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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

FORM 10-K
(Mark One)

☑ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

OR

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to

Commission File Number 1-8097

Valaris Limited
(Exact name of registrant as specified in its charter)

Bermuda |  | 98-1589854
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
Clarendon House, 2 Church Street |  |
Hamilton | Bermuda |  |  | HM 11
(Address of principal executive offices) |  | (Zip Code)

Registrant's telephone number, including area code: +44 (0) 20 7659 4660

Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Ticker Symbol(s) |  | Name of each exchange on which registered
Common Shares, $0.01 par value share |  | VAL |  | New York Stock Exchange
Warrants to purchase Common Shares |  | VAL WS |  | New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (S232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act:

Large accelerated filer | ☒ |  | Accelerated filer | o
Non-Accelerated filer | o |  | Smaller reporting company | ☐
|  |  | Emerging growth company | ☐

☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
☒ Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
☐ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐
The aggregate market value of the common shares (based upon the closing price on the New York Stock Exchange on June 30, 2025 of $42.11 of the registrant held by non-affiliates of Valaris Limited at that date) was approximately $2.5 billion.
As of February 13, 2026, there were 69,230,926 common shares of the registrant outstanding.

TABLE OF CONTENTS
PART I | ITEM 1. | BUSINESS | 6
| ITEM 1A. | RISK FACTORS | 15
| ITEM 1B. | UNRESOLVED STAFF COMMENTS | 42
| ITEM 1C. | CYBERSECURITY | 43
| ITEM 2. | PROPERTIES | 45
| ITEM 3. | LEGAL PROCEEDINGS | 47
| ITEM 4. | MINE SAFETY DISCLOSURES | 47
PART II | ITEM 5. | MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | 48
| ITEM 6 | RESERVED | 50
| ITEM 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 51
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 75
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | 76
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | 132
| ITEM 9A. | CONTROLS AND PROCEDURES | 132
| ITEM 9B. | OTHER INFORMATION | 132
| ITEM 9C. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS | 132
PART III | ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | 133
| ITEM 11. | EXECUTIVE COMPENSATION | 133
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS | 134
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE | 134
| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES | 134
PART IV | ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | 135
| ITEM 16. | FORM 10-K SUMMARY | 139
|  | SIGNATURES | 140

FORWARD-LOOKING STATEMENTS
Statements contained in this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "likely," "outlook," "plan," "project," "could," "may," "might," "should," "will" and similar words and specifically include statements regarding expected financial performance; expected utilization, day rates, revenues, operating expenses, cash flows, contract status, terms and duration, contract backlog, capital expenditures, insurance, financing and funding; our expectations regarding the timing, completion and anticipated benefits of the pending business combination (the "Business Combination") with Transocean Ltd.; the offshore drilling market, including supply and demand, customer drilling programs, stacking of rigs, effects of new rigs on the market and effect of the volatility of commodity prices; expected work commitments, awards, contracts and letters of intent; the availability, delivery, mobilization, contract commencement or relocation or other movement of rigs and the timing thereof; rig reactivations, enhancement, upgrade or repair and timing and cost thereof; the suitability of rigs for future contracts; performance and expected benefits of our joint ventures, including our joint venture with Saudi Arabian Oil Company ("Saudi Aramco"); timing of the delivery of the Saudi Aramco Rowan Offshore Drilling Company ("ARO") newbuild rigs and the timing of additional ARO newbuild orders; divestitures of assets; general market, business and industry conditions, trends and outlook; general political conditions, including political tensions, conflicts and war; the impacts and effects of public health crises, pandemics and epidemics; future operations; the effectiveness of our cybersecurity programs; uncertainty around the use and impacts of artificial intelligence ("AI") applications; expectations regarding our sustainability targets and strategy; the impact of increasing regulatory complexity; the outcome of tax disputes, assessments and settlements; expense management; and the likely outcome of litigation, legal proceedings, investigations or insurance or other claims or contract disputes and the timing thereof.
Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:
•our ability to complete the Business Combination as timely as expected or at all, the impact of the significant management time and resources expended in an effort to complete the Business Combination, any disruptions to our relationships with third parties and employees or negative publicity or legal proceedings related to the Business Combination or disruptions to our ongoing operations, and uncertainty regarding the outcome of the Business Combination;
•delays in contract commencement dates or cancellation, suspension, renegotiation or termination with or without cause of drilling contracts or drilling programs as a result of general or industry-specific economic conditions, regulatory changes, mechanical difficulties, performance, delays in the delivery of critical drilling equipment, failure of the customer to receive final investment decision (FID) for which the drilling rig was contracted or other reasons;
•changes in worldwide rig supply and demand, competition or technology;
•general economic and business conditions, including recessions, inflation, volatility affecting the banking system and financial markets, changing tariff and tax policies, trade disputes and adverse changes in the level of international trade activity;
•requirements to make significant expenditures in connection with customer drilling requirements, joint ventures, rig reactivations and to comply with governing laws or regulations in the regions we operate;
•loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, including focusing on renewable energy projects;
2

•our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to labor regulations, rising wages, unionization, or otherwise, or to retain employees;
•the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems, including our rig operating systems;
•the adequacy of sources of liquidity for us and our customers;
•compliance with our debt agreements and debt restrictions that may limit our liquidity and flexibility;
•our ability to obtain financing, service our debt, fund capital expenditures and pursue other business opportunities;
•risks inherent to drilling rig repairs, modifications, upgrades or reactivations, unexpected delays in equipment delivery, engineering, design or commissioning issues following delivery, or changes in the commencement, completion or service dates;
•our ability to generate operational efficiencies from our shared services center and potential risks relating to the processing of transactions and recording of financial information;
•downtime and other risks associated with offshore rig operations, including rig or equipment failure, damage and other unplanned repairs, the limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to severe storms and hurricanes and the limited availability or high cost of insurance coverage for certain offshore perils, such as hurricanes in the Gulf of America or associated removal of wreckage or debris;
•our customers cancelling or shortening the duration of our drilling contracts, cancelling future drilling programs and seeking pricing and other contract concessions from us;
•decreases in levels of drilling activity and capital expenditures by our customers, whether as a result of the global capital markets and liquidity, prices of oil and natural gas, changes in tax policy (such as the United Kingdom’s (the "U.K.") windfall tax on oil and gas producers in the British North Sea), climate change concerns or otherwise, which may cause us to idle, stack or retire additional rigs;
•impacts and effects of public health crises, pandemics and epidemics, the related public health measures implemented by governments worldwide, the duration and severity of an outbreak and its impact on global oil demand, the volatility in prices for oil and natural gas and the extent of disruptions to our operations;
•disruptions to the operations and business of our key customers, suppliers and other counterparties, including impacts affecting our supply chain and logistics;
•governmental action, terrorism, cyber-attacks, piracy, military action and political and economic uncertainties, including civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas, which may result in expropriation, nationalization, confiscation or deprivation or destruction of our assets; suspension and/or termination of contracts based on force majeure events or adverse environmental safety events; or volatility in prices of oil and natural gas;
•risks associated with operations in non-U.S. jurisdictions and the expansion into new geographical markets;
•risks and challenges resulting from the use of AI by us, third-party service providers or our competitors;
3

•disputes over production levels among members of the Organization of Petroleum Exporting Countries and other oil and gas producing nations (“OPEC+”), which could result in increased supply and/or volatility in prices for oil and natural gas that could affect the markets for our services;
•our ability to enter into, and the terms of, future drilling contracts for rigs currently idled and for rigs whose contracts are expiring;
•any failure to execute definitive contracts following announcements of letters of intent, letters of award or other expected work commitments;
•the outcome of litigation, legal proceedings, investigations or other claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, and any renegotiation, nullification, cancellation or breach of contracts with customers or other parties;
•internal control risk due to changes in management, hiring of employees, employee reductions and our shared service center;
•governmental regulatory, legislative and permitting requirements affecting drilling operations, including limitations on drilling locations, limitations on new oil and gas leasing in United States (the "U.S.") federal lands and waters, and legislative or regulatory measures to limit or reduce greenhouse gas emissions ("GHG");
•governmental policies that could reduce demand for hydrocarbons, including mandating or incentivizing the conversion from internal combustion engine powered vehicles to electric-powered vehicles;
•forecasts or expectations regarding the global energy transition, including consumer preferences for alternative fuels and electric-powered vehicles, as part of the global energy transition;
•increased scrutiny from regulators, market and industry participants, stakeholders and others in regard to our sustainability practices and reporting;
•our ability to achieve our sustainability aspirations, targets, goals and commitments, or the impact of any changes to such matters;
•potential impacts on our business resulting from climate-change, and the impact on our business from climate-change related physical changes or changes in weather patterns;
•new and future regulatory, legislative or permitting requirements, future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill abatement contingency plan capability requirements and other governmental actions that may result in claims of force majeure or otherwise adversely affect our existing drilling contracts, operations or financial results;
•environmental or other liabilities, risks, damages or losses, whether related to storms, hurricanes or other weather-related events (including wreckage or debris removal), collisions, groundings, blowouts, fires, explosions, cyber-attacks, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;
•tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws (including global minimum tax initiatives), treaties and regulations, tax assessments and liabilities for taxes;
•our ability to realize the expected benefits of our joint venture with Saudi Aramco, including our ability to fund any required capital contributions or to enforce any payment obligations of the joint venture pursuant to outstanding shareholder notes receivable and benefits of our other joint ventures;
4

•the potentially dilutive impacts of outstanding warrants;
•the costs, disruption and diversion of our management's attention associated with campaigns by activist securityholders; and
•adverse changes in foreign currency exchange rates.
In addition to the numerous risks, uncertainties and assumptions described above, you should also carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Part II of this Annual Report on Form 10-K. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law.
5

PART I
Item 1. Business
General
Valaris Limited is a global offshore contract drilling company. Unless the context requires otherwise, the terms "Valaris," "Company," "we," "us" and "our" refer to Valaris Limited together with all its subsidiaries and predecessors.
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.
Pending Business Combination with Transocean
On February 9, 2026, Valaris and Transocean Ltd. ("Transocean") entered into a business combination agreement (the “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. See "Par t II. Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations - Introduction - Pending Business Combination with Transocean" for further information.
6

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.
Contract Drilling Operations
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 lease arrangements with ARO. Floaters, Jackups and ARO are also reportable segments.
As of December 31, 2025, we owned 46 rigs and excluding our held-for-sale rig, 17 are located in Europe, 16 are located in Middle East and Africa, eight are located in North and South America and four are located in Asia and the Pacific Rim.
Our drilling rigs drill and complete oil and natural gas wells. From time to time, our drilling rigs may be utilized as accommodation units or for other ancillary services such as well workovers and interventions, plug and abandonment and decommissioning work and carbon capture and sequestration projects. Demand for our drilling services is based upon many factors beyond our control. See “Item 1A. Risk Factors - The success of our business depends on the level of activity in offshore oil and natural gas exploration, which can be significantly affected by volatile oil and natural gas prices.”
7

Our drilling contracts are negotiated with our customers, and most contracts are awarded following competitive bidding. The terms of our drilling contracts vary, but generally contain the following commercial terms:
•contract duration or term for a specific period of time or a period necessary to drill one or more wells,
•term extension options, exercisable by our customers, upon advance notice to us, at mutually agreed, indexed, fixed rates or current rate at the date of extension,
•provisions permitting early termination of the contract, which may include (1) if the rig is lost or destroyed, (2) if operations are suspended for a specified period of time due to various events, including damage or breakdown of major rig equipment, unsatisfactory performance, "force majeure" events or breach of contract, (3) failure of the customer to receive final investment decision (FID) approval with respect to projects for which the drilling rig was contracted or (4) at the convenience (without cause) of the customer, exercisable upon advance notice to us, and in certain cases without making an early termination payment to us,
•payment of compensation to us is (generally in U.S. dollars, although some contracts require a portion of the compensation to be paid in local currency) on a day rate basis such that we receive a fixed amount for each day that the drilling rig is under contract (lower day rates generally apply for periods when operations are suspended due to various events, including during delays that are beyond our reasonable control, during repair of equipment damage or breakdown and during periods of re-drilling damaged portions of the well, and no day rate, or zero rate, generally applies when these limited periods are exceeded until the event is remediated, and during periods to remediate unsatisfactory performance or other specified conditions),
•payment by us of the operating expenses of the drilling rig, including crew labor and incidental rig supply and maintenance costs,
•mobilization and demobilization requirements of us to move the drilling rig to and from the planned drilling site, and may include reimbursement of all or a portion of these moving costs by the customer in the form of an up-front payment, additional day rate over the contract term or direct reimbursement, and
•provisions allowing us to recover certain labor and other operating cost increases from our customers through day rate adjustment or direct reimbursement for certain cost increases due to changes in applicable law or rising operational expenses.
Contract awards generally remain subject to a highly competitive bidding process, which could result in contracts that contain unfavorable contractual and commercial terms, such as certain limitations on our ability to be indemnified from operator and third-party damages caused by our negligence, gross negligence or willful misconduct, resulting in increases in the nature and amounts of liability allocated to us, which we endeavor to limit through a financial cap.
Backlog Information
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for backlog information.
Major Customers
We provide our contract drilling services to major international, government-owned and independent oil and gas companies. During the year ended December 31, 2025, our five largest customers accounted for 49% of consolidated revenues. Petróleo Brasileiro S.A. ("Petrobras"), BP plc ("BP") and Azule Energy ("Azule"), our customers who account for 10% or more of consolidated revenues, accounted for 35% of consolidated revenues.
8

Competition
The offshore contract drilling industry is highly competitive. Drilling contracts are, for the most part, awarded on a competitive bid basis. Price is often the primary factor in determining which contractor is awarded a contract, although quality of service, operational and safety performance, equipment suitability and availability, location of equipment, reputation and technical expertise are also factors.
Non-U.S. Operations
Revenues from non-U.S. operations were 86%, 84% and 80% of our total consolidated revenues during the years ended December 31, 2025, 2024 and 2023, respectively.
See "Item 1A. Risk Factors - Our non-U.S. operations involve additional risks not typically associated with U.S. operations."
Insurance and Indemnification Matters
Our insurance program provides coverage, subject to the policies' terms and conditions and to the extent not otherwise assumed by the customer under the indemnification provisions of the drilling contract, for third-party liability claims arising from our operations. Our insurance program provides coverage that is customary for our industry. Generally, our insurance program provides third-party liability coverage up to $855.0 million. We retain the risk for liability not indemnified by the customer in excess of, and for risks not covered by, our insurance coverage.
Our insurance program also provides hull and machinery coverage for physical damage (including total loss) to our rigs, cargo and equipment, excluding damage arising from a named windstorm in the Gulf of America. We separately purchase a small limit of named windstorm insurance for our floater rigs in the Gulf of America. We carry limited insurance for loss of hire for several of our rigs.
Our customers typically indemnify us for most well-control events. Well-control events generally include an unintended release from a well that cannot be contained by using equipment on site, such as a blowout preventer, by increasing the weight of drilling fluid or by diverting the fluids safely into production facilities. Subject to the exceptions noted below, our customers typically assume most of the responsibility for and indemnify us from any loss, damage or other liability resulting from pollution or contamination arising from operations. Such pollution or contamination may be as a result of blowouts, cratering and seepage, when the source of the pollution originates from the well or reservoir. Such indemnities typically include costs for clean-up and removal of pollution and third-party damages.
Our drilling contracts customarily provide that each party is responsible for injuries or death to their respective personnel and loss or damage to their respective property (including the personnel and property of each parties’ contractors and subcontractors) regardless of the cause of the loss or damage. However, exceptions may exist as it relates to damages due to our negligence. In addition, our drilling contracts typically provide for our customers to indemnify us, generally based on replacement cost minus some level of depreciation, for loss or damage to our down-hole equipment. In some cases, we are indemnified by our customer for a limited amount of the repair of or replacement cost of our subsea equipment. We also maintain insurance for exposures to personal injuries, damage to or loss of property and certain business risks.
We generally indemnify the customer for legal and financial consequences of spills of waste oil, fuels, lubricants, motor oils, pipe dope, paint, solvents, ballast, bilge, garbage, debris, sewage, hazardous waste and other liquids, the discharge of which originates from our rigs or equipment above the surface of the water and in some cases from our subsea equipment. Our contracts generally provide that, in the event of any such spill from our rigs, we are also responsible for the related fines and penalties.
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The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the date hereof and is general in nature. In addition, our drilling contracts are individually negotiated, and the degree of indemnification we receive from operators against the liabilities discussed above can vary from contract to contract based on market conditions and customer requirements existing when the contract was negotiated and the interpretation and enforcement of applicable law when the claim is adjudicated. Our insurance program and the terms of our drilling contracts may change in the future.
In certain cases, vendors who provide equipment or services to us limit their pollution liability to a specific monetary cap, and we assume the liability above that cap. Typically, in the case of original equipment manufacturers, the cap is a negotiated amount based on mutual agreement of the parties considering the risk profiles and thresholds of each party. However, for smaller vendors, the liability is usually limited to the value, or double the value, of the contract for the purchase of such equipment or services.
Additional information on insurance and indemnification matters and related risks is discussed in “Item 1A. Risk Factors,” which should be read in conjunction with the foregoing information.
Governmental Regulation and Environmental Matters
Our operations are affected by laws, regulations and political initiatives that relate to the oil and natural gas industry, including laws and regulations that have or may impose increased oil-spill related and financial responsibility requirements. Laws and regulations curtailing exploration and development drilling for oil and natural gas will directly affect us for economic, environmental, safety or other policy reasons. It is also possible that these laws, regulations and political initiatives could adversely affect our operations in the future by significantly increasing our operating costs or restricting areas open for drilling activity. We incorporate by reference herein the disclosures on governmental regulations, including environmental matters, contained in the following sections of this Annual Report on Form 10-K:
•"Item 1A. Risk Factors – Regulatory, Legal and Tax Risks";
•"Item 1A. Risk Factors – Sustainability Risks";
•"Item 3. Legal Proceedings"; and
•"Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Effects of Climate Change and Climate Change Regulation."
The International Convention on Oil Pollution Preparedness, Response and Cooperation, the International Convention on Civil Liability for Oil Pollution Damage 1992, the U.K. Merchant Shipping Act 1995, Marpol 73/78 (the International Convention for the Prevention of Pollution from Ships), the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998, as amended, the Oil Pollution Act of 1990 ("OPA 90"), as amended, the Clean Water Act and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention, reporting and control and have significantly expanded potential liability, fine and penalty exposure across many segments of the oil and natural gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Similar environmental laws apply in our other areas of operation.
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Sustainability
Consistent with our purpose of providing responsible solutions that deliver energy to the world, we are focused on sustainability-related matters to drive continued shareholder value and meet the demands of our stakeholders. Our board of directors' Safety and Sustainability Committee regularly meets to address sustainability topics and is responsible for overseeing the Company’s policies, programs and practices related to sustainability as well as the Company’s management of risks in such areas. We also have a dedicated department focused on sustainability and new energy and a cross-functional working group to identify and evaluate opportunities and promote sustainable business practices.
For further discussion of sustainability-related risks and considerations see “Risk Factors” in Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report on Form 10-K.
We encourage you to review our latest Sustainability Report, located on our website (www.valaris.com), for more detailed information regarding our sustainability programs and initiatives. Nothing on our website, including our Sustainability Report or sections thereof, shall be deemed incorporated by reference into this Annual Report on Form 10-K or other filings that we make with the SEC.
Human Capital
We believe our people are one of the most important elements of our success, and we benefit from a motivated, engaged and diverse workforce. Our approach to attracting, developing and retaining a workforce of high-performing talent is anchored in a long-term employment model that seeks to foster personal growth and engagement.
Purpose and Culture
At Valaris, our purpose is to provide responsible solutions that deliver energy to the world. Our values are designed to guide us in support of our purpose:
•Integrity – Doing the right thing, whether or not anyone is watching;
•Safety – Causing no harm is always a priority;
•Excellence – Delivering value to our customers while consistently raising the bar on performance;
•Respect – Treating others the way we would like to be treated;
•Ingenuity – Solving problems creatively; and
•Stewardship – Safeguarding where we work for the next generation.
Our Ethics and Compliance Policy and our Code of Conduct (the “Code”) form the foundation of our compliance and ethics program, which provides guidance on how to uphold our values. We have translated the Code into nine different languages, making it widely accessible to our employees across the globe. We maintain an Ethics Hotline that is available to all employees, either online or by phone, to confidentially seek guidance or raise a concern.
The Code is reviewed on a periodic basis and approved by our board of directors. To further support our values of respect and integrity, we have policies prohibiting corruption, bribery (including facilitation payments), money laundering, retaliation and reprisals for raising concerns, including those related to worker rights, working conditions, mistreatment, fraud and misconduct. In addition, we have adopted a policy against modern slavery and human trafficking in our business and our supply chains.
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Employees
We had a global workforce of approximately 5,070 persons including contractors, and approximately 3,800 persons excluding contractors, as of December 31, 2025. Our personnel represented 78 nationalities spread across 25 locations. The majority of our personnel work on our offshore rigs and are compensated on an hourly basis. A portion of our employees and contractors working outside of the U.S. are represented under collective bargaining or similar agreements, which are subject to periodic salary negotiation.
Employee Wellbeing and Engagement
We believe that one of the best ways to serve our customers is through creating a healthy, safe and engaging working and learning environment, where our employees are confident and comfortable to put their best work forward. We seek to promote a healthy environment by prioritizing the mental and physical health and other needs of our employees while recognizing them for their achievements and accomplishments. For example, in most countries where we work, we offer an employee assistance program (“EAP”) to employees and their families. Our EAP provides access to counselors and other mental health professionals as well as discounts to fitness centers, financial guidance and other benefits in support of our overall commitment to maintain a healthy workforce.
Feedback from our employees plays a key role in creating an agile, collaborative and trustworthy culture. We use surveys to measure employee engagement as well as our ability to align and execute around a common vision and foster innovation and creativity. These surveys help our leaders analyze the impact of company practices and culture on performance and have created a roadmap for improvement.
Training and Retention
We are focused on developing talent and leadership among both our onshore and offshore employees. In 2021, we launched the Building Organizational Leadership (BOLD) training program. This program is designed to engage, support and provide leadership tools for our offshore supervisors, helping them assess and develop their team’s understanding and use of our safety processes and policies. Approximately 1,620 personnel have attended the program since its launch. Also, in 2025, we launched an enhanced leadership development program for senior offshore leaders, which was delivered through targeted workshops during the year to strengthen management effectiveness and decision-making in complex operating environments.
We provide regular training in health, safety, environmental and emergency response to our employees, as relevant to their roles, and we mandate that our employees complete training related to the Code, covering topics such as anti-corruption, workplace behavior and conflicts of interest. In addition, in 2025, all employees were assigned "Workplace Harassment" training as part of supporting a more inclusive workforce. Certain employees must also complete additional training on topics ranging from trade compliance to human trafficking.
Safety
Our policies set the expectation that causing no harm is a priority while conducting our operations. We seek to control major operational hazards with effective safeguards, robust barrier management, and the disciplined implementation of management systems designed to protect the health and safety of our personnel, the environment and our assets.
As part of our focus on preventing high-consequence events, in 2025, we implemented BarrierPulse TM a barrier management and performance monitoring framework that provides structured oversight of safety-critical barriers and escalation reporting for leadership visibility. BarrierPulse TM supports the identification, verification, and monitoring of barriers intended to prevent, detect, or mitigate major accident hazards, enhancing our ability to understand barrier status and health, enhancing our ability to take timely corrective action before a major event occurs.
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Our Safe Systems of Work are designed with the aim of completing each job safely and efficiently:
●Work Instruction – Step-by-step descriptions of how to complete specific work activities, including mandatory precautions and controls to be implemented;
●Permit to Work – Formal authorization and control process for the safe execution of potentially hazardous work that may present risk to people, the environment or assets;
●Energy Isolation – Formal isolation of all energy sources before performing work on equipment;
●Job Safety Analysis – Identification and control of job-specific hazards before starting work; and
●Stop Work Authority – Empowerment to stop work if a risk to people, the environment or assets is perceived to exist.
Information about our Executive Officers
Officers generally serve for a one-year term or until successors are elected and qualified to serve. The table below sets forth certain information regarding our executive officers as of February 20, 2026:

