values of liabilities for income taxes currently payable and unrecognized tax benefits are based on our interpretation of applicable tax laws and incorporate estimates, judgments and assumptions regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, judgments and assumptions in connection with accounting for income taxes, especially those involving the deployment of tax planning strategies, may result in materially different carrying values of income tax assets and liabilities and operating results.

We operate in several jurisdictions where tax laws relating to the offshore drilling industry are not well developed. In jurisdictions where available statutory law and regulations are incomplete or underdeveloped, we obtain professional guidance and consider existing industry practices before utilizing tax planning strategies and meeting our tax obligations. Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information.

Tax returns are routinely subject to audit in most jurisdictions and tax liabilities occasionally are finalized through a negotiation process. In some jurisdictions, income tax payments may be required before a final income tax obligation is determined in order to avoid significant penalties and/or interest. While we historically have not experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:

• In order to utilize tax planning strategies and conduct operations efficiently, our subsidiaries frequently enter into transactions with affiliates that are generally subject to complex tax regulations and are frequently reviewed and challenged by tax authorities.

• We may conduct future operations in certain tax jurisdictions where tax laws are not well developed, and it may be difficult to secure adequate professional guidance.

• Tax laws, regulations, agreements, treaties and the administrative practices and precedents of tax authorities change frequently, requiring us to modify existing tax strategies to conform to such changes.

Pension and Other Postretirement Benefits

Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, mortality rates, annual compensation increases, and other factors. Key assumptions at December 31, 2025, included (1) a weighted average discount rate of 5.34% to determine pension benefit obligations, (2) a weighted average discount rate of 5.54% to determine net periodic pension cost and (3) an expected long-term rate of return on pension plan assets of 6.44% to determine net periodic pension cost. The assumed discount rate is based upon the average yield for either Moody’s or Standard & Poor's Aa-rated corporate bonds, and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations.

Using our key assumptions at December 31, 2025, a one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $52.4 million, while a one-percentage-point decrease (increase) in the expected long-term rate of return on plan assets would increase (decrease) annual net benefits cost by approximately $4.6 million. To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which increased to 6.62% at December 31, 2025 from 6.44% at December 31, 2024. See " Note 9 - Pension and Other Post Retirement Benefits " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for information on our pension and other postretirement benefit plans.

NEW ACCOUNTING PRONOUNCEMENTS

See " Note 1 - Description of the Business and Summary of Significant Accounting Policies " to our consolidated financial statements included in " Item 8 . Financial Statements and Supplementary Data " for information on new accounting pronouncements.