Name |  | Age |  | Position
Anton Dibowitz |  | 53 |  | President and Chief Executive Officer
Christopher Weber |  | 53 |  | Senior Vice President and Chief Financial Officer
Gilles Luca |  | 54 |  | Senior Vice President and Chief Operating Officer
Matthew Lyne |  | 51 |  | Senior Vice President and Chief Commercial Officer
Davor Vukadin |  | 52 |  | Senior Vice President and General Counsel and Secretary

Set forth below is certain additional information on our executive officers, including the business experience of each executive officer for at least the last five years:
Anton Dibowitz became the President and Chief Executive Officer of Valaris in December 2021, following his service as the Company’s interim President and Chief Executive Officer since September 2021. Mr. Dibowitz joined the Valaris board of directors in July 2021. Prior to joining the Valaris board of directors, he served as an advisor of Seadrill Ltd., a global offshore drilling contractor, from November 2020 until March 2021. He served as Chief Executive Officer of Seadrill Ltd. from July 2017 until October 2020. Prior to this, Mr. Dibowitz served as Executive Vice President of Seadrill Management since June 2016, and as Chief Commercial Officer since January 2013. He has over 20 years of drilling industry experience. Prior to joining Seadrill, Mr. Dibowitz held various positions within tax, process reengineering and marketing at Transocean Ltd. and Ernst & Young LLP. He is a Certified Public Accountant and a graduate of the University of Texas at Austin where he received a Bachelor's degree in Business Administration and Master's degrees in Professional Accounting (MPA) and Business Administration (MBA).
Christopher Weber became the Senior Vice President and Chief Financial Officer of Valaris in August 2022. Previously, he served as Chief Financial Officer of LUFKIN Industries, a leading global provider of rod lift optimization solutions, products, technologies and services to the oil and gas industry, from February 2021 to July 2022. Mr. Weber also served as Chief Financial Officer of Abaco Drilling Technologies from July 2019 to February 2021 and Chief Financial Officer of Halliburton Company from June 2017 to November 2018. Prior to Halliburton, Mr. Weber served as Chief Financial Officer of Parker Drilling Company and held senior finance roles at Valaris predecessor companies. He received an MBA in Finance and Strategy from the Wharton School and a BA in Economics and English Literature from Vanderbilt.
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Gilles Luca became Senior Vice President and Chief Operating Officer in December 2019. Previously, he served as Senior Vice President, Operations Support. He joined Valaris in 1997. Mr. Luca also served Valaris as Senior Vice President - Western Hemisphere, Vice President - Business Development and Strategic Planning, Vice President - Brazil Business Unit and General Manager - Europe and Africa. Before joining Valaris as an Operations Engineer in The Netherlands, Mr. Luca was employed by Foramer Drilling and Schlumberger with assignments in France and Venezuela. He holds a Master's Degree in Petroleum Engineering from the French Petroleum Institute and a Bachelor in Civil Engineering.
Matthew Lyne became the Senior Vice President and Chief Commercial Officer of Valaris in September 2022. Previously, he served as Executive Vice President, Chief Commercial and Strategy Officer of Seadrill Limited from May 2021 to September 2022. Seadrill Limited filed for bankruptcy in February 2021. Prior to this role, he held a number of senior marketing and commercial roles at Seadrill Limited for more than 10 years. He also served in a number of senior operational and functional roles with Transocean Ltd. prior to joining Seadrill Limited. Mr. Lyne has over 20 years of offshore drilling experience in various international locations. Mr. Lyne has a Bachelor of Science degree in Engineering from Montana Technological University.
Davor Vukadin was appointed Senior Vice President, General Counsel and Secretary in May 2022. Before being named to his current position, Mr. Vukadin served as Associate General Counsel and Secretary from June 2021 to May 2022. Previously, he served as Associate General Counsel and Assistant Secretary from November 2018 to June 2021. He joined Valaris as Senior Counsel in 2014. Prior to joining Valaris, Mr. Vukadin practiced corporate and securities law with the law firm of Norton Rose Fulbright for thirteen years. He holds a Bachelor of Arts degree in Economics from The University of Chicago and a law degree from The University of Texas School of Law.
Available Information
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports that we file with, or furnish to, the Securities and Exchange Commission ("SEC") in accordance with the Exchange Act are available free of charge on our website at www.valaris.com/investors. In addition, the SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The information contained on our website is not included as part of, or incorporated by reference into, this report.
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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.
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•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.
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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;
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•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.
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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,
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•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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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
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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.
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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.
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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.
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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.
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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.”
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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.
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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.
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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.
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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,
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•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
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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.
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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.
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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 1B. Unresolved Staff Comments
None.
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Item 1C. Cybersecurity
We have a cybersecurity program designed to assess, identify and manage risks from cybersecurity threats. The Company’s cybersecurity program includes administrative, technical and physical safeguards that address our information systems, including our IT and operational technology environments. The program is designed to ensure the confidentiality, security, integrity and availability of those systems and the information residing therein.
Strategy and Risk Management:
Our cybersecurity strategy leverages administrative safeguards that include policies, procedures and processes to assess, identify and manage risks from cybersecurity threats. We have adopted a Cybersecurity Incident Response Policy (the “CIRP”), which provides a framework and procedures for investigating, containing, documenting and mitigating incidents, including reporting findings and keeping senior management and other key stakeholders informed and involved as appropriate.
Additionally, all of the Company’s employees are required to undertake an annual cybersecurity training program on how to identify characteristics of various cybersecurity threats and ways to report such threats, which is augmented by additional training and communications on IT and cybersecurity matters throughout the year. Periodically during the year, the Company’s IT department leads simulations of cybersecurity incidents with employees, including annual tabletop exercises for offshore employees, to test the organization’s ability to respond to a variety of cybersecurity-related scenarios.
Our policies, procedures and processes are aligned with our technical tools, which include security monitoring and alerting, cybersecurity incident identification and remediation, and other technologies to ensure the security of our systems and information. We also have implemented certain physical safeguards, such as restricted access to areas containing critical IT and operational technology equipment, to mitigate risks to our physical environment.
Cybersecurity is integrated into our enterprise risk management ("ERM") process. Cybersecurity-related risks are included in our ERM risk register, which are reviewed by internal stakeholders who designate the relative level of severity of identified risks. The ERM risk register, which includes any identified cybersecurity-related risks, is reviewed by our Executive Management Committee and is reported quarterly to the board of directors, who then reviews the risk register, including any changes in key risks, and provides oversight as appropriate.
Oversight:
The Audit Committee is responsible for, and actively engaged in, the oversight of our IT and cybersecurity program, including the oversight of risks from cybersecurity threats and risks posed by the use and impacts of artificial intelligence. Two of the members of the Audit Committee have obtained a certification or completed coursework in cybersecurity. The Audit Committee, at least quarterly, receives reports from the Company’s Senior Director – Information Technology (“SDIT”) on, among other things, the Company’s cybersecurity incidents, risks, threats and measures, training and organizational readiness. The board of directors is kept apprised of cybersecurity risk matters, including through participation in the quarterly cybersecurity briefings to the Audit Committee that are described above. We have protocols by which certain cybersecurity incidents are escalated within the Company and, where appropriate, reported in a timely manner to the board of directors and Audit Committee.
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At the management level, the SDIT and his team are responsible for leading enterprise-wide information security strategy, policy, standards, architecture and processes, including the assessment and management of material risks from cybersecurity threats. The Company’s SDIT reports to the Chief Financial Officer. The SDIT has extensive cybersecurity knowledge and skills, gained from over 25 years of relevant work experience. The SDIT is informed about and monitors the prevention, detection, mitigation and remediation of cybersecurity incidents in accordance with the CIRP, which may include reports from the IT team. The SDIT also regularly reviews risk management measures implemented by the Company to identify and mitigate cybersecurity risks.
Third Parties and Assessments:
We engage third-party service providers in various capacities to strengthen our cybersecurity posture. The Company works with external consultants to conduct cybersecurity assessments, which may include evaluations of cloud security, network vulnerabilities and other areas of cyber risk. Our IT department, along with other key stakeholders, including Internal Audit, determines the need, scope and frequency of these assessments based on the Company's cybersecurity risk evaluation process.
Further, pursuant to our CIRP, we may engage third-party support to enable an effective and timely response to a significant cybersecurity incident.
In addition to assessing our own cybersecurity preparedness, we also consider and evaluate cybersecurity risks associated with use of third-party service providers. We obtain Systems and Organization Controls ("SOC") 1 and SOC 2 reports, as applicable, from our third-party service providers which assess those entities' controls to cover security, availability, integrity, confidentiality and privacy. Any applicable findings of this third-party assessment are analyzed by the appropriate employees and further action is taken as needed.
Impact of Cybersecurity Risks and Threats:
While we have not experienced any material cybersecurity threats or incidents as of the date of this Annual Report on Form 10-K, there can be no guarantee that we will not be the subject of future successful attacks, threats or incidents. Additional information on cybersecurity risks we face is discussed in “Item 1A. Risk Factors,” which should be read in conjunction with the foregoing information.
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Item 2. Properties
Contract Drilling Fleet
The following table provides certain information about the rigs in our drilling fleet as of February 17, 2026:

Rig Name | Rig Type |  | Year Delivered |  | Design |  | Maximum Water Depth/ Drilling Depth |  | Location | Status
Floaters |  |  |  |  |  |  |  |  |  |
VALARIS DS-4 | Drillship |  | 2010 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Brazil | Under contract
VALARIS DS-7 | Drillship |  | 2013 |  | Dynamically Positioned |  | 10,000'/40,000' |  | Angola | Under contract
VALARIS DS-8 | Drillship |  | 2015 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Brazil | Under contract
VALARIS DS-9 | Drillship |  | 2015 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Angola | Under contract
VALARIS DS-10 | Drillship |  | 2017 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Spain | Future contract
VALARIS DS-11 | Drillship |  | 2013 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Spain | Preservation stacked(1)
VALARIS DS-12 | Drillship |  | 2013 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Spain | Future contract
VALARIS DS-13 | Drillship |  | 2023 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Spain | Preservation stacked(1)
VALARIS DS-14 | Drillship |  | 2023 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Spain | Preservation stacked(1)
VALARIS DS-15 | Drillship |  | 2014 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Spain | Future contract
VALARIS DS-16 | Drillship |  | 2014 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Gulf of America | Under contract
VALARIS DS-17 | Drillship |  | 2014 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Brazil | Under contract
VALARIS DS-18 | Drillship |  | 2015 |  | Dynamically Positioned |  | 12,000'/40,000' |  | Gulf of America | Future contract
VALARIS DPS-1 | Semisubmersible |  | 2012 |  | Dynamically Positioned |  | 10,000'/35,000' |  | Malaysia | Held for sale
VALARIS MS-1 | Semisubmersible |  | 2011 |  | F&G ExD Millennium, Moored |  | 8,200'/40,000 |  | Malaysia | Available
Jackups |  |  |  |  |  |  |  |  |  |
VALARIS 72 | Jackup |  | 1981 |  | Hitachi K1025N |  | 225'/25,000' |  | United Kingdom | Under contract
VALARIS 76 | Jackup |  | 2000 |  | MLT Super 116-C |  | 350'/30,000' |  | Saudi Arabia | Leased to ARO drilling
VALARIS 92 | Jackup |  | 1982 |  | MLT 116-C |  | 210'/25,000' |  | United Kingdom | Under contract
VALARIS 104 | Jackup |  | 2002 |  | KFELS MOD V-B |  | 400'/30,000' |  | UAE | Preservation stacked(1)
VALARIS 106 | Jackup |  | 2005 |  | KFELS MOD V-B |  | 400'/30,000' |  | Indonesia | Future contract
VALARIS 107 | Jackup |  | 2006 |  | KFELS MOD V-B |  | 400'/30,000' |  | Australia | Under contract
VALARIS 108 | Jackup |  | 2007 |  | KFELS MOD V-B |  | 400'/30,000' |  | Saudi Arabia | Leased to ARO drilling
VALARIS 109 | Jackup |  | 2008 |  | KFELS MOD V-Super B |  | 350'/35,000' |  | Namibia | Preservation stacked(1)
VALARIS 110 | Jackup |  | 2015 |  | KFELS MOD V-B |  | 400'/35,000' |  | Qatar | Under contract
VALARIS 111 | Jackup |  | 2003 |  | KFELS MOD V Enhanced B-Class |  | 400'/36,000' |  | Croatia | Preservation stacked(1)
VALARIS 115 | Jackup |  | 2013 |  | Baker Marine Pacific Class 400 |  | 400'/30,000' |  | Brunei | Under contract
VALARIS 116 | Jackup |  | 2008 |  | LT 240- C |  | 375'/35,000' |  | Saudi Arabia | Leased to ARO drilling
VALARIS 117 | Jackup |  | 2009 |  | LT 240- C |  | 350'/35,000' |  | Mexico | Under contract
VALARIS 118 | Jackup |  | 2012 |  | LT 240- C |  | 350'/35,000 |  | Trinidad | Under contract
VALARIS 120 | Jackup |  | 2013 |  | KFELS Super A |  | 400'/40,000' |  | United Kingdom | Under contract
VALARIS 121 | Jackup |  | 2013 |  | KFELS Super A |  | 400'/40,000' |  | United Kingdom | Under contract
VALARIS 122 | Jackup |  | 2013 |  | KFELS Super A |  | 400'/40,000' |  | United Kingdom | Under contract
VALARIS 123 | Jackup |  | 2019 |  | KFELS Super A |  | 400'/40,000' |  | Netherlands | Under contract
VALARIS 140 | Jackup |  | 2016 |  | LT Super 116E |  | 340'/30,000' |  | Saudi Arabia | Leased to ARO drilling
VALARIS 141 | Jackup |  | 2016 |  | LT Super 116E |  | 340'/30,000' |  | Saudi Arabia | Leased to ARO drilling
VALARIS 143 | Jackup |  | 2010 |  | LT EXL Super 116-E |  | 350'/35,000' |  | UAE | Preservation stacked(1)
VALARIS 144 | Jackup |  | 2010 |  | LT Super 116-E |  | 350'/35,000' |  | Angola | Under contract

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Rig Name | Rig Type |  | Year Delivered |  | Design |  | Maximum Water Depth/ Drilling Depth |  | Location | Status
Jackups (Continued) |  |  |  |  |  |  |  |  |  |
VALARIS 146 | Jackup |  | 2011 |  | LT EXL Super 116-E |  | 320'/35,000' |  | Saudi Arabia | Leased to ARO drilling
VALARIS 147 | Jackup |  | 2013 |  | LT Super 116-E |  | 350'/30,000' |  | UAE | Preservation stacked(1)
VALARIS 148 | Jackup |  | 2013 |  | LT Super 116-E |  | 350'/30,000' |  | UAE | Preservation stacked(1)
VALARIS 248 | Jackup |  | 2000 |  | LT Super Gorilla |  | 400'/35,000' |  | United Kingdom | Under contract
VALARIS 249 | Jackup |  | 2001 |  | LT Super Gorilla |  | 400'/35,000' |  | Trinidad | Under contract
VALARIS 250 | Jackup |  | 2003 |  | LT Super Gorilla XL |  | 550'/35,000' |  | Saudi Arabia | Leased to ARO drilling
VALARIS Viking | Jackup |  | 2010 |  | KEFLS N Class |  | 435'/35,000' |  | United Kingdom | Preservation stacked(1)
VALARIS Stavanger | Jackup |  | 2011 |  | KEFLS N Class |  | 400'/35,000' |  | United Kingdom | Under contract
VALARIS Norway | Jackup |  | 2011 |  | KEFLS N Class |  | 400'/35,000' |  | United Kingdom | Under contract

(1)Prior to stacking, upfront steps are taken to preserve the rig. This may include a quayside power source to dehumidify key equipment and/or provide electric current to the hull to prevent corrosion. Also, certain equipment may be removed from the rig for storage in a temperature-controlled environment. While stacked, large equipment that remains on the rig is periodically inspected and maintained by Valaris personnel. These steps are designed to reduce time and lower cost to reactivate the rig once returned to the active fleet.
We provide Mobile Offshore Drilling Units (MODUs) and associated services to support our clients' offshore exploration, appraisal, production and carbon capture and storage activities, including drilling new wells, servicing existing wells and eventually abandoning wells. Our MODUs are marine vessels that function as drilling rigs, equipped to drill offshore wells and, on occasion, install customer’s surface and subsea equipment. The intended water depth, environmental conditions, well depth and geological conditions are the principal factors that determine the size and type of drilling unit most suitable for a particular offshore project.
Floater rigs consist of drillships and semisubmersibles. Drillships are purpose-built maritime vessels outfitted with drilling equipment packages. Drillships are self-propelled and can be positioned over a well location through the use of dynamic positioning systems. Our 13 drillships are capable of drilling in water depths of up to 12,000 feet.
Semisubmersibles are drilling rigs with pontoons and columns that are partially submerged at the drilling location to provide added stability during drilling operations. Semisubmersibles are held in a fixed location over the ocean floor either by mooring systems or through dynamic positioning. Our moored semisubmersible is capable of drilling in water depths of up to 8,000 feet and our dynamically positioned semisubmersible is capable of drilling in water depths of up to 10,000 feet.
Jackups are drilling rigs that operate in shallower water depths of 400 feet or less. They are self-elevating MODUs that can be towed to a field location and elevated above the waterline using leg-jacking systems. The cantilever and drilling equipment extends outward from the hull over fixed platforms or open water locations to allow well operations to take place. We currently have 31 jackup rigs in our fleet.
We own all rigs in our fleet and we manage the drilling operations for two platform rigs owned by a third-party.
We lease various office, warehouse and storage facilities worldwide, including our corporate offices in Houston, Texas and other offices and facilities located in various countries in North America, South America, Europe, Middle East, Africa and the Asia Pacific region. We own offices and other facilities in the U.S. (Louisiana) and Brazil.
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Item 3. Legal Proceedings
Environmental Matters
We are currently subject to pending notices of assessment relating to spills of drilling fluids, oil, brine, chemicals, grease or fuel from drilling rigs operating offshore Brazil from 2008 to 2017, pursuant to which the governmental authorities have assessed, or are anticipated to assess, fines. We have contested these notices and appealed certain adverse decisions and are awaiting decisions in these cases. Although we do not expect final disposition of these assessments to have a material adverse effect on our financial position, operating results and cash flows, there can be no assurance as to the ultimate outcome of these assessments. A $0.5 million liability related to these matters was included in Accrued liabilities and other on our Consolidated Balance Sheet as of December 31, 2025 included in "Item 8. Financial Statements and Supplementary Data."
Other Matters
In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.
See “Note 11 - Commitments and Contingencies” to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II

Item 5. | Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information
On April 30, 2021, the Company issued an aggregate of approximately 75.0 million Common Shares and Warrants are traded on the NYSE under the symbols “VAL” and “VAL WS”, respectively.
Many of our shareholders hold shares electronically, all of which are owned by a nominee of the Depository Trust Company. We had 63 shareholders of record on February 1, 2026.
Dividends
We have not paid or declared any dividends on our Common Shares. Our Indenture and the 2028 Credit Agreement include provisions that limit our ability to pay dividends. Further, in connection with certain provisions within the Business Combination Agreement, we are restricted in our ability to declare dividends until the transaction is completed or the agreement is terminated.
Bermuda Tax
We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermudian dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermudian dollars) in and out of Bermuda or to pay dividends to U.S. residents who are holders of our Common Shares.
On December 27, 2023, Bermuda enacted the Corporate Income Tax Act 2023 (the “CIT Act”), which became effective on January 1, 2025. The CIT Act imposes a tax on 15% of the net income of certain Bermuda constituent entities (as determined in accordance with the CIT Act, including after adjusting for any relevant foreign tax credits applicable to the Bermuda constituent entities). For years ended December 31, 2024 and prior, there was no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by us or by our shareholders in respect of our shares.
Equity Compensation Plans
For information on shares issued or to be issued in connection with our equity compensation plans, see "Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters."
Issuer Repurchases of Equity Securities
Our board of directors has authorized a share repurchase program (the "Share Repurchase Program") under which we may purchase up to $600.0 million of our outstanding Common Shares, subject to certain additional restrictions provided within the Business Combination Agreement. The Share Repurchase Program does not have a fixed expiration, may be modified, suspended or discontinued at any time and any repurchases made pursuant to the Share Repurchase Program are subject to compliance with applicable covenants and restrictions under our financing agreements.
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The following table provides a summary of our repurchases of our equity securities during the quarter ended December 31, 2025 (in millions, except average price per share):

Issuer Purchases of Equity Securities
Period |  | Total Number of Securities Purchased |  | Average Price Paid per Security |  | Total Number of Securities Purchased as Part of Publicly Announced Plans or Programs |  | Approximate Dollar Value of Securities that May Yet Be Purchased Under Plans or Programs
October 1 - October 31 |  | 0.2 |  |  | $ | 51.61 |  |  | 0.2 |  |  | $ | 190.7 |
November 1 - November 30 |  | 0.1 |  |  | $ | 55.58 |  |  | 0.1 |  |  | $ | 183.3 |
December 1 - December 31 |  | 0.2 |  |  | $ | 51.47 |  |  | 0.2 |  |  | $ | 175.0 |
Total |  | 0.5 |  |  | $ | 52.68 |  |  | 0.5 |  |  | $ | 175.0 |

Cumulative Total Shareholder Return
The chart below presents a comparison of the cumulative total shareholder return, assuming $100 invested on May 3, 2021 (first trading date after our emergence from bankruptcy) for Valaris Limited, the Standard & Poor's MidCap 400 Index and Dow Jones US Select Oil Equipment & Services Index (the "Industry Index").
COMPARISON OF CUMULATIVE TOTAL RETURN(1)
Among Valaris Limited, the S&P MidCap 400 Index and Industry Index
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| May 3, 2021 |  | Fiscal Years Ended December 31,
| Relisting |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | 2025
Valaris Limited | $ | 100.0 |  |  | $ | 151.9 |  |  | $ | 285.3 |  |  | $ | 289.3 |  |  | $ | 186.7 |  |  | $ | 212.7 |
S&P MidCap 400 | $ | 100.0 |  |  | $ | 104.6 |  |  | $ | 91.0 |  |  | $ | 105.9 |  |  | $ | 120.7 |  |  | $ | 129.7 |
Industry Index | $ | 100.0 |  |  | $ | 96.5 |  |  | $ | 160.7 |  |  | $ | 168.4 |  |  | $ | 155.1 |  |  | $ | 167.3 |

(1)Total return assuming reinvestment of dividends. Assumes $100 invested on May 3, 2021, which represents the first trading date after our emergence from bankruptcy.
Item 6. Reserved
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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.
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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.
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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.
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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) | $ | 3,030.8 |  |  | $ | 2,024.0 |
Jackups (2) | 1,125.8 |  |  | 1,313.0 |
Other (3) | 515.7 |  |  | 271.5 |
Total | $ | 4,672.3 |  |  | $ | 3,608.5 |
ARO (4) | $ | 2,011.3 |  |  | $ | 1,422.9 |

(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):

| 2026 |  | 2027 |  | 2028 and beyond |  |  |  | Total
Floaters | $ | 1,023.0 |  |  | $ | 1,268.7 |  |  | $ | 739.1 |  |  |  |  | $ | 3,030.8 |
Jackups | 520.0 |  |  | 430.1 |  |  | 175.7 |  |  |  |  | 1,125.8 |
Other | 160.5 |  |  | 109.1 |  |  | 246.1 |  |  |  |  | 515.7 |
Total | $ | 1,703.5 |  |  | $ | 1,807.9 |  |  | $ | 1,160.9 |  |  |  |  | $ | 4,672.3 |
ARO | $ | 414.8 |  |  | $ | 407.3 |  |  | $ | 1,189.2 |  |  |  |  | $ | 2,011.3 |

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.
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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.
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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
| 2025 |  | 2024 |  |
Operating revenues |  |  |  |  |  |  |
Revenues (exclusive of reimbursable revenues) | $ | 2,207.9 |  |  | $ | 2,211.9 |  |  | $ | (4.0) |  |  | — | %
Reimbursable revenues | 161.1 |  |  | 150.7 |  |  | 10.4 |  |  | 7 | %
Total operating revenues | 2,369.0 |  |  | 2,362.6 |  |  | 6.4 |  |  | — | %
Operating expenses |  |  |  |  |  |  |
Contract drilling expenses (exclusive of depreciation and reimbursable expenses) | 1,477.1 |  |  | 1,618.5 |  |  | (141.4) |  |  | (9) | %
Reimbursable expenses | 152.6 |  |  | 142.4 |  |  | 10.2 |  |  | 7 | %
Total contract drilling expenses (exclusive of depreciation) | 1,629.7 |  |  | 1,760.9 |  |  | (131.2) |  |  | (7) | %
Loss on impairment | 27.3 |  |  | — |  |  | 27.3 |  |  | NM
Depreciation | 146.3 |  |  | 122.1 |  |  | 24.2 |  |  | 20 | %
General and administrative | 97.1 |  |  | 116.3 |  |  | (19.2) |  |  | (17) | %
Total operating expenses | 1,900.4 |  |  | 1,999.3 |  |  | (98.9) |  |  | (5) | %
Equity in earnings (losses) of ARO | 8.4 |  |  | (11.0) |  |  | 19.4 |  |  | (176) | %
Operating income | 477.0 |  |  | 352.3 |  |  | 124.7 |  |  | 35 | %
Other income, net | 75.3 |  |  | 17.9 |  |  | 57.4 |  |  | 321 | %
Provision (benefit) for income taxes | (426.8) |  |  | 0.4 |  |  | (427.2) |  |  | NM
Net income | 979.1 |  |  | 369.8 |  |  | 609.3 |  |  | 165 | %
Net loss attributable to noncontrolling interests | 3.7 |  |  | 3.6 |  |  | 0.1 |  |  | 3 | %
Net income attributable to Valaris | $ | 982.8 |  |  | $ | 373.4 |  |  | $ | 609.4 |  |  | 163 | %

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.
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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.
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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:

| 2025 |  | 2024
Total Fleet |  |  |
Floaters(1) | 15 |  |  | 18 |
Jackups(2) | 24 |  |  | 28 |
Other(3) | 7 |  |  | 7 |
Total Valaris | 46 |  |  | 53 |
ARO(4) | 9 |  |  | 9 |
Active Fleet (5) |  |  |
Floaters(6) | 11 |  |  | 13 |
Jackups (7) | 17 |  |  | 18 |
Other (3) | 7 |  |  | 7 |
Active Fleet - Valaris | 35 |  |  | 38 |
ARO (4) | 9 |  |  | 9 |

(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.
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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,
|  | 2025 |  | 2024
Rig Utilization - Total Fleet (1) |  |  |  |
Floaters |  | 54 | % |  | 61 | %
Jackups |  | 61 | % |  | 58 | %
Other (2) |  | 97 | % |  | 100 | %
Total Valaris |  | 65 | % |  | 67 | %
ARO |  | 86 | % |  | 80 | %
Rig Utilization - Active Fleet (1) |  |  |  |
Floaters |  | 71 | % |  | 83 | %
Jackups |  | 93 | % |  | 83 | %
Other (2) |  | 97 | % |  | 100 | %
Total Valaris |  | 87 | % |  | 87 | %
ARO |  | 86 | % |  | 80 | %
Average Daily Revenue (3) |  |  |  |
Floaters |  | $ | 386,000 |  |  | $ | 345,000 |
Jackups |  | 138,000 |  |  | 121,000 |
Other (2) |  | 51,000 |  |  | 38,000 |
Total Valaris |  | $ | 179,000 |  |  | $ | 165,000 |
ARO |  | $ | 113,000 |  |  | $ | 104,000 |

(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.
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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) | $ | 1,224.1 |  |  | $ | 823.4 |  |  | $ | 571.0 |  |  | $ | 160.4 |  |  | $ | (571.0) |  |  | $ | 2,207.9 |
Reimbursable revenues | 36.5 |  |  | 89.4 |  |  | — |  |  | 35.2 |  |  | — |  |  | 161.1 |
Total operating revenues | 1,260.6 |  |  | 912.8 |  |  | 571.0 |  |  | 195.6 |  |  | (571.0) |  |  | 2,369.0 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |
Contract drilling expenses (exclusive of depreciation and reimbursable expenses) | 765.6 |  |  | 486.5 |  |  | 360.7 |  |  | 70.6 |  |  | (206.3) |  |  | 1,477.1 |
Reimbursable expenses | 34.3 |  |  | 83.5 |  |  | — |  |  | 34.8 |  |  | — |  |  | 152.6 |
Total contract drilling expenses (exclusive of depreciation) | 799.9 |  |  | 570.0 |  |  | 360.7 |  |  | 105.4 |  |  | (206.3) |  |  | 1,629.7 |
Loss on impairment | 23.6 |  |  | 3.7 |  |  | — |  |  | — |  |  | — |  |  | 27.3 |
Depreciation | 60.5 |  |  | 58.6 |  |  | 114.9 |  |  | 13.2 |  |  | (100.9) |  |  | 146.3 |
General and administrative | — |  |  | — |  |  | 28.8 |  |  | — |  |  | 68.3 |  |  | 97.1 |
Equity in earnings of ARO | — |  |  | — |  |  | — |  |  | — |  |  | 8.4 |  |  | 8.4 |
Operating income | $ | 376.6 |  |  | $ | 280.5 |  |  | $ | 66.6 |  |  | $ | 77.0 |  |  | $ | (323.7) |  |  | $ | 477.0 |

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Year Ended December 31, 2024

| Floaters |  | Jackups |  | ARO |  | Other |  | Reconciling Items |  | Consolidated Total
Operating revenues: |  |  |  |  |  |  |  |  |  |  |
Revenues (exclusive of reimbursable revenues) | $ | 1,382.8 |  |  | $ | 686.5 |  |  | $ | 512.5 |  |  | $ | 142.6 |  |  | $ | (512.5) |  |  | $ | 2,211.9 |
Reimbursable revenues | 57.9 |  |  | 68.4 |  |  | — |  |  | 24.4 |  |  | — |  |  | 150.7 |
Total operating revenues | 1,440.7 |  |  | 754.9 |  |  | 512.5 |  |  | 167.0 |  |  | (512.5) |  |  | 2,362.6 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |
Contract drilling expenses (exclusive of depreciation and reimbursable expenses) | 930.3 |  |  | 477.1 |  |  | 367.7 |  |  | 63.6 |  |  | (220.2) |  |  | 1,618.5 |
Reimbursable expenses | 54.9 |  |  | 64.3 |  |  | — |  |  | 23.2 |  |  | — |  |  | 142.4 |
Total contract drilling expenses (exclusive of depreciation) | 985.2 |  |  | 541.4 |  |  | 367.7 |  |  | 86.8 |  |  | (220.2) |  |  | 1,760.9 |
Loss on impairment | — |  |  | — |  |  | 28.4 |  |  | — |  |  | (28.4) |  |  | — |
Depreciation | 58.1 |  |  | 45.0 |  |  | 89.2 |  |  | 9.5 |  |  | (79.7) |  |  | 122.1 |
General and administrative | — |  |  | — |  |  | 23.7 |  |  | — |  |  | 92.6 |  |  | 116.3 |
Equity in losses of ARO | — |  |  | — |  |  | — |  |  | — |  |  | (11.0) |  |  | (11.0) |
Operating income | $ | 397.4 |  |  | $ | 168.5 |  |  | $ | 3.5 |  |  | $ | 70.7 |  |  | $ | (287.8) |  |  | $ | 352.3 |

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.
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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.
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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,
| 2025 |  | 2024
Net gain (loss) on sale of property | $ | 118.6 |  |  | $ | (0.2) |
Interest expense, net | (98.8) |  |  | (84.8) |
Interest income | 70.8 |  |  | 86.1 |
Net foreign currency exchange gains (losses) | (14.3) |  |  | 13.8 |
Net periodic pension and retiree medical income (loss) | (0.9) |  |  | 2.4 |
Other, net | (0.1) |  |  | 0.6 |
| $ | 75.3 |  |  | $ | 17.9 |

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.
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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.
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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,
| 2025 |  | 2024
Net cash provided by operating activities | $ | 546.2 |  |  | $ | 355.4 |
Capital expenditures | $ | (343.5) |  |  | $ | (455.1) |

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.
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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.
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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 |  | $ | 0.5 |  |  |  |  | $ | (3.7) |
VALARIS 247 |  | August 2025 |  |  |  | Jackups |  | 103.9 |  |  |  |  | 88.4 |
Retired Semis (3) |  | April 2025 |  |  |  | Floaters |  | 7.8 |  |  |  |  | (7.8) |
VALARIS 75 (4) |  | January 2025 |  |  |  | Jackups |  | 23.8 |  |  |  |  | 23.0 |
|  |  |  |  |  |  |  | $ | 136.0 |  |  |  |  | $ | 99.9 |

(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.
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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 | $ | 227.3 |
October 2028 | 173.4 |
Total | $ | 400.7 |

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
| 2026 |  | 2027 and 2028 |  | 2029 and 2030 |  | Thereafter |  | Total
Principal payments on long-term debt | $ | — |  |  | $ | — |  |  | $ | 1,100.0 |  |  | $ | — |  |  | $ | 1,100.0 |
Interest payments on long-term debt | 92.1 |  |  | 184.3 |  |  | 138.2 |  |  | — |  |  | 414.6 |
Operating leases | 39.8 |  |  | 33.7 |  |  | 6.2 |  |  | 0.4 |  |  | 80.1 |
Total contractual obligations(1) | $ | 131.9 |  |  | $ | 218.0 |  |  | $ | 1,244.4 |  |  | $ | 0.4 |  |  | $ | 1,594.7 |

(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.
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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
| 2026 |  | 2027 and 2028 |  | 2029 and 2030 |  | Thereafter |  | Total
Letters of credit | $ | 5.1 |  |  | $ | 25.3 |  |  | $ | 5.0 |  |  | $ | — |  |  | $ | 35.4 |

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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,
| 2025 |  | 2024 |  | 2023 |  |
Shares repurchased | 2.0 |  |  | 2.2 |  |  | 3.0 |  |  |
Total aggregate cost | $ | 100.0 |  |  | $ | 125.0 |  |  | $ | 200.0 |  |  |
Average per share price | $ | 49.78 |  |  | $ | 56.11 |  |  | $ | 66.77 |  |  |

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.
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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.
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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.
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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.
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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.
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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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Information required under this Item 7A. has been incorporated herein from "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."
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Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2025 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, has issued an audit report on our internal control over financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.
February 20, 2026
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Valaris Limited:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Valaris Limited and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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Income tax positions pertaining to certain tax transactions
As discussed in Notes 1 and 10 to the consolidated financial statements, the Company evaluated the income tax effect of certain transactions which often requires local country tax expertise and judgment. This requires the Company to interpret complex tax laws in multiple jurisdictions to assess whether its tax positions have a more than 50 percent likelihood of being sustained with the taxing authorities.
We identified the assessment of income tax positions pertaining to certain tax transactions as a critical audit matter. Complex auditor judgment was required to evaluate the Company’s assessment that certain tax positions have a more than 50 percent likelihood of being sustained with the taxing authorities. In addition, specialized skills and knowledge were required to evaluate the Company’s interpretation of tax laws in the applicable jurisdictions.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s income tax process. This included controls related to the interpretation of tax laws applicable to certain transactions and the assessment that tax positions pertaining to those transactions have a more than 50 percent likelihood of being sustained with taxing authorities. We involved tax professionals with specialized skills and knowledge, who assisted on evaluating the Company’s interpretation of local tax laws and assessment of whether tax positions had a greater than 50 percent likelihood of being sustained with taxing authorities.
/s/ KPMG LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 20, 2026
78

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Valaris Limited:
Opinion on Internal Control Over Financial Reporting
We have audited Valaris Limited and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 20, 2026 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Houston, Texas
February 20, 2026
80

VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
OPERATING REVENUES |  |  |  |  |
Revenues (exclusive of reimbursable revenues) | $ | 2,207.9 |  |  | $ | 2,211.9 |  |  | $ | 1,676.0 |
Reimbursable revenues | 161.1 |  |  | 150.7 |  |  | 108.2 |
Total operating revenues | 2,369.0 |  |  | 2,362.6 |  |  | 1,784.2 |
OPERATING EXPENSES |  |  |  |  |
Contract drilling expenses (exclusive of depreciation and reimbursable expenses) | 1,477.1 |  |  | 1,618.5 |  |  | 1,440.4 |
Reimbursable expenses | 152.6 |  |  | 142.4 |  |  | 103.2 |
Total contract drilling expenses (exclusive of depreciation) | 1,629.7 |  |  | 1,760.9 |  |  | 1,543.6 |
Loss on impairment | 27.3 |  |  | — |  |  | — |
Depreciation | 146.3 |  |  | 122.1 |  |  | 101.1 |
General and administrative | 97.1 |  |  | 116.3 |  |  | 99.3 |
Total operating expenses | 1,900.4 |  |  | 1,999.3 |  |  | 1,744.0 |
EQUITY IN EARNINGS (LOSSES) OF ARO | 8.4 |  |  | (11.0) |  |  | 13.3 |
OPERATING INCOME | 477.0 |  |  | 352.3 |  |  | 53.5 |
OTHER INCOME (EXPENSE) |  |  |  |  |
Interest income | 70.8 |  |  | 86.1 |  |  | 101.4 |
Interest expense, net | (98.8) |  |  | (84.8) |  |  | (68.9) |
Other, net | 103.3 |  |  | 16.6 |  |  | (1.8) |
Total other income | 75.3 |  |  | 17.9 |  |  | 30.7 |
INCOME BEFORE INCOME TAXES | 552.3 |  |  | 370.2 |  |  | 84.2 |
PROVISION (BENEFIT) FOR INCOME TAXES |  |  |  |  |
Current income tax expense (benefit) | 88.3 |  |  | (5.4) |  |  | 3.8 |
Deferred income tax expense (benefit) | (515.1) |  |  | 5.8 |  |  | (786.4) |
Total provision (benefit) for income taxes | (426.8) |  |  | 0.4 |  |  | (782.6) |
NET INCOME | 979.1 |  |  | 369.8 |  |  | 866.8 |
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | 3.7 |  |  | 3.6 |  |  | (1.4) |
NET INCOME ATTRIBUTABLE TO VALARIS | $ | 982.8 |  |  | $ | 373.4 |  |  | $ | 865.4 |
EARNINGS PER SHARE |  |  |  |  |
Basic | $ | 13.92 |  |  | $ | 5.18 |  |  | $ | 11.68 |
Diluted | $ | 13.86 |  |  | $ | 5.12 |  |  | $ | 11.51 |
WEIGHTED-AVERAGE SHARES OUTSTANDING |  |  |  |  |
Basic | 70.6 |  |  | 72.1 |  |  | 74.1 |
Diluted | 70.9 |  |  | 72.9 |  |  | 75.2 |

The accompanying notes are an integral part of these consolidated financial statements.
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VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
NET INCOME | $ | 979.1 |  |  | $ | 369.8 |  |  | $ | 866.8 |
OTHER COMPREHENSIVE INCOME, NET |  |  |  |  |
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income | 24.5 |  |  | 10.9 |  |  | 10.8 |
Foreign currency translation adjustments | 2.2 |  |  | (1.9) |  |  | (0.3) |
NET OTHER COMPREHENSIVE INCOME | 26.7 |  |  | 9.0 |  |  | 10.5 |
COMPREHENSIVE INCOME | 1,005.8 |  |  | 378.8 |  |  | 877.3 |
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | 3.7 |  |  | 3.6 |  |  | (1.4) |
COMPREHENSIVE INCOME ATTRIBUTABLE TO VALARIS | $ | 1,009.5 |  |  | $ | 382.4 |  |  | $ | 875.9 |

The accompanying notes are an integral part of these consolidated financial statements.
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VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except par value amounts)

| December 31,
ASSETS | 2025 |  |  | 2024
CURRENT ASSETS |  |  |  |
Cash and cash equivalents | $ | 599.4 |  |  |  | $ | 368.2 |
Accounts receivable, net | 474.8 |  |  |  | 571.2 |
Assets held for sale | 6.4 |  |  |  | — |
Other current assets | 144.7 |  |  |  | 139.3 |
Total current assets | 1,225.3 |  |  |  | 1,078.7 |
PROPERTY AND EQUIPMENT, AT COST | 2,598.3 |  |  |  | 2,309.4 |
Less accumulated depreciation | 509.5 |  |  |  | 376.5 |
Property and equipment, net | 2,088.8 |  |  |  | 1,932.9 |
LONG-TERM NOTES RECEIVABLE FROM ARO | 345.0 |  |  |  | 296.2 |
INVESTMENT IN ARO | 121.8 |  |  |  | 113.4 |
DEFERRED TAX ASSETS | 1,364.2 |  |  |  | 849.5 |
OTHER ASSETS | 159.7 |  |  |  | 149.1 |
Total assets | $ | 5,304.8 |  |  |  | $ | 4,419.8 |
LIABILITIES AND SHAREHOLDERS' EQUITY |  |  |  |
CURRENT LIABILITIES |  |  |  |
Accounts payable - trade | $ | 348.2 |  |  |  | $ | 328.5 |
Accrued liabilities and other | 343.4 |  |  |  | 351.0 |
Total current liabilities | 691.6 |  |  |  | 679.5 |
LONG-TERM DEBT | 1,086.0 |  |  |  | 1,082.7 |
DEFERRED TAX LIABILITIES | 29.7 |  |  |  | 30.1 |
OTHER LIABILITIES | 325.8 |  |  |  | 383.2 |
Total liabilities | 2,133.1 |  |  |  | 2,175.5 |
COMMITMENTS AND CONTINGENCIES (Note 11) |  |  |  |
VALARIS SHAREHOLDERS' EQUITY |  |  |  |
Common shares, $0.01 par value, 700.0 shares authorized, 76.4 and 76.2 shares issued, 69.2 and 71.0 shares outstanding as of December 31, 2025 and 2024 respectively | 0.8 |  |  |  | 0.8 |
Preference shares, $0.01 par value, 150.0 shares authorized, no shares issued as of December 31, 2025 and 2024 | — |  |  |  | — |
Stock warrants | 16.4 |  |  |  | 16.4 |
Additional paid-in capital | 1,134.9 |  |  |  | 1,113.3 |
Retained earnings | 2,381.7 |  |  |  | 1,398.9 |
Accumulated other comprehensive income | 60.9 |  |  |  | 34.2 |
Treasury shares, at cost, 7.2 and 5.2 shares as of December 31, 2025 and 2024, respectively | (425.1) |  |  |  | (325.1) |
Total Valaris shareholders' equity | 3,169.6 |  |  |  | 2,238.5 |
NONCONTROLLING INTERESTS | 2.1 |  |  |  | 5.8 |
Total shareholders' equity | 3,171.7 |  |  |  | 2,244.3 |
Total liabilities and shareholders' equity | $ | 5,304.8 |  |  |  | $ | 4,419.8 |

The accompanying notes are an integral part of these consolidated financial statements.
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VALARIS LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
OPERATING ACTIVITIES |  |  |  |  |
Net income | $ | 979.1 |  |  | $ | 369.8 |  |  | $ | 866.8 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |
Deferred income tax expense (benefit) | (515.1) |  |  | 5.8 |  |  | (786.4) |
Depreciation expense | 146.3 |  |  | 122.1 |  |  | 101.1 |
Net (gain) loss on sale of property | (118.6) |  |  | 0.2 |  |  | (28.6) |
Loss on impairment | 27.3 |  |  | — |  |  | — |
Share-based compensation expense | 25.2 |  |  | 27.7 |  |  | 27.3 |
Accretion of discount on the Notes Receivable from ARO | (24.7) |  |  | (40.0) |  |  | (28.3) |
Equity in losses (earnings) of ARO | (8.4) |  |  | 11.0 |  |  | (13.3) |
Loss on extinguishment of debt | — |  |  | — |  |  | 29.2 |
Changes in contract liabilities | (41.0) |  |  | (31.7) |  |  | 4.9 |
Changes in deferred costs | 16.1 |  |  | 39.3 |  |  | (26.1) |
Changes in contract assets | (10.3) |  |  | (1.0) |  |  | 0.6 |
Other | 8.0 |  |  | 6.9 |  |  | 5.8 |
Changes in operating assets and liabilities | 78.9 |  |  | (133.2) |  |  | 121.2 |
Contributions to pension plans and other post-retirement benefits | (16.6) |  |  | (21.5) |  |  | (6.7) |
Net cash provided by operating activities | 546.2 |  |  | 355.4 |  |  | 267.5 |
INVESTING ACTIVITIES |  |  |  |  |
Additions to property and equipment | (343.5) |  |  | (455.1) |  |  | (696.1) |
Proceeds from disposition of assets | 137.9 |  |  | 2.8 |  |  | 30.3 |
Net cash used in investing activities | (205.6) |  |  | (452.3) |  |  | (665.8) |
FINANCING ACTIVITIES |  |  |  |  |
Payments for share repurchases | (100.0) |  |  | (126.4) |  |  | (198.6) |
Payments related to tax withholdings for share-based awards | (3.6) |  |  | (29.9) |  |  | (5.4) |
Debt issuance costs | — |  |  | (0.8) |  |  | (38.6) |
Issuance of 2030 Second Lien Notes | — |  |  | — |  |  | 1,103.0 |
Redemption of 2028 First Lien Notes | — |  |  | — |  |  | (571.8) |
Other | — |  |  | (1.2) |  |  | (3.1) |
Net cash provided by (used in) financing activities | (103.6) |  |  | (158.3) |  |  | 285.5 |
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS AND RESTRICTED CASH | 237.0 |  |  | (255.2) |  |  | (112.8) |
CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, BEGINNING OF PERIOD | 380.5 |  |  | 635.7 |  |  | 748.5 |
CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, END OF PERIOD | $ | 617.5 |  |  | $ | 380.5 |  |  | $ | 635.7 |

The accompanying notes are an integral part of these consolidated financial statements.
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VALARIS LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF THE BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
References to the “Company,” “we,” “us” or “our” in this Annual Report are to Valaris Limited, together with its consolidated subsidiaries.
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 Saudi Aramco Rowan Offshore Drilling Company ("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.
Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Valaris Limited, those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. All intercompany accounts and transactions have been eliminated. Investments in operating entities in which we have the ability to exercise significant influence, but where we do not control operating and financial policies, are accounted for using the equity method. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. We account for our interest in ARO using the equity method of accounting and only recognize our portion of equity in earnings in our consolidated financial statements. ARO is a variable interest entity; however, we are not the primary beneficiary and therefore do not consolidate ARO.
Reclassification
Certain previously reported amounts have been reclassified to conform to the current year presentation.
Pervasiveness of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States ("U.S. GAAP") requires us to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.
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Foreign Currency Remeasurement and Translation
Our functional currency is the United States (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. These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Most transaction gains and losses are included in Other, net, in our Consolidated Statements of Operations. Certain gains and losses from the translation of foreign currency balances of our non-U.S. dollar functional currency subsidiaries are included in Accumulated other comprehensive income on our Consolidated Balance Sheets. Net foreign currency exchange gains and losses were $14.3 million of losses, $13.8 million of gains and $3.5 million of losses, and were included in Other, net, in our Consolidated Statements of Operations for the years ended December 31, 2025, 2024 and 2023, respectively.
Cash Equivalents
Highly liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. To mitigate our credit risk, our investments in time deposits have historically been diversified across multiple, high-quality financial institutions.
Restricted Cash
Our restricted cash primarily consists of collateral on letters of credit. We classify restricted cash balances on the Consolidated Balance Sheets within Other current assets, if the restriction is expected to expire or otherwise be resolved within one year, and in Other assets, if the restriction is expected to expire or otherwise be resolved in more than one year. See "Note 14 - Supplemental Financial Information" for additional information on our restricted cash balances and "Note 11 - Commitments and Contingencies" for more information regarding our letters of credit.
Property and Equipment
All costs incurred in connection with the acquisition, construction, major enhancement and improvement of assets are capitalized, including allocations of interest incurred during periods that our drilling rigs are under construction or undergoing major enhancements and improvements. Costs incurred to place an asset into service are capitalized, including costs related to the initial mobilization of a newbuild drilling rig. Repair and maintenance costs are charged to contract drilling expenses in the period in which they are incurred. Upon the sale or retirement of assets, the related cost and accumulated depreciation are removed from the balance sheet, and the resulting gain or loss is included in Other, net in our Consolidated Statements of Operations.
We have identified the significant components of our drilling rigs and ascribe useful lives based on the expected time until the next required overhaul or the end of the expected economic lives of the components.
Our property and equipment is depreciated on a straight-line basis, after allowing for salvage values, over the estimated useful lives of our assets. Drilling rigs and related equipment are depreciated over estimated useful lives ranging from three to 35 years. Buildings and improvements are depreciated over estimated useful lives ranging from 10 to 30 years. Leasehold improvements are depreciated over the lesser of the asset useful life or lease term. Other equipment, including computer and communications hardware and software, is depreciated over estimated useful lives ranging from two to six years.
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We evaluate the carrying value of our property and equipment, primarily our drilling rigs, on a quarterly basis to identify events or changes in circumstances ("triggering events") that indicate that the carrying value of such rigs may not be recoverable. For property and equipment used in our operations, recoverability generally is determined by comparing the carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the carrying value of the asset and its estimated fair value. Property and equipment classified as held for sale is recorded at the lower of its net book value or fair value less the estimated cost to sell.
We recorded pre-tax, non-cash impairment losses related to long-lived assets of $27.3 million in the year ended December 31, 2025. See "Note 5 - Property and Equipment" for additional information on our impairment charges.
Operating Revenues and Expenses
See "Note 2 - Revenue from Contracts with Customers" for information on our accounting policies for revenue recognition and certain operating costs that are deferred and amortized over future periods.
Income Taxes
We conduct operations and earn income in numerous countries. Current income taxes are recognized for the amount of taxes payable or refundable based on the laws and income tax rates in the taxing jurisdictions in which operations are conducted and income is earned.
Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year-end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.
We operate in certain jurisdictions where tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, we may enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and assets we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns. Our tax positions are evaluated for recognition as unrecognized tax benefits using a more-likely-than-not threshold, and those 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. Interest and penalties relating to income taxes are included in Current income tax expense in our Consolidated Statements of Operations.
Our drilling rigs frequently move from one taxing jurisdiction to another based on where they are contracted to perform drilling services. The movement of drilling rigs among taxing jurisdictions may involve a transfer of drilling rig ownership among our subsidiaries through an intercompany rig sale. The pre-tax profit resulting from an intercompany rig sale is eliminated from our consolidated financial statements, and the carrying value of a rig sold in an intercompany transaction remains at the historical net depreciated cost prior to the transaction. Our consolidated financial statements do not reflect the asset disposition transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary. The income tax effects resulting from intercompany rig sales are recognized in earnings in the period in which the sale occurs.
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In some instances, we may determine that certain temporary differences will not result in a taxable or deductible amount in future years, as it is more-likely-than-not we will commence operations and depart from a given taxing jurisdiction without such temporary differences being recovered or settled. Under these circumstances, no future tax consequences are expected and no deferred taxes are recognized in connection with such operations. We evaluate these determinations on a periodic basis and, in the event our expectations relative to future tax consequences change, the applicable deferred taxes are recognized or derecognized.
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.
See "Note 10 - Income Taxes" for additional information on our income taxes.
Share-Based Compensation
We sponsor share-based compensation plans that provide equity compensation to our key employees, officers and non-employee directors. Our 2021 Management Incentive Plan (the “MIP”) allows our board of directors to authorize equity-based grants to be settled in cash, shares or a combination of shares and cash. Compensation expense for time-based equity awards to be settled in shares is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period).
Compensation expense for performance awards is recognized over the requisite service period using the accelerated method and is reduced for forfeited awards in the period in which the forfeitures occur. For our performance awards that cliff vest and require the employee to render service through the vesting date, even though attainment of performance objectives might be earlier, our expense under the accelerated method would be a ratable expense over the vesting period. Equity-settled performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. The estimated probable outcome of attainment of the specified performance goals is based primarily on relative performance over the requisite performance period. Any subsequent changes in this estimate as it relates to performance objectives are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs, except in the case of objectives based on a market condition, such as our stock price. Compensation cost for awards based on a market performance objective is recognized as long as the requisite service period is completed and will not be reversed even if the market-based objective is never satisfied. Any adjustments to the compensation cost recognized in our Consolidated Statements of Operations for awards that are forfeited are recognized in the period in which the forfeitures occur. See "Note 8 - Share Based Compensation" for additional information on our share-based compensation.
Pension and Other Post-retirement Benefit Plans
We measure our actuarially determined obligations and related costs for our defined benefit pension and other post-retirement plans, retiree life and medical supplemental plan benefits by applying assumptions, the most significant of which include long-term rate of return on plan assets, discount rates and mortality rates. For the long-term rate of return, we develop our assumptions regarding the expected rate of return on plan assets based on historical experience and projected long-term investment returns, and we weight the assumptions based on each plan's asset allocation. For the discount rate, we base our assumptions on a yield curve approach. Actual results may differ from the assumptions included in these calculations. If actuarial gains or losses exceed 10% of the greater of the plan assets or plan liabilities, we amortize such gains or losses into income over either the period of expected future service of active participants, or over the expected average remaining lifetime of all participants. We recognize gains or losses related to plan curtailments at the date the plan amendment or termination is adopted which may precede the effective date. See "Note 9 - Pension and Other Post-retirement Benefits" for additional information on our defined benefit pension and other post-retirement plans.
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Fair Value Measurements
We measure certain of our assets and liabilities based on a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1") and the lowest priority to unobservable inputs ("Level 3"). Level 2 measurements represent inputs that are observable for similar assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. See "Note 4 - Fair Value Measurements" for additional information on the fair value measurement of certain of our assets and liabilities.
Noncontrolling Interests
Third parties hold a noncontrolling ownership interest in certain of our non-U.S. subsidiaries. Noncontrolling interests are classified as equity on our Consolidated Balance Sheets, and net income attributable to noncontrolling interests is presented separately in our Consolidated Statements of Operations. All income attributable to noncontrolling interest was from continuing operations.
Earnings Per Share
Basic earnings per share is computed by dividing net income available to common shareholders by the weighted-average number of common shares of Valaris Limited (the "Common Shares") outstanding during the period. Weighted-average shares outstanding used in our computation of diluted EPS is calculated using the treasury stock method, which includes the effect of all potentially dilutive stock equivalents, including warrants, restricted stock unit awards and performance stock unit awards.
The following table is a reconciliation of the weighted-average shares used in our basic and diluted EPS computations for the years ended December 31, 2025, 2024 and 2023 (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Income attributable to our shares | $ | 982.8 |  |  | $ | 373.4 |  |  | $ | 865.4 |
Weighted average shares outstanding: |  |  |  |  |
Basic | 70.6 |  |  | 72.1 |  |  | 74.1 |
Effect of stock equivalents | 0.3 |  |  | 0.8 |  |  | 1.1 |
Diluted | 70.9 |  |  | 72.9 |  |  | 75.2 |
EARNINGS PER SHARE |  |  |  |  |
Basic | $ | 13.92 |  |  | $ | 5.18 |  |  | $ | 11.68 |
Diluted | $ | 13.86 |  |  | $ | 5.12 |  |  | $ | 11.51 |

Anti-dilutive share awards totaling 217,000, 160,000 and 147,000 were excluded from the computation of diluted EPS for the years ended December 31, 2025, 2024 and 2023, respectively.
We have 5,470,801 warrants outstanding (the "Warrants") as of December 31, 2025 which are exercisable for one Common Share per Warrant at an initial exercise price of $131.88 per Warrant, in each case as may be adjusted from time to time pursuant to the applicable warrant agreement. The Warrants expire on April 29, 2028. The exercise of these Warrants into Common Shares would have a dilutive effect to the holdings of Valaris Limited's existing shareholders. These Warrants are anti-dilutive for all periods presented above.
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New Accounting Pronouncements
Recently adopted accounting pronouncements
Improvements to Income Tax Disclosures - In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("Update 2023-09"), which expands income tax disclosure requirements to include additional information related to the rate reconciliation of our effective tax rates to statutory rates as well as additional disaggregation of taxes paid. The amendments in Update 2023-09 also remove disclosures related to certain unrecognized tax benefits and deferred taxes. Update 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The amendments are required to be applied on a prospective basis, with an option to apply the guidance retrospectively. We adopted Update 2023-09 effective for this annual report for the year ended December 31, 2025 on a prospective basis. See "Note 10 - Income Taxes" for expanded disclosures around our income tax information.
Measurement of Credit Losses for Accounts Receivable and Contract Assets - In July 2025, the FASB issued ASU No. 2025-05, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets ("Update 2025-05"), which allows public business entities to elect a practical expedient for current accounts receivables and contract assets to assume that current conditions as of the balance sheet date do not change for the remaining life of the asset. Update 2025-05 is effective for fiscal years beginning after December 15, 2025, with early adoption permitted, and is required to be applied on a prospective basis. We have elected the practical expedient as allowed by Update 2025-05 effective January 1, 2026 and it has not had, nor is it expected to have, a material impact on the recognition or measurement of our credit losses within our condensed consolidated financial statements.
Accounting pronouncements to be adopted
Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures - In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses ("Update 2024-03"), which requires companies to disclose additional information for certain relevant expense categories in the Statements of Operations and within the notes to the financial statements. Update 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted and can be applied either prospectively to financial statements issued for reporting periods after the effective date, or retrospectively to prior periods which are presented in the financial statements. We are currently assessing the impact of the requirements on our consolidated financial statements and disclosures.
With the exception of the updated standards discussed above, there have been no accounting pronouncements issued and not yet effective that have significance, or potential significance, to our consolidated financial statements.
2. REVENUE FROM CONTRACTS WITH CUSTOMERS
Under our drilling contracts with customers, we provide a drilling rig and drilling services, including rig crews, on a day rate contract basis. 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 generally 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.
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Our drilling contracts contain a lease component and we have elected to apply the practical expedient provided under Accounting Standards Codification ("ASC") 842 to not separate the lease and non-lease components and apply the revenue recognition guidance in ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)." The drilling services provided under each drilling contract is a single performance obligation satisfied over time and is comprised of a series of distinct time increments, or service periods. Total revenue is determined for each individual drilling contract by estimating both fixed and variable consideration expected to be earned over the contract term. Fixed consideration generally relates to activities such as mobilization, demobilization and capital upgrades of our rigs that are not distinct performance obligations within the context of our contracts and is recognized on a straight-line basis over the contract term. Variable consideration generally relates to distinct service periods during the contract term and is recognized in the period when the services are performed. The amount estimated for variable consideration is only recognized as revenue to the extent that it is probable that a significant reversal will not occur during the contract term. We have applied the optional exemption afforded in ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)," and have not disclosed the variable consideration related to our estimated future day rate revenues.
The term of our drilling contracts is typically defined by either a specified period of time or the completion of a specified number of wells. The remaining duration of our drilling contracts based on those in place as of December 31, 2025 was between approximately 1 month and 5 years.
Day Rate Drilling Revenue
Our drilling contracts provide for payment on a day rate basis and include a rate schedule with higher rates for periods when the drilling rig is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The day rate invoiced to the customer is determined based on the varying rates applicable to specific activities performed on an hourly or other time increment basis. Day rate consideration is allocated to the distinct hourly or other time increment to which it relates within the contract term and is generally recognized consistent with the contractual rate invoiced for the services provided during the respective period. Invoices are typically issued to our customers on a monthly basis and payment terms on customer invoices are typically 30 days.
Certain of our contracts contain performance incentives whereby we may earn a bonus based on pre-established performance criteria. Such incentives are generally based on our performance over individual monthly time periods or individual wells. Consideration related to a performance bonus is generally recognized in the specific time period to which the performance criteria was attributed.
We may receive termination fees if certain drilling contracts are terminated by the customer prior to the end of the contractual term. Such compensation is recognized as revenue when our performance obligation is satisfied, the termination fee can be reasonably measured and collection is probable.
Mobilization / Demobilization Revenue
In connection with certain contracts, we receive lump-sum fees or similar compensation for the mobilization of equipment and personnel prior to the commencement of drilling services or the demobilization of equipment and personnel upon contract completion. Fees received for the mobilization or demobilization of equipment and personnel are included in Operating revenues. The costs incurred in connection with the mobilization and demobilization of equipment and personnel are included in Contract drilling expenses.
Mobilization fees received prior to commencement of drilling operations are recorded as a contract liability and amortized on a straight-line basis over the contract term. Demobilization fees expected to be received upon contract completion are estimated at contract inception and recognized on a straight-line basis over the contract term. In some cases, demobilization fees may be contingent upon the occurrence or non-occurrence of a future event. In such cases, this may result in cumulative-effect adjustments to demobilization revenues upon changes in our estimates of future events during the contract term.
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Capital Upgrade / Contract Preparation Revenue
In connection with certain contracts, we receive lump-sum fees or similar compensation generally for requested capital upgrades to our drilling rigs or for other contract preparation work. Fees received for requested capital upgrades and other contract preparation work are recorded as a contract liability and amortized on a straight-line basis over the contract term to Operating revenues.
Revenues Related to Reimbursable Expenses
We generally receive reimbursements from our customers for purchases of supplies, equipment, personnel services and other services provided at their request. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is recognized during the period in which the corresponding goods and services are consumed once the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer within Operating revenues.
Contract Assets and Liabilities
Contract assets represent amounts recognized as revenue but for which the right to invoice the customer is dependent upon our future performance. Once the previously recognized revenue is invoiced, the corresponding contract asset, or a portion thereof, is transferred to accounts receivable.
Contract liabilities generally represent fees received for mobilization, capital upgrades or in the case of our 50/50 unconsolidated joint venture with Saudi Aramco, represent the difference between the amounts billed under the bareboat charter arrangements and lease revenues earned. See “Note 3 – Equity Method Investment in ARO" for additional details regarding our balances with ARO.
Contract assets and liabilities are presented net on our Consolidated Balance Sheets on a contract-by-contract basis. Current contract assets and liabilities are included in Other current assets and Accrued liabilities and other, respectively, and noncurrent contract assets and liabilities are included in Other assets and Other liabilities, respectively, on our Consolidated Balance Sheets.
The following table summarizes our contract assets and contract liabilities (in millions):

| December 31,
| 2025 |  | 2024
Current contract assets | $ | 4.3 |  |  | $ | 1.3 |
Noncurrent contract assets | $ | 12.8 |  |  | $ | 5.5 |
Current contract liabilities (deferred revenue) | $ | 87.7 |  |  | $ | 87.2 |
Noncurrent contract liabilities (deferred revenue) | $ | 63.2 |  |  | $ | 71.4 |

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Changes in contract assets and liabilities during the period are as follows (in millions):

| Contract Assets |  | Contract Liabilities
Balance as of December 31, 2023 | $ | 6.0 |  |  | $ | 153.8 |
Revenue recognized in advance of right to bill customer | 9.6 |  |  | — |
Increase due to revenue deferred during the period | — |  |  | 213.8 |
Decrease due to amortization of deferred revenue that was included in the beginning contract liability balance | — |  |  | (104.1) |
Decrease due to amortization of deferred revenue that was added during the period | — |  |  | (77.2) |
Decrease due to transfer to receivables and payables during the period | (8.8) |  |  | (27.7) |
Balance as of December 31, 2024 | $ | 6.8 |  |  | $ | 158.6 |
Revenue recognized in advance of right to bill customer | 11.9 |  |  | — |
Increase due to revenue deferred during the period | — |  |  | 107.7 |
Decrease due to amortization of deferred revenue that was included in the beginning contract liability balance | — |  |  | (81.1) |
Decrease due to amortization of deferred revenue that was added during the period | — |  |  | (26.1) |
Decrease due to transfer to receivables and payables during the period | (1.6) |  |  | (8.2) |
Balance as of December 31, 2025 | $ | 17.1 |  |  | $ | 150.9 |

Deferred Contract Costs
Costs incurred for upfront rig mobilizations and certain contract preparations are attributable to our future performance obligation under each respective drilling contract. These costs are deferred and amortized on a straight-line basis over the contract term. Demobilization costs are recognized as incurred upon contract completion. Costs associated with the mobilization of equipment and personnel unrelated to contracts are expensed as incurred. Deferred contract costs are included in Other current assets and Other assets on our Consolidated Balance Sheets and totaled $36.6 million and $47.4 million as of December 31, 2025 and 2024, respectively. During the years ended December 31, 2025, 2024 and 2023, amortization of such costs totaled $39.6 million, $108.4 million and $92.9 million, respectively.
Deferred Certification Costs
We must obtain certifications from various regulatory bodies in order to operate our drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs incurred in connection with maintaining such certifications, including inspections, tests, surveys and drydock, and other compliance costs, are deferred and amortized on a straight-line basis over the corresponding certification periods. Deferred regulatory certification and compliance costs are included in Other current assets and Other assets on our Consolidated Balance Sheets and totaled $7.6 million and $12.9 million as of December 31, 2025 and 2024, respectively. During the years ended December 31, 2025, 2024 and 2023, amortization of such costs totaled $8.5 million, $10.1 million and $12.7 million, respectively.
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Future Amortization of Contract Liabilities and Deferred Costs
Our contract liabilities and deferred costs are amortized on a straight-line basis over the contract term or corresponding certification period to Operating revenues and Contract drilling expenses, respectively, with the exception of the contract liabilities related to our bareboat charter arrangements with ARO which would not be contractually payable until the end of the lease term or termination, if sooner. See "Note 3 - Equity Method Investment in ARO" for additional information on ARO and related arrangements. The table below reflects the expected future amortization of our contract liabilities and deferred costs recorded as of December 31, 2025. In the case of our contract liabilities related to our bareboat charter arrangements with ARO, the contract liability is not amortized and as such, the amount is reflected in the table below at the end of the current lease term.

| (In millions)
| 2026 |  | 2027 |  | 2028 |  | 2029 & Thereafter |  |  | Total
Amortization of contract liabilities | $ | 87.7 |  |  | $ | 39.5 |  |  | $ | 8.1 |  |  | $ | 15.6 |  |  |  | $ | 150.9 |
Amortization of deferred costs | $ | 37.7 |  |  | $ | 6.3 |  |  | $ | 0.2 |  |  | $ | — |  |  |  | $ | 44.2 |

3. EQUITY METHOD INVESTMENT IN ARO
Background
ARO is a 50/50 unconsolidated joint venture between the Company and Saudi Aramco that owns and operates jackup drilling rigs in Saudi Arabia. As of December 31, 2025, ARO owned nine jackup rigs, had ordered two newbuild jackup rigs and leased seven rigs from us through bareboat charter arrangements (the "Lease Agreements") whereby substantially all operating costs are incurred by ARO. At December 31, 2025, the leased rigs were under long-term drilling contracts, or related extensions, with Saudi Aramco. The nine rigs owned by ARO are currently operating under contracts with Saudi Aramco, each with a minimum aggregate contract term of 15 years, provided that the rigs meet the technical and operational requirements of Saudi Aramco.
The shareholder agreement governing the joint venture (the "Shareholder Agreement") specifies that ARO shall purchase 20 newbuild jackup rigs. The first two newbuild jackups, Kingdom 1 and Kingdom 2, were ordered in January 2020 and commenced operations in the fourth quarter of 2023 and the third quarter of 2024, respectively. ARO ordered the next two newbuild jackups, Kingdom 3 and Kingdom 4, in October 2024 and November 2025, respectively. In connection with these plans, we have a potential obligation to fund ARO for newbuild jackup rigs. See “Note 11 - Commitments and Contingencies" for additional information.
The joint venture partners agreed in the Shareholder Agreement that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs. The initial contracts provided by Saudi Aramco for each of the newbuild rigs will be for an eight-year term. The day rate for the initial contracts for each newbuild rig is determined using a pricing mechanism that targets a six-year payback period for construction costs on an EBITDA basis. The initial eight-year contracts will be followed by a minimum of another eight years of term, re-priced in three-year intervals based on a market pricing mechanism.
Summarized Financial Information
The operating revenues of ARO presented below reflect revenues earned under drilling contracts with Saudi Aramco for the ARO-owned jackup rigs as well as the rigs leased from us. ARO's contract drilling expenses are inclusive of the bareboat charter fees for the rigs leased from us. See additional discussion below regarding these related-party transactions.
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Summarized financial information for ARO is as follows (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Revenues | $ | 571.0 |  |  | $ | 512.5 |  |  | $ | 496.6 |
Operating expenses |  |  |  |  |
Contract drilling expenses (exclusive of depreciation) | 360.7 |  |  | 367.7 |  |  | 365.9 |
Loss on impairment (1) | — |  |  | 28.4 |  |  | — |
Depreciation | 114.9 |  |  | 89.2 |  |  | 65.9 |
General and administrative | 28.8 |  |  | 23.7 |  |  | 22.2 |
Operating income | 66.6 |  |  | 3.5 |  |  | 42.6 |
Other expense, net | 59.5 |  |  | 55.5 |  |  | 31.8 |
Provision (benefit) for income taxes | 15.7 |  |  | (4.8) |  |  | 8.3 |
Net income (loss) | $ | (8.6) |  |  | $ | (47.2) |  |  | $ | 2.5 |

(1)In connection with Saudi Aramco's suspension of certain drilling contracts, the VALARIS 143, VALARIS 147 and VALARIS 148 contracts were suspended and subsequently terminated during the year ended December 31, 2024. Pursuant to the requirements of the contracts, ARO had capitalized certain costs to maintain and upgrade these rigs, which were determined to be impaired due to the contract suspensions and subsequent terminations. As a result, ARO recorded a pre-tax, non-cash loss on impairment of $28.4 million during the year ended December 31, 2024. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for more information about the contract terminations.

| December 31,
| 2025 |  | 2024
Cash and cash equivalents | $ | 99.3 |  |  | $ | 50.0 |
Other current assets | 148.3 |  |  | 127.7 |
Non-current assets | 1,266.1 |  |  | 1,291.1 |
Total assets | $ | 1,513.7 |  |  | $ | 1,468.8 |
Current liabilities | $ | 139.0 |  |  | $ | 146.6 |
Non-current liabilities | 1,263.8 |  |  | 1,202.7 |
Total liabilities | $ | 1,402.8 |  |  | $ | 1,349.3 |

Equity in earnings (losses) of ARO
We account for our interest in ARO using the equity method of accounting and only recognize our portion of ARO's net income (loss), adjusted for basis differences as discussed below, which is included in Equity in earnings (losses) of ARO in our Consolidated Statements of Operations. ARO is a variable interest entity; however, we are not the primary beneficiary and therefore do not consolidate ARO. Judgments regarding our level of influence over ARO included considering key factors such as each partner's ownership interest, representation on the board of managers of ARO and ability to direct activities that most significantly impact ARO's economic performance, including the ability to influence policy-making decisions. Our investment in ARO would be assessed for impairment if there are changes in facts and circumstances that indicate a loss in value may have occurred. If a loss were deemed to have occurred and this loss was determined to be other than temporary, the carrying value of our investment would be written down to fair value and an impairment recorded.
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Our equity method investment in ARO was recorded at its estimated fair value in fresh start accounting upon emergence from bankruptcy in 2021. We computed the difference between the fair value of ARO's net assets and the carrying value of those net assets in ARO's U.S. GAAP financial statements ("basis differences") at that date. These basis differences primarily related to ARO's long-lived assets and the recognition of intangible assets associated with certain of ARO's drilling contracts that were determined to have favorable terms relative to market terms as of the measurement date.
Basis differences are amortized over the remaining life of the assets or liabilities to which they relate and are recognized as an adjustment to the Equity in earnings (losses) of ARO in our Consolidated Statements of Operations. The amortization of those basis differences is combined with our 50% interest in ARO's net income (loss). A reconciliation of those components is presented below (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
50% interest in ARO net income (loss) | $ | (4.3) |  |  | $ | (23.6) |  |  | $ | 1.3 |
Amortization of basis differences | 12.7 |  |  | 12.6 |  |  | 12.0 |
Equity in earnings (losses) of ARO | $ | 8.4 |  |  | $ | (11.0) |  |  | $ | 13.3 |

Related-Party Transactions
Revenues recognized by us related to the Lease Agreements are included within Revenues (exclusive of reimbursable revenues) and revenues related to certain reimbursable expenses in accordance with the Lease Agreements are recognized within Reimbursable revenues in our Consolidated Statements of Operations and were as follows (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Revenues (exclusive of reimbursable revenues) from Lease Agreements | $ | 69.4 |  |  | $ | 52.6 |  |  | $ | 69.2 |
Reimbursable revenues from Lease Agreements | 4.2 |  |  | — |  |  | — |
Total operating revenues from Lease Agreements | $ | 73.6 |  |  | $ | 52.6 |  |  | $ | 69.2 |

Our balances related to the ARO lease agreements were as follows (in millions):

| December 31, |  |  |
| 2025 |  | 2024 |  |  |
Accounts receivable | $ | 47.8 |  |  | $ | 16.5 |  |  |  |
Contract assets (1) | $ | 2.0 |  |  | $ | — |  |  |  |
Contract liabilities (1) | $ | 16.3 |  |  | $ | 14.1 |  |  |  |
Accounts payable (1) | $ | 61.8 |  |  | $ | 43.1 |  |  |  |

(1)The per day bareboat charter amount in the Lease Agreements is subject to adjustment based on actual performance of the respective rig and therefore, the corresponding contract assets and contract liabilities are subject to adjustment during the lease term. Upon completion of the lease term, such amounts become a payable to or a receivable from ARO. In addition, the accounts payable balance includes amounts owed to ARO for certain reimbursable costs.
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During 2017 and 2018, the Company contributed assets to ARO in exchange for a 10-year shareholder note receivable due from ARO (the "Notes Receivable from ARO"), which as amended in December 2023, bear interest based on a one-year term Secured Overnight Financing Rate ("SOFR"), set as of the end of the year prior to the year applicable, plus 2.10%. The Notes Receivable from ARO were adjusted to the estimated fair value in fresh start accounting in 2021 and the resulting discount to the principal amount is being amortized using the effective interest method to interest income over the remaining terms of the notes.
The principal amount and discount of the Notes Receivable from ARO were as follows (in millions):

| December 31, |  |  |
| 2025 |  | 2024 |  |  |
Principal amount (1) | $ | 400.7 |  |  | $ | 376.6 |  |  |  |
Discount | (55.7) |  |  | (80.4) |  |  |  |
Carrying value | $ | 345.0 |  |  | $ | 296.2 |  |  |  |

(1)The interest on the Notes Receivable from ARO for 2025 and 2024 of approximately $24.1 million and $24.6 million, respectively, were paid in kind in December 2025 and 2024 by increasing the principal balance of the Notes Receivable from ARO in each respective period.
Interest income earned on the Notes Receivable from ARO was as follows (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Interest income | $ | 24.1 |  |  | $ | 24.6 |  |  | $ | 30.5 |
Non-cash amortization (1)(2) | 24.7 |  |  | 40.0 |  |  | 28.3 |
Total interest income on the Notes Receivable from ARO | $ | 48.8 |  |  | $ | 64.6 |  |  | $ | 58.8 |

(1)Represents the amortization of the discount on the Notes Receivable from ARO using the effective interest method to interest income over the term of the notes.
(2)In 2024, we recognized $13.9 million of non-cash interest income attributable to a settlement agreement executed in June 2024 whereby $50.7 million of accounts payable due to ARO was net settled against a portion of the Notes Receivable from ARO.
Maximum Exposure to Loss
The following table summarizes the total assets and liabilities as reflected in our Consolidated Balance Sheets as well as our maximum exposure to loss related to ARO (in millions). Our maximum exposure to loss is limited to (1) our equity investment in ARO; (2) the carrying amount of our Notes Receivable from ARO; and (3) other receivables and contract assets from ARO, partially offset by contract liabilities as well as payables to ARO.

| December 31, |
| 2025 |  | 2024 |
Total assets | $ | 516.6 |  |  | $ | 426.1 |  |
Less: total liabilities | 78.1 |  |  | 57.2 |  |
Maximum exposure to loss | $ | 438.5 |  |  | $ | 368.9 |  |

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4. FAIR VALUE MEASUREMENTS
The carrying values and estimated fair values of certain of our financial instruments were as follows (in millions):

|  | December 31, 2025 |  | December 31, 2024
|  | Carrying Value |  | Estimated Fair Value |  | Carrying Value |  | Estimated Fair Value
2030 Second Lien Notes (1) |  | $ | 1,086.0 |  |  | $ | 1,144.9 |  |  | $ | 1,082.7 |  |  | $ | 1,112.7 |
Notes Receivable from ARO (2)(3) |  | $ | 345.0 |  |  | $ | 403.8 |  |  | $ | 296.2 |  |  | $ | 378.3 |

(1)The estimated fair value of the 2030 Second Lien Notes (as defined in "Note 6 - Debt") was determined using quoted market prices, which are level 1 inputs.
(2)The estimated fair value of the Notes Receivable from ARO was estimated using an income approach to value the forecasted cash flows attributed to the Notes Receivable from ARO using a discount rate based on a comparable yield with a country-specific risk premium, which are considered to be level 2 inputs.
(3)The aggregate principal balance of the Notes Receivable from ARO as of December 31, 2025, includes an increase of $24.1 million related to paid in kind interest, which was applied to the principal balance on December 31, 2025. See "Note 3 - Equity Method Investment in ARO" for additional information.
The estimated fair values of our cash and cash equivalents, restricted cash, accounts receivable and trade payables approximated their carrying values as of December 31, 2025 and 2024.
5. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following (in millions):

|  | December 31,
|  | 2025 |  | 2024
Drilling rigs and equipment |  | $ | 1,958.8 |  |  | $ | 1,660.9 |
Work-in-progress |  | 590.3 |  |  | 607.6 |
Other |  | 49.2 |  |  | 40.9 |
Total property and equipment, at cost |  | $ | 2,598.3 |  |  | $ | 2,309.4 |

While taking into account certain restrictions on the sales of assets under our Indenture dated as of April 19, 2023 (the "Indenture”) and within the Business Combination Agreement (as defined within "Note 15 - Subsequent Events"), as part of our strategy, we may act opportunistically from time to time to sell assets to enhance shareholder value. Additionally, we may consider retiring assets that no longer meet our standards for economic returns. Gains recognized on sales of assets are included in Other, net in the Consolidated Statements of Operations.
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Assets Held for Sale
In the fourth quarter of 2025, we approved a plan to retire VALARIS DPS-1, a semisubmersible rig within our Floaters segment. VALARIS DPS-1 was reclassified from Property and equipment, net to Assets held for sale on our Consolidated Balance Sheets during the fourth quarter of 2025.
In connection with the held-for-sale classification of VALARIS DPS-1, we recognized a non-cash loss on impairment of $15.8 million during the year ended December 31, 2025, which represents the amount of carrying value that exceeded its estimated fair value less costs to sell. We estimated the fair value using a probability-weighted market approach based on recent transactions involving comparable assets, non-binding independent broker quotes and management assumptions, all of which are considered Level 3 inputs due to the level of estimation involved.
Assets Sold
Sale of VALARIS 102 and VALARIS 145
In the fourth quarter of 2025, we approved a plan to retire two rigs within our Jackups segment, VALARIS 102 and VALARIS 145 (collectively, the "Retired Jackups"). The Retired Jackups were sold for recycling and permanently removed from service in December 2025 for total cash proceeds of $0.5 million.
In connection with the sale of the Retired Jackups, we recognized a non-cash loss on impairment of $3.7 million, which represents the amount of carrying value that exceeded the disposal group's aggregate fair value less costs to sell. We estimated the fair value using the contractual sales price within the executed sale agreement for the Retired Jackups, which is considered a Level 2 input.
Sale of VALARIS 247
During the year ended December 31, 2025, we sold VALARIS 247, a rig within our Jackups segment, and collected cash proceeds of approximately $108.0 million. We recognized a pre-tax gain of $88.4 million in connection with the sale.
Sale of Retired Semis
In the first quarter of 2025, we approved a plan to retire three semisubmersible rigs within our Floaters segment, VALARIS DPS-3, VALARIS DPS-5, and VALARIS DPS-6 (collectively, the “Retired Semis”). In April 2025, the Retired Semis were sold for recycling and permanently removed from service for total cash proceeds of $10.0 million.
In connection with the retirement of the Retired Semis, we recognized a non-cash loss on impairment of $7.8 million, which represents the amount of carrying value that exceeded the disposal group's aggregate fair value less costs to sell. We estimated the fair value using a market approach based on the preliminary sale agreement for the Retired Semis, which is considered a Level 3 input due to the level of estimation involved since the sale had not yet been completed at the time of our analysis.
Sale of VALARIS 75
In the first quarter of 2025, VALARIS 75, a rig within our Jackups segment which had an immaterial net book value, was sold resulting in a pre-tax gain on sale of $23.0 million. Of the proceeds, $14.0 million was collected upon closing, $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.
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Sale of Angola Office Building
During the year ended December 31, 2025, we sold an office building in Angola for cash proceeds of $5.2 million, resulting in a pre-tax gain of $4.0 million. Of the proceeds, approximately $2.5 million was collected in 2024 and $2.7 million was collected in 2025.
Sale of VALARIS 54
During the year ended December 31, 2023, we recognized a pre-tax gain of $27.3 million for the sale of VALARIS 54.
6. DEBT
2028 First Lien Notes
On April 3, 2023, the Company issued a notice of conditional redemption to the holders of our Senior Secured First Lien Notes due 2028 (the "2028 First Lien Notes") at a redemption price equal to 104.0% of the aggregate $550.0 million principal amount of the 2028 First Lien Notes plus accrued and unpaid interest to, but not including, the redemption date (the “Redemption Price”). On April 19, 2023, in connection with the issuance of our 2030 Second Lien Notes, as discussed below, the Company discharged its obligations under the indenture governing the 2028 First Lien Notes and deposited the Redemption Price with Wilmington Savings Fund Society, as trustee under such indenture. The 2028 First Lien Notes were redeemed on May 3, 2023 for an aggregate redemption price of $571.8 million (excluding accrued and unpaid interest) with a portion of the net proceeds from the issuance of the Initial Second Lien Notes, as discussed below. We accounted for the redemption as an extinguishment of debt and recognized a corresponding loss of $29.2 million, which is included in our Consolidated Statements of Operations for the year ended December 31, 2023.
2030 Second Lien Notes
On April 19, 2023, the Company and Valaris Finance Company LLC (“Valaris Finance”), a wholly-owned subsidiary, issued and sold $700.0 million aggregate principal amount of Second Lien Notes (the "Initial Second Lien Notes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). The Initial Second Lien Notes were issued at par for net proceeds of $681.4 million, after deducting the initial purchasers’ discount and offering expenses. A portion of the proceeds were used to fund the redemption of all of the outstanding 2028 First Lien Notes as discussed above.
On August 21, 2023, the Company and Valaris Finance issued $400.0 million aggregate principal amount of Second Lien Notes (the "Additional Notes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act. The Additional Notes were issued at 100.75% of par, plus accrued interest from April 19, 2023. The net proceeds were approximately $396.9 million after deducting the initial purchasers’ discount and estimated offering expenses, and excluding accrued interest received of $11.4 million.
The Initial Second Lien Notes and the Additional Notes (together, the "2030 Second Lien Notes") were issued under the Indenture, and mature on April 30, 2030. The 2030 Second Lien Notes bear an interest rate of 8.375% per annum with an effective interest rate of 8.76%. Interest is payable semi-annually in arrears on April 30 and October 30 of each year, beginning on October 30, 2023. The 2030 Second Lien Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by the Guarantors and by each of the Company’s future restricted subsidiaries (other than Valaris Finance) that guarantees any debt of the Issuers or any guarantor under certain future debt in an aggregate principal amount in excess of a certain amount. The Second Lien Notes and the related guarantees are secured on a second-priority basis by the Collateral (as defined below).
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On or after April 30, 2026, the Issuers may, at their option, redeem all or any portion of the 2030 Second Lien Notes, at once or over time, at the redemption prices set forth below, plus accrued and unpaid interest, if any, to, but not including, the redemption date. The following prices are for 2030 Second Lien Notes redeemed during the 12-month period commencing on April 30 of the years set forth below, and are expressed as percentages of principal amount:

Redemption Year | Price
2026 | 104.188%
2027 | 102.094%
2028 and thereafter | 100.000%

At any time prior to April 30, 2026, the Issuers may, on any one or more occasions, redeem up to 40.0% of the aggregate principal amount of the 2030 Second Lien Notes issued under the Indenture (including any additional Second Lien Notes issued in the future) with an amount equal to or less than the net cash proceeds of certain equity offerings, at a redemption price equal to 108.375% of the principal amount thereof, plus accrued and unpaid interest thereon, if any, to but not including, the redemption date. In addition, at any time prior to April 30, 2026, the Issuers may redeem up to 10.0% of the aggregate principal amount of the 2030 Second Lien Notes during any twelve-month period at a redemption price equal to 103.0% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the redemption date.
At any time prior to April 30, 2026, the Issuers may redeem some or all of the 2030 Second Lien Notes at a price equal to 100.0% of the principal amount of the 2030 Second Lien Notes redeemed, plus accrued and unpaid interest, if any, to, but not including, the redemption date, plus a “make-whole” premium.
Upon the occurrence of certain Change of Control Triggering Event (as defined in the Indenture), the Issuers may be required to make an offer to repurchase all of the 2030 Second Lien Notes then outstanding at a price equal to 101.0% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the repurchase date.
The Indenture contains covenants that, among other things, restrict the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt and issue certain preferred stock; (ii) incur or create liens; (iii) make certain distributions, investments and other restricted payments; (iv) sell or otherwise dispose of certain assets; (v) engage in certain transactions with affiliates; and (vi) merge, consolidate, amalgamate or sell, transfer, lease or otherwise dispose of all or substantially all of the Company’s assets. These covenants are subject to important exceptions and qualifications. In addition, many of these covenants will be suspended with respect to the 2030 Second Lien Notes during any time that the 2030 Second Lien Notes have investment grade ratings from at least two rating agencies and no default with respect to the 2030 Second Lien Notes has occurred and is continuing. As of December 31, 2025, we were in compliance in all material respects with our covenants under the Indenture.
2028 Credit Agreement
On April 3, 2023, the Company entered into a senior secured revolving credit agreement (the “2028 Credit Agreement”). The 2028 Credit Agreement, which is scheduled to mature on April 3, 2028, provides for commitments permitting borrowings of up to $375.0 million (which may be increased, subject to the agreement of lenders to provide such additional commitments and the satisfaction of certain conditions, 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 (the "Availability Date").
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The 2028 Credit Agreement and the related guarantees are secured on a first-priority basis, subject to permitted liens, by (a) first preferred ship mortgages over each vessel owned by us and the Guarantors as of the Availability Date, with certain exceptions (the “Collateral Vessels”); (b) first priority assignments of certain insurances and requisition compensation in respect of the Collateral Vessels; (c) first priority pledges of all equity interests in our subsidiaries that own Collateral Vessels and certain subsidiaries that hold equity interests in entities that own vessels (the “Collateral Rig Owners”); (d) first priority assignments of earnings of the Collateral Vessels from the Collateral Rig Owners; (e) any vessels and other assets of ours and the Guarantors that are pledged, at our option, to secure the 2028 Credit Agreement; and (f) all proceeds thereof (the "Collateral").
Amounts borrowed under the 2028 Credit Agreement are subject to an interest rate per annum equal to, at our option, either (a) a base rate determined as the greatest of (i) a prime rate, (ii) the federal funds rate plus 0.5% and (iii) Term SOFR (as defined in the 2028 Credit Agreement) for a one month interest period plus 1.1% (such base rate to be subject to a 1% floor) or (b) Term SOFR plus 0.10% (subject to a 0% floor), plus, in each case of clauses (a) and (b) above, an applicable margin ranging from 1.50% to 3.00% and 2.50% to 4.00%, respectively, based on the credit ratings that are one notch higher than the corporate family ratings provided by Standard & Poor’s Financial Services LLC (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”) with respect to Valaris Limited.
Additionally, we are required to pay a quarterly commitment fee to the lenders under the 2028 Credit Agreement with respect to the average daily unutilized commitments thereunder at a rate ranging from 0.375% to 0.75% depending on the credit ratings that are one notch higher than the corporate family ratings provided by S&P and Moody’s with respect to Valaris Limited. With respect to each letter of credit issued pursuant to the 2028 Credit Agreement, we are required to pay a letter of credit fee equal to the applicable margin in effect for Term SOFR loans and a fronting fee in an amount to be mutually agreed between us and the issuer of such letter of credit. We are also required to pay customary agency fees in respect of the 2028 Credit Agreement.
The 2028 Credit Agreement contains various covenants that limit, among other things, our and our restricted subsidiaries’ ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to shareholders; enter into transactions with affiliates; enter into sale-leaseback transactions; and enter into a merger, amalgamation, consolidation or sale of assets. Further, the 2028 Credit Agreement contains financial covenants that require 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.
As of December 31, 2025, we were in compliance in all material respects with our covenants under the 2028 Credit Agreement. We had no amounts outstanding under the 2028 Credit Agreement as of December 31, 2025.
Interest Expense
Interest expense, net totaled $98.8 million, $84.8 million and $68.9 million for the years ended December 31, 2025, 2024 and 2023 which was net of capitalized interest of $1.9 million, $15.9 million and $5.6 million, respectively, for capital projects.
Amortization of debt premium and issuance costs was $6.6 million, $6.6 million and $5.0 million for the years ended December 31, 2025, 2024 and 2023, respectively, and is included within Interest expense, net in the Consolidated Statements of Operations.
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7. SHAREHOLDERS' EQUITY
Activity in our various shareholders' equity accounts for the years ended December 31, 2025, 2024 and 2023 were as follows (in millions):

| Shares Issued |  | Par Value |  | Additional Paid-in Capital |  | Warrants |  | Retained Earnings |  | AOCI |  | Treasury Shares |  | Non-controlling Interest
BALANCE, December 31, 2022 | 75.2 |  |  | $ | 0.8 |  |  | $ | 1,097.9 |  |  | $ | 16.4 |  |  | $ | 160.1 |  |  | $ | 14.7 |  |  | $ | — |  |  | $ | 8.0 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | 865.4 |  |  | — |  |  | — |  |  | 1.4 |
Share-based compensation cost | — |  |  | — |  |  | 27.3 |  |  |  |  | — |  |  | — |  |  | — |  |  | — |
Shares issued under share-based compensation plans, net | 0.2 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Repurchase of Common Shares | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (200.1) |  |  | — |
Net changes in pension and other postretirement benefits | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 10.8 |  |  | — |  |  | — |
Shares withheld for taxes on vesting of share-based awards | — |  |  | — |  |  | (5.4) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (0.3) |  |  | — |  |  | — |
BALANCE, December 31, 2023 | 75.4 |  |  | $ | 0.8 |  |  | $ | 1,119.8 |  |  | $ | 16.4 |  |  | $ | 1,025.5 |  |  | $ | 25.2 |  |  | $ | (200.1) |  |  | $ | 9.4 |
Net income (loss) | — |  |  | — |  |  | — |  |  | — |  |  | 373.4 |  |  | — |  |  | — |  |  | (3.6) |
Share-based compensation cost | — |  |  | — |  |  | 27.7 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Shares issued under share-based compensation plans, net | 0.8 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Repurchase of Common Shares | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (125.0) |  |  | — |
Net changes in pension and other postretirement benefits | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 10.9 |  |  | — |  |  | — |
Shares withheld for taxes on vesting of share-based awards | — |  |  | — |  |  | (29.9) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Purchase of noncontrolling ownership interest in a non-U.S. subsidiary (1) | — |  |  | — |  |  | 4.1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (8.4) |
Sale of noncontrolling ownership interest in a non-U.S. subsidiary (1) | — |  |  | — |  |  | (8.4) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 8.4 |
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1.9) |  |  | — |  |  | — |
BALANCE, December 31, 2024 | 76.2 |  |  | $ | 0.8 |  |  | $ | 1,113.3 |  |  | $ | 16.4 |  |  | $ | 1,398.9 |  |  | $ | 34.2 |  |  | $ | (325.1) |  |  | $ | 5.8 |
Net income (loss) | — |  |  | — |  |  | — |  |  | — |  |  | 982.8 |  |  | — |  |  | — |  |  | (3.7) |
Share-based compensation cost | — |  |  | — |  |  | 25.2 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Shares issued under share-based compensation plans, net | 0.2 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Repurchase of Common Shares | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (100.0) |  |  | — |
Net changes in pension and other postretirement benefits | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 24.5 |  |  | — |  |  | — |
Shares withheld for taxes on vesting of share-based awards | — |  |  | — |  |  | (3.6) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 2.2 |  |  | — |  |  | — |
BALANCE, December 31, 2025 | 76.4 |  |  | 0.8 |  |  | 1,134.9 |  |  | 16.4 |  |  | 2,381.7 |  |  | 60.9 |  |  | (425.1) |  |  | 2.1 |

(1)In 2024, the Company purchased the 51% noncontrolling interest related to a certain non-U.S. subsidiary and concurrently transferred the 51% noncontrolling interest to new partners. The net transactions did not result in a change to our ownership or controlling interest in the non-U.S. subsidiary.
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Share Repurchase Program
Our board of directors has authorized a share repurchase program (the "Share Repurchase Program") under which we may purchase up to $600.0 million of our outstanding Common Shares. The Share Repurchase Program does not have a fixed expiration, may be modified, suspended or discontinued at any time and any repurchases made pursuant to the Share Repurchase Program are subject to compliance with applicable covenants and restrictions under our financing agreements.
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,
| 2025 |  | 2024 |  | 2023 |  |
Shares repurchased | 2.0 |  |  | 2.2 |  |  | 3.0 |  |  |
Aggregate cost | $ | 100.0 |  |  | $ | 125.0 |  |  | $ | 200.0 |  |  |
Average price per share | $ | 49.78 |  |  | $ | 56.11 |  |  | $ | 66.77 |  |  |

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 (as defined within "Note 15 - Subsequent Events").
8. SHARE BASED COMPENSATION
Valaris Limited adopted the MIP as of April 30, 2021 and authorized and reserved 9.0 million Common Shares for issuance pursuant to equity incentive awards to be granted under the MIP, which may be in the form of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and cash awards or any combination thereof. As of December 31, 2025, there were 6.2 million shares available for issuance under the MIP.
Time-Based Share Awards
Under the Company's MIP, time-based restricted stock unit awards have been granted to certain employees and senior officers which generally vest ratably over a three-year period from the date of grant. The grant-date fair value per share for these time-based restricted stock awards is equal to the closing price of the Company's stock on the grant date.
Non-employee directors receive an annual grant of time-based restricted awards which vest in full on the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant. Non-employee directors are permitted to elect to receive deferred share awards which can be settled and delivered on the six-month anniversary following the termination of the director's service or a specific pre-determined date.
Our time-based share awards do not have voting or participating rights as the dividend equivalent provided for in the award agreement is forfeitable (except in certain limited circumstances) and further our debt agreements limit our ability to pay dividends and none have been declared. Compensation expense for share awards is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). Our compensation cost is reduced for forfeited awards in the period in which the forfeitures occur.
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Compensation expense for our time-based share awards is allocated to Contract drilling expenses (exclusive of depreciation and reimbursable expenses) and General and administrative expenses within our Consolidated Statements of Operations based on the award holder's employment function. The following table summarizes time-based share award compensation expense and the related income tax benefit recognized (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Contract drilling expenses (exclusive of depreciation and reimbursable expenses) | $ | 9.3 |  |  | $ | 8.8 |  |  | $ | 6.8 |
General and administrative | 8.6 |  |  | 8.7 |  |  | 9.0 |
| 17.9 |  |  | 17.5 |  |  | 15.8 |
Tax benefit | (0.5) |  |  | (1.1) |  |  | (1.6) |
Total | $ | 17.4 |  |  | $ | 16.4 |  |  | $ | 14.2 |

As of December 31, 2025, there was $28.3 million of total estimated unrecognized compensation cost related to time-based share awards, which has a weighted-average remaining vesting period of 1.4 years.
The following table summarizes the value of time-based share awards granted and vested:

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Weighted-average grant date fair value of share awards granted during the period (per share) | $ | 43.58 |  |  | $ | 69.89 |  |  | $ | 63.22 |
Total fair value of share awards vested during the period (in millions) | $ | 13.4 |  |  | $ | 30.0 |  |  | $ | 25.2 |

The following table summarizes time-based share awards activity for the year ended December 31, 2025 (shares in thousands):

| Share Awards
| Awards |  | Weighted-Average Grant Date Fair Value
Share awards as of December 31, 2024 | 597 |  |  | $ | 60.58 |
Granted | 494 |  |  | $ | 43.58 |
Vested | (307) |  |  | $ | 56.80 |
Forfeited | (3) |  |  | $ | 58.00 |
Share awards as of December 31, 2025 | 781 |  |  | $ | 51.32 |

Performance Awards
Under the Company's MIP, performance awards may be issued to our senior officers. Performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals.
105

The performance awards granted in 2021 and 2022 were based on three performance goals and subject to achievement of those performance goals based on (a) designated share price hurdles whereby our closing stock price must equal or exceed certain market price targets for ninety consecutive trading days (the "Share Price Objective"); (b) relative return on capital employed ("ROCE") as compared to a specified peer group, all as defined in the award agreements (the "ROCE Objective"), and (c) specified strategic goals as established by the Compensation Committee of the board of directors (the "Strategic Goal Objective" and together with the ROCE Objective, the "Performance-Based Objectives"). In 2023, incremental awards based on the Strategic Goal Objective were granted. These awards were paid in equity during 2024 following a three-year performance period and were subject to attainment of such objectives ranging from 0% to 150% of target performance under such objectives.
The performance awards granted in 2023, 2024 and 2025 include awards which are subject to the achievement of goals based on our absolute total shareholder return and our total shareholder return relative to a specified peer group (the "TSR Objectives" and together with the Share Price Objective, the "Market-Based Objectives"). These awards are payable in equity at a range from 0% to 200% of target performance following three-year performance periods, subject to approval by the Compensation Committee of the board of directors following the end of each respective performance period.
The estimated probable outcome of attainment of the specified performance goals is based primarily on relative performance over the requisite performance period. Any subsequent changes in this estimate as it relates to the Performance-Based Objectives are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs. Compensation cost for the Market-Based Objectives is recognized as long as the requisite service period is completed and will not be reversed even if the Market-Based Objectives are never satisfied. Compensation expense for performance awards is recognized over the requisite service period using the accelerated method and is reduced for forfeited awards in the period in which the forfeitures occur.
The fair value of the performance awards is measured on the date of grant. The grant-date fair value per unit for the portion of the performance awards related to Performance-Based Objectives was equal to the closing price of the Company's stock on the grant date. The portion of these awards that were based on the Company's achievement of Market-based Objectives were valued at the date of grant using a Monte Carlo simulation with the following weighted average assumptions for the grants made in the years ended December 31, 2025, 2024 and 2023:

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Expected price volatility | 48 | % |  | 49 | % |  | 60 | %
Expected dividend yield | — |  |  | — |  |  | — |
Risk-free interest rate | 3.90 | % |  | 4.31 | % |  | 4.32 | %

The expected price volatility assumption is estimated using market data for certain peer companies during periods in which our own trading history is limited. As our trading history increases, it will bear greater weight in determining our expected price volatility assumption.
The weighted average grant-date fair values of performance awards granted during the years ended December 31, 2025, 2024 and 2023 were $28.92, $63.05 and $62.09, respectively.
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The following table summarizes the performance award activity for the year ended December 31, 2025 (shares in thousands):

| Awards(2) |  | Weighted Average Grant Date Fair Value Price(2)
Balance as of December 31, 2024 | 271 |  |  | $ | 61.69 |
Granted - Market-Based Objectives(1) | 236 |  |  | $ | 28.92 |
Balance as of December 31, 2025 | 507 |  |  | $ | 46.42 |

(1)The number of awards granted reflects the shares that would be granted if the target level of performance were to be achieved. The number of shares actually issued after considering forfeitures may range from zero to 472,000.
(2)There were no forfeited or vested shares for the year ended December 31, 2025.
During the years ended December 31, 2025, 2024 and 2023, we recognized $7.7 million, $10.6 million and $11.7 million of compensation expense for performance awards, respectively, which was included in General and administrative expenses in our Consolidated Statements of Operations.
As of December 31, 2025, there was $8.4 million of total estimated unrecognized compensation cost related to performance awards, which has a weighted-average remaining vesting period of 1.6 years.
9. PENSION AND OTHER POST-RETIREMENT BENEFITS
We have defined-benefit pension plans and post-retirement health and life insurance plans that provide benefits upon retirement for certain full-time employees. The defined-benefit pension plans include: (1) a pension plan which was amended in 2018 to freeze any future benefit accrual whereby eligible employees no longer receive pay credits in the plan and newly hired employees are not eligible to participate; and (2) supplemental executive retirement plans, which are also frozen, that provided eligible employees an opportunity to defer a portion of their compensation for use after retirement. Additionally, we have frozen retiree life and medical supplemental plans which provide post-retirement health and life insurance benefits.
107

The following table presents the changes in benefit obligations and plan assets for the years ended December 31, 2025 and 2024 and the funded status and weighted-average assumptions used to determine the benefit obligation at the measurement date (dollars in millions):

|  | Years Ended December 31,
|  | 2025 |  | 2024
|  | Pension Benefits |  | Other Benefits |  | Total |  | Pension Benefits |  | Other Benefits |  | Total
Projected benefit obligation: |  |  |  |  |  |  |  |  |  |  |  |
BALANCE at the beginning of the period |  | $ | 571.3 |  |  | $ | 10.2 |  |  | $ | 581.5 |  |  | $ | 606.5 |  |  | $ | 11.0 |  |  | $ | 617.5 |
Interest cost |  | 30.5 |  |  | 0.5 |  |  | 31.0 |  |  | 29.3 |  |  | 0.5 |  |  | 29.8 |
Actuarial loss (gain) |  | 5.3 |  |  | — |  |  | 5.3 |  |  | (22.1) |  |  | (0.7) |  |  | (22.8) |
Benefits paid |  | (42.1) |  |  | (0.6) |  |  | (42.7) |  |  | (42.4) |  |  | (0.6) |  |  | (43.0) |
BALANCE at the end of the period |  | $ | 565.0 |  |  | $ | 10.1 |  |  | $ | 575.1 |  |  | $ | 571.3 |  |  | $ | 10.2 |  |  | $ | 581.5 |
Plan assets |  |  |  |  |  |  |  |  |  |  |  |
Fair value, at the beginning of the period |  | $ | 469.9 |  |  | $ | — |  |  | $ | 469.9 |  |  | $ | 471.2 |  |  | $ | — |  |  | $ | 471.2 |
Actual return |  | 60.1 |  |  | — |  |  | 60.1 |  |  | 20.2 |  |  | — |  |  | 20.2 |
Employer contributions |  | 16.0 |  |  | — |  |  | 16.0 |  |  | 20.9 |  |  | — |  |  | 20.9 |
Benefits paid |  | (42.1) |  |  | — |  |  | (42.1) |  |  | (42.4) |  |  | — |  |  | (42.4) |
Fair value, at the end of the period |  | $ | 503.9 |  |  | $ | — |  |  | $ | 503.9 |  |  | $ | 469.9 |  |  | $ | — |  |  | $ | 469.9 |
Net benefit liabilities |  | $ | 61.1 |  |  | $ | 10.1 |  |  | $ | 71.2 |  |  | $ | 101.4 |  |  | $ | 10.2 |  |  | $ | 111.6 |
Amounts recognized in Consolidated Balance Sheet: |  |  |  |  |  |  |  |  |  |  |  |
Accrued liabilities |  | $ | (2.0) |  |  | $ | (0.9) |  |  | $ | (2.9) |  |  | $ | (4.1) |  |  | $ | (1.0) |  |  | $ | (5.1) |
Other liabilities (long-term) |  | (59.1) |  |  | (9.2) |  |  | (68.3) |  |  | (97.3) |  |  | (9.2) |  |  | (106.5) |
Net benefit liabilities |  | $ | (61.1) |  |  | $ | (10.1) |  |  | $ | (71.2) |  |  | $ | (101.4) |  |  | $ | (10.2) |  |  | $ | (111.6) |
Accumulated contributions less than net periodic benefit cost |  | $ | (114.1) |  |  | $ | (18.0) |  |  | $ | (132.1) |  |  | $ | (129.5) |  |  | $ | (18.5) |  |  | $ | (148.0) |
Amounts not yet reflected in net periodic benefit cost: |  |  |  |  |  |  |  |  |  |  |  |
Actuarial gain |  | 53.2 |  |  | 7.9 |  |  | 61.1 |  |  | 28.3 |  |  | 8.3 |  |  | 36.6 |
Prior service cost |  | (0.2) |  |  | — |  |  | (0.2) |  |  | (0.2) |  |  | — |  |  | (0.2) |
Total accumulated other comprehensive income |  | $ | 53.0 |  |  | $ | 7.9 |  |  | $ | 60.9 |  |  | $ | 28.1 |  |  | $ | 8.3 |  |  | $ | 36.4 |
Net benefit liabilities |  | $ | (61.1) |  |  | $ | (10.1) |  |  | $ | (71.2) |  |  | $ | (101.4) |  |  | $ | (10.2) |  |  | $ | (111.6) |
Weighted-average assumptions: |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  | 5.34 | % |  | 5.28 | % |  |  |  | 5.54 | % |  | 5.52 | % |  |
Cash balance interest credit rate |  | 3.72 | % |  | N/A |  |  |  | 3.26 | % |  | N/A |  |

The projected benefit obligations for pension benefits in the preceding table reflect the actuarial present value of benefits accrued based on services rendered to date assuming the actual or assumed expected date of separation for retirement.
The accumulated benefit obligation is equal to the projected benefit obligation at December 31, 2025 and 2024 as the pension and other post-retirement benefit plans were frozen in prior years.
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The components of net periodic pension, retiree medical (income) loss and the weighted-average assumptions used to determine such amounts were as follows (dollars in millions):

|  | Years Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Interest cost |  | $ | 31.0 |  |  | $ | 29.8 |  |  | $ | 31.2 |
Expected return on plan assets |  | (29.4) |  |  | (31.6) |  |  | (31.4) |
Amortization of net gain |  | (0.7) |  |  | (0.6) |  |  | (0.7) |
Net periodic pension and retiree medical (income) loss (1) |  | $ | 0.9 |  |  | $ | (2.4) |  |  | $ | (0.9) |
Discount rate |  | 5.54 | % |  | 4.97 | % |  | 5.21 | %
Expected return on assets |  | 6.44 | % |  | 6.88 | % |  | 7.10 | %
Cash balance interest credit rate |  | 3.26 | % |  | 3.26 | % |  | 3.23 | %

(1)All components of Net periodic pension and retiree medical (income) loss are included in Other, net, in our Consolidated Statements of Operations.
We currently expect to contribute approximately $19.2 million to our pension plans and to directly pay other post-retirement benefits of approximately $0.9 million in 2026. These amounts represent the minimum contributions we are required to make under relevant statutes. We do not expect to make contributions in excess of the minimum required amounts.
The pension plans' investment objectives for fund assets are to: achieve a rate of return such that contributions are minimized and future assets are available to fund liabilities, maintain liquidity sufficient to pay benefits when due, diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk and gradually de-risk the plan by increasing the allocation of investments which track the overall liabilities of the plan as the ratio of assets to liabilities improves and economic conditions warrant. The plans employ several active managers with proven long-term records in their specific investment discipline.
109

Target allocations among asset categories as of December 31, 2025, and the fair value of each category of plan assets as of December 31, 2025 and 2024, are presented below. The plans will reallocate assets in accordance with the allocation targets, after giving consideration to the expected level of cash required to pay current benefits and plan expenses (dollars in millions):

| December 31,
| 2025 |  |  | 2024
| Target range (1) |  | Amount |  |  | Amount
Equities: |  |  |  |  |  |
Global equity fund (2) | 41% to 47% |  | $ | 217.3 |  |  |  | $ | — |
U.S. equity: |  |  |  |  |  |
U.S. large cap |  |  | — |  |  |  | 93.3 |
U.S. small/mid cap |  |  | — |  |  |  | 24.6 |
Global Low Volatility Equity |  |  | — |  |  |  | 34.1 |
Non-U.S. equity: |  |  |  |  |  |
International all cap |  |  | — |  |  |  | 42.7 |
International small cap |  |  | — |  |  |  | 18.9 |
Emerging markets |  |  | — |  |  |  | 34.1 |
Real estate equities | 4% to 8% |  | 36.5 |  |  |  | 36.5 |
Fixed income: | 45% to 55% |  |  |  |  |
Long-term corporate bonds |  |  | 160.2 |  |  |  | 102.8 |
Long-term government bonds |  |  | 32.0 |  |  |  | — |
U.S. Treasury STRIPS |  |  | 52.9 |  |  |  | 76.7 |
Cash and equivalents | $0 - $5.0 |  | 5.0 |  |  |  | 6.2 |
Total |  |  | $ | 503.9 |  |  |  | $ | 469.9 |

(1)Our investment policy only sets allocation target ranges for general asset classes and not specific investment types.
(2)During 2025, the assets in the various equity asset categories were consolidated into a single Global equity fund.
All of our investments, other than cash and cash equivalents, are measured at fair value using the net asset value per share (or its equivalent) practical expedient and therefore are not categorized in the fair value hierarchy. Cash and cash equivalents are considered Level 1 as they were valued at cost, which approximates fair value.
Assets in the Global equity fund include a broad range of global equity securities for which the portfolio may be a full replication or a sampling of the Morgan Stanley Capital International All Country World Index and may be held through a commingled or institutional mutual fund. Assets in the U.S. equities category include investments in common and preferred stocks (and equivalents such as American Depository Receipts and convertible bonds) and may be held through separate accounts, commingled funds or an institutional mutual fund. Assets in the global low volatility equities include investments in a broad range of developed market global equity securities and may be held through a commingled or institutional mutual fund. Assets in the international equities category include investments in a broad range of international equity securities, including both developed and emerging markets, and may be held through a commingled or institutional mutual fund. The real estate category includes investments in pooled and commingled funds whose objectives are diversified equity investments in income-producing properties. Each real estate fund is intended to provide broad exposure to the real estate market by property type, geographic location and size and may invest internationally. Additionally, this category includes real estate investment trusts, which are represented in the Dow Jones US Select REIT Index. Securities in the fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds and should be rated investment grade or above. Investments in this category should have an average investment rating of “A” or better.
110

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 plan's 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.
Estimated future annual benefit payments from plan assets are presented below. Such amounts are based on existing benefit formulas and include the effect of future service (in millions):

|  | Pension Benefits |  | Other Post-Retirement Benefits
Years ending December 31, |  |  |  |
2026 |  | $ | 41.0 |  |  | $ | 0.9 |
2027 |  | 40.7 |  |  | 0.9 |
2028 |  | 40.4 |  |  | 0.9 |
2029 |  | 40.2 |  |  | 0.8 |
2030 |  | 39.7 |  |  | 0.8 |
2031 through 2035 |  | 189.9 |  |  | 3.6 |

Savings Plans
We have savings plans, (the "Savings Plan", the "Limited Retirement Plan", the "Multinational Savings Plan"), which cover eligible employees as defined within each plan. The Savings Plan includes a 401(k) savings plan feature, which allows eligible employees to make tax-deferred contributions to the plans. The Limited Retirement Plan allows eligible employees in the United Kingdom (the "U.K.") to make tax-deferred contributions to the plan. Contributions made to the Multinational Savings Plan may or may not qualify for tax deferral based on each plan participant's local tax requirements.
Employee contributions have been matched up to a maximum of 6% since the beginning of 2025 and were matched up to a maximum of 5% in 2024 and 2023. These matching contributions totaled $19.2 million, $15.6 million and $13.2 million for the years ended December 31, 2025, 2024 and 2023, respectively.
10. 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.
During the fourth quarter of 2025, we adopted Update 2023-09 (see "Note 1 - Description of the Business and Summary of Significant Accounting Policies" for further discussion on Update 2023-09) on a prospective basis. As such, we have updated income tax disclosure presentations as of and for the year ended December 31, 2025 in order to comply with Update 2023-09, but have not retrospectively applied these presentational changes to any of the prior periods presented. This adoption of Update 2023-09 resulted in presentational differences of our income tax disclosures and did not result in a change to the calculations of our income before income taxes, current tax expense, deferred tax expense or effective tax rates for the year ended December 31, 2025.
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Our income before income taxes and benefit for income taxes for the year ended December 31, 2025 are summarized as follows (in millions):

Income (loss) before income taxes: |  |  |
Bermuda | $ | (107.4) |  |  |
Foreign |  |  |
U.S. | 42.2 |  |  |
Other foreign | 617.5 |  |  |
Total foreign | 659.7 |  |  |
Total income before income taxes | $ | 552.3 |  |  |
Provision (benefit) for income taxes: |  |  |
Current tax expense: |  |  |
Bermuda federal | $ | — |  |  |
Bermuda state | — |  |  |
Foreign |  |  |
U.S. | 13.7 |  |  |
Other foreign | 74.6 |  |  |
Total foreign | 88.3 |  |  |
Total current tax expense | $ | 88.3 |  |  |
Deferred tax benefit: |  |  |
Bermuda federal | $ | — |  |  |
Bermuda state | — |  |  |
Foreign |  |  |
U.S. | (1.7) |  |  |
Other foreign | (513.4) |  |  |
Total foreign | (515.1) |  |  |
Total deferred tax benefit | $ | (515.1) |  |  |
Total provision (benefit) for income taxes: |  |  |
Bermuda federal | $ | — |  |  |
Bermuda state | — |  |  |
Foreign |  |  |
U.S. | 12.0 |  |  |
Other foreign | (438.8) |  |  |
Total foreign | (426.8) |  |  |
Total benefit for income taxes | $ | (426.8) |  |  |

112

Our income before income taxes and provision for income taxes for the years ended December 31, 2024 and 2023 are summarized as follows (in millions):

| Years Ended December 31,
| 2024 |  | 2023
Income before income taxes: |  |  |
U.S. | $ | 49.8 |  |  | $ | 30.7 |
Non-U.S. | 320.4 |  |  | 53.5 |
| $ | 370.2 |  |  | $ | 84.2 |
Current income tax expense (benefit): |  |  |
U.S. | $ | 11.5 |  |  | $ | (30.3) |
Non-U.S. | (16.9) |  |  | 34.1 |
| (5.4) |  |  | 3.8 |
Deferred income tax expense (benefit): |  |  |
U.S. | (4.4) |  |  | 1.9 |
Non-U.S. | 10.2 |  |  | (788.3) |
| 5.8 |  |  | (786.4) |
Total income tax expense (benefit) | $ | 0.4 |  |  | $ | (782.6) |

Effective Tax Rate
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.
113

As a Bermuda-domiciled company, Valaris Limited is subject to a 15.0% Bermuda corporate income tax, which became effective on January 1, 2025. In addition, we are subject to other income taxes, including those in the U.S. and in various foreign jurisdictions. Our consolidated effective tax rate reconciliation for the year ended December 31, 2025 is summarized below (in millions, except percentages):

| Amount |  | %
Bermuda federal statutory rate | $ | 82.8 |  |  | 15.0 | %
Changes in valuation allowances | 16.1 |  |  | 2.9 | %
Foreign tax effects |  |  |
Angola |  |  |
Withholding taxes | 16.5 |  |  | 3.0 | %
Changes in valuation allowances | (8.0) |  |  | (1.4) | %
Other | 8.4 |  |  | 1.5 | %
Brazil |  |  |
Tax rate differential | 11.5 |  |  | 2.1 | %
Other | (3.1) |  |  | (0.6) | %
British Virgin Islands |  |  |
Tax rate differential | 6.3 |  |  | 1.1 | %
Luxembourg |  |  |
Changes in valuation allowances | (1,092.2) |  |  | (197.8) | %
Prior period tax matters | (54.8) |  |  | (9.9) | %
Cross border income inclusion | 9.5 |  |  | 1.7 | %
State and local tax rate differential | 9.2 |  |  | 1.7 | %
Other | 4.8 |  |  | 0.9 | %
Saudi Arabia |  |  |
Withholding taxes | 6.3 |  |  | 1.1 | %
Other | 2.8 |  |  | 0.5 | %
Switzerland |  |  |
Changes in valuation allowances | 383.9 |  |  | 69.5 | %
Prior period tax matters | 156.2 |  |  | 28.3 | %
Tax rate differential | (25.2) |  |  | (4.6) | %
State and local tax rate differential | 13.4 |  |  | 2.4 | %
Global minimum taxes | 5.5 |  |  | 1.0 | %
Other | (1.4) |  |  | (0.3) | %
Trinidad |  |  |
Tax rate differential | 6.6 |  |  | 1.2 | %
Changes in valuation allowances | (5.2) |  |  | (0.9) | %
Other | (1.5) |  |  | (0.3) | %
United Kingdom |  |  |
Changes in valuation allowances | 10.0 |  |  | 1.8 | %
United States |  |  |
Changes in valuation allowances | (17.2) |  |  | (3.1) | %
Expiration of foreign tax credits | 16.3 |  |  | 3.0 | %
Other | 6.6 |  |  | 1.2 | %
Other foreign jurisdictions (1) | 12.8 |  |  | 2.3 | %
Changes in unrecognized tax benefits | (3.7) |  |  | (0.6) | %
Total | $ | (426.8) |  |  | (77.3) | %

(1)Other foreign jurisdictions includes the aggregated remaining foreign jurisdictions for which there were no foreign tax effects reconciling items which exceeded the 5% disclosure threshold.
114

Our consolidated effective tax rate reconciliations for the years ended December 31, 2024 and 2023 are summarized below (in millions, except percentages):

| Years Ended December 31,
| 2024 |  | 2023
Bermuda statutory income tax rate | — | % |  | — | %
Non-Bermuda taxes | 25.6 |  |  | 74.0 |
Valuation allowance | (2.3) |  |  | (953.6) |
Resolution of prior year items | (23.2) |  |  | (49.9) |
Effective income tax rate | 0.1 | % |  | (929.5) | %

Our 2025 consolidated effective income tax rate includes 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.
Our 2024 consolidated effective income tax rate includes 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.
Our 2023 consolidated effective income tax rate includes discrete tax benefit of $42.0 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 rates for the years ended December 31, 2025, 2024 and 2023 were (92.2)%, 21.8% and (872.3)%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three-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.
Deferred Taxes
The components of deferred income tax assets and liabilities are summarized as follows (in millions):

|  | December 31,
|  | 2025 |  | 2024
Deferred tax assets: |  |  |  |
Net operating loss carryforwards |  | $ | 3,103.9 |  |  | $ | 3,071.8 |
Property and equipment |  | 1,397.4 |  |  | 1,555.4 |
Interest limitation carryforwards |  | 112.9 |  |  | 126.0 |
Employee benefits, including share-based compensation |  | 28.0 |  |  | 36.6 |
Foreign tax credits |  | 0.2 |  |  | 16.4 |
Other |  | 17.9 |  |  | 21.9 |
Valuation allowance |  | (3,292.3) |  |  | (3,971.3) |
Total deferred tax assets |  | 1,368.0 |  |  | 856.8 |
Deferred tax liabilities |  | (26.9) |  |  | (26.7) |
Net deferred tax asset |  | $ | 1,341.1 |  |  | $ | 830.1 |

The realization of substantially all of our deferred tax assets is dependent upon generating sufficient taxable income during future periods in various jurisdictions in which we operate. We rely on projected taxable income from both current and future drilling contracts for the recognition of deferred tax assets. Realization of certain of our deferred tax assets is not assured. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change.
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As of December 31, 2025, we had gross deferred tax assets of $3.1 billion relating to $13.6 billion of net operating loss ("NOL") carryforwards and $112.9 million of interest limitation carryforwards, primarily related to the U.S., Luxembourg and the U.K., which can be used to reduce our income taxes payable in future years. NOL carryforwards, which were generated in various jurisdictions worldwide, include $8.4 billion that do not expire and $5.2 billion that will expire, if not utilized, between 2026 and 2042. Deferred tax assets for NOL carryforwards as of December 31, 2025 include $2.3 billion, $614.9 million, $75.7 million, $58.7 million, $27.2 million and $21.2 million pertaining to NOL carryforwards in Luxembourg, the U.S., the U.K., Bermuda, Switzerland and Trinidad, respectively. Interest limitation carryforwards generally do not expire. Additionally, as a result of our emergence from bankruptcy, the utilization of certain U.S. deferred tax assets including, but not limited to, NOL carryforwards and interest limitation carryforwards is limited to $0.5 million annually.
We had a $3.3 billion and a $4.0 billion valuation allowance as of December 31, 2025 and 2024, respectively, on deferred tax assets relating to those assets for which we are not more likely than not to realize due to the inability to generate sufficient taxable income in the period prior to expiration and/or of the character necessary to use the benefit of the deferred tax assets.
During the years ended December 31, 2025, 2024 and 2023, we recognized a deferred tax benefit of $523.2 million, $8.5 million and $802.9 million, respectively, associated with changes in deferred tax asset valuation allowances. The deferred tax benefit in 2025 includes a $1.1 billion reduction of our valuation allowance in Luxembourg, which was partially offset by a $383.9 million increase to the valuation allowance in Switzerland, driven in part by the establishment of a $168.8 million valuation allowance resulting from a change in estimated future taxable income in a certain operating jurisdiction in connection with the retirement of the Retired Semis. The deferred tax benefit in 2023 primarily related to a $799.5 million reduction of our valuation allowance.
The net reductions to the valuation allowances for 2025 and 2023 were due to changes in the balances of relevant positive and negative evidence considered when assessing the realization of our deferred tax assets in certain operating jurisdictions. After considering the balance of evidence, which included historical financial results, projected earnings, contract backlog, day rates and market outlook, we determined that sufficient positive evidence existed to conclude that these portions of the valuation allowance on deferred tax assets were no longer needed. We intend to continue maintaining a valuation allowance on a substantial portion of our deferred tax assets until there is sufficient evidence to support a reversal of such allowances. The timing and amount of future valuation allowance reductions are subject to future levels of contracting and profitability achieved.
Unrecognized Tax Benefits
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.
As of December 31, 2025, we had $94.8 million of unrecognized tax benefits, of which $88.2 million was included in Other liabilities on our Consolidated Balance Sheet, and $6.6 million, which is associated with tax positions taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets.
As of December 31, 2024, we had $93.5 million of unrecognized tax benefits, of which $82.8 million was included in Other liabilities on our Consolidated Balance Sheet, $10.7 million, which is associated with tax positions taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets.
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If recognized, $88.2 million of the $94.8 million unrecognized tax benefits as of December 31, 2025 would impact our consolidated effective income tax rate. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2025, 2024 and 2023 (in millions) were as follows:

|  | Years Ended December 31,
|  | 2025 |  | 2024 |  | 2023
Balance, beginning of period |  | $ | 93.5 |  |  | $ | 201.4 |  |  | $ | 217.6 |
Increases as a result of tax positions taken during prior years |  | 10.2 |  |  | 4.1 |  |  | 88.6 |
Decreases as a result of tax positions taken during prior years |  | (8.6) |  |  | (1.4) |  |  | (3.4) |
Settlements with taxing authorities |  | (7.0) |  |  | (103.5) |  |  | (41.8) |
Impact of foreign currency exchange rates |  | 6.5 |  |  | (7.9) |  |  | 0.6 |
Increases as a result of tax positions taken during the current year |  | 1.3 |  |  | 2.7 |  |  | 13.4 |
Lapse of applicable statutes of limitations |  | (1.1) |  |  | (1.9) |  |  | (73.6) |
Balance, end of period |  | $ | 94.8 |  |  | $ | 93.5 |  |  | $ | 201.4 |

Accrued interest and penalties totaled $48.0 million and $45.5 million as of December 31, 2025 and 2024, respectively, and were included in Other liabilities on our Consolidated Balance Sheets. We recognized a net expense of $1.5 million, and net benefits of $8.0 million and $35.4 million associated with interest and penalties during the years ended December 31, 2025, 2024 and 2023, respectively. Interest and penalties are included in Current income tax expense in our Consolidated Statements of Operations.
Three of our subsidiaries file or previously filed U.S. tax returns and the tax returns of one or more of these subsidiaries is under exam for tax years 2014 and subsequent years. None of these examinations are expected to have a significant impact on the Company's consolidated results of operations and cash flows. Tax years as early as 2005 remain subject to examination in the other major tax jurisdictions in which we operated.
Statutes of limitations applicable to certain of our tax positions lapsed during the years ended December 31, 2025, 2024 and 2023, resulting in net income tax benefits, inclusive of interest and penalties, of $1.4 million, $2.7 million and $77.3 million, respectively.
Absent the commencement of examinations by tax authorities, statutes of limitations applicable to certain of our tax positions will lapse during 2026, but we do not expect these to have a material impact to our unrecognized tax benefits or effective income tax rate.
Tax Assessments
Malaysia Tax Assessment
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.
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Luxembourg Tax Assessment
In December 2023, one of the Company’s Luxembourg subsidiaries received tax assessments for fiscal years 2019, 2020, 2021 and 2023. In February 2024, the Luxembourg tax authorities rescinded the portion of the assessment relating to 2023, resulting in a revised aggregate tax assessment of approximately €60.0 million (approximately $65.0 million converted at then-current exchange rates). We recorded a liability for uncertain tax positions for this amount in 2023 and contested the validity and amount of the assessments. In April 2024, we received a favorable decision from the Luxembourg tax authorities stating that the assessments for the 2019-2021 tax years are not enforceable. As a result, we reversed the uncertain tax position liability for the previously issued assessments and recognized a tax benefit of approximately $65.0 million in 2024.
Australian Tax 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).
Undistributed Earnings
Dividend income received by Valaris Limited from its subsidiaries is exempt from Bermuda taxation. We do not provide deferred taxes on 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 would be subject to additional income taxes. The unrecognized deferred tax liability related to these undistributed earnings was not practicable to estimate as of December 31, 2025.
Tax Legislation
On July 4, 2025, the U.S. enacted H.R. 1, informally referred to as the One Big Beautiful Bill Act (“OBBBA”). Among other provisions, the OBBBA includes the permanent extension, with modifications, of certain business and international tax provisions originally enacted under the Tax Cuts and Jobs Act of 2017 that were scheduled to sunset at the end of 2025. The OBBBA did not have a material impact on our consolidated financial statements for the year ending December 31, 2025.
Additionally, Bermuda enacted the Corporate Income Tax Act 2023 on December 27, 2023 (the “CIT Act”) which stipulates a tax on 15% of the net income of certain Bermuda constituent entities (as determined in accordance with the CIT Act, including after adjusting for any relevant foreign tax credits applicable to the Bermuda constituent entities). No tax was chargeable under the CIT Act until tax years starting on or after January 1, 2025. Deferred taxes of $27.5 million with an offsetting valuation allowance of $27.5 million were established as of December 31, 2023, upon enactment.
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11. COMMITMENTS AND CONTINGENCIES
ARO Newbuild Funding Obligations
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 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. ARO 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. The final payment for each rig will be due upon delivery.
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.
Letters of Credit
In the ordinary course of business with customers and others, we have entered into letters of credit to guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Letters of credit outstanding as of December 31, 2025 totaled $35.4 million and are issued under facilities provided by various banks and other financial institutions, but none were issued under the 2028 Credit Agreement. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirements. As of December 31, 2025, we had collateral deposits in the amount of $16.3 million with respect to these agreements.
Patent Litigation
In December 2022, a subsidiary of Transocean Ltd. commenced an arbitration proceeding against us alleging breach of a license agreement related to certain dual-activity drilling patents. In July 2025, the arbitration tribunal rendered a final decision awarding Transocean Ltd. $7.9 million in damages, including interest, and awarded Valaris $7.4 million as reimbursement for legal fees incurred in connection with this matter. As a result of this decision, in the second quarter of 2025, we reversed $17.1 million of the $25.0 million liability previously accrued in 2024, and we recognized a $7.4 million receivable for the recovery of legal fees. In the third quarter of 2025, the awarded amounts due to and from Transocean Ltd. were paid and therefore, we have no outstanding balances pertaining to this matter as of December 31, 2025.
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Brazil Administrative Matter
In July 2023, we received notice of an administrative proceeding initiated against us in Brazil. Specifically, the Federal Court of Accounts ("TCU") sought from us, Samsung Heavy Industries (“SHI”) and others, on a joint and several basis, a total of approximately BRL 601.0 million in damages that TCU asserted arose from the overbilling to Petrobras in 2015 in relation to the drilling services agreement with Petrobras for VALARIS DS-5 (the “DSA”). As fully disclosed in our prior periodic reports, the DSA was previously the subject of (1) investigations by the SEC and the U.S Department of Justice, each of which closed their investigation of us in 2018 without any enforcement action, (2) an arbitration proceeding against SHI in which we prevailed, resulting in SHI making a $200.0 million cash payment to us in December 2019, and (3) a settlement with Petrobras normalizing our business relations in August 2018.
In May 2024, the Brazilian prosecutor issued an opinion recommending that the TCU close this matter against us. In July 2025, a trial was held and all claims against us were dismissed.
Other Matters
In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows.
12. LEASES
We have operating leases for office space, facilities, equipment, employee housing and certain rig berthing facilities. For all asset classes, except office space, we account for the lease component and the non-lease component as a single lease component. Short-term leases with a term of one year or less are not recorded in the Consolidated Balance Sheets. Our leases have remaining lease terms of less than one month to six years, some of which include options to extend. The lease term used for calculating our right-of-use assets and lease liabilities is determined by considering the non-cancelable lease term, as well as any extension options that we are reasonably certain to exercise. Our right-of-use assets, current lease liabilities, and long-term lease liabilities are included within Other assets, Accrued liabilities and other, and Other liabilities, respectively, in the Consolidated Balance Sheets.
We evaluate the carrying value of our right-of-use assets on a periodic basis to identify events or changes in circumstances, such as lease abandonment, which indicate that the carrying value of such right-of-use assets may be impaired.
The components of lease expense are as follows (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Long-term operating lease cost | $ | 41.9 |  |  | $ | 35.4 |  |  | $ | 24.6 |
Short-term operating lease cost | 21.3 |  |  | 17.6 |  |  | 13.2 |
Variable lease cost (1) | 13.8 |  |  | 9.8 |  |  | 11.3 |
Total operating lease cost | $ | 77.0 |  |  | $ | 62.8 |  |  | $ | 49.1 |

(1)Variable lease costs are excluded from the measurement of right-of-use assets and lease liabilities and consist primarily of variable fees related to offshore equipment rentals.
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Supplemental balance sheet information related to our operating leases is as follows (in millions, except lease term and discount rate):

| December 31,
| 2025 |  | 2024
Operating lease right-of-use assets | $ | 69.3 |  | $ | 84.5
Current lease liability | $ | 35.6 |  | $ | 28.0
Long-term lease liability | 37.3 |  | 56.9
Total operating lease liabilities | $ | 72.9 |  | $ | 84.9
Weighted-average remaining lease term (in years) | 2.5 |  | 3.2
Weighted-average discount rate (1) | 7.67 | % |  | 7.75 | %

(1)Represents our estimated incremental borrowing cost on a secured basis for similar terms as the underlying leases.
Supplemental cash flow information related to our operating leases is as follows (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
ROU assets obtained in exchange for operating lease liabilities | $ | 19.4 |  |  | $ | 39.4 |  |  | $ | 80.3 |
Cash paid for amounts included in the measurement of our operating lease liabilities | $ | 40.1 |  |  | $ | 34.9 |  |  | $ | 26.2 |

Maturities of lease liabilities as of December 31, 2025 were as follows (in millions):

2026 | $ | 39.8 |
2027 | 25.4 |
2028 | 8.3 |
2029 | 3.5 |
2030 | 2.7 |
Thereafter | 0.4 |
Total lease payments | $ | 80.1 |
Less imputed interest | (7.2) |
Total | $ | 72.9 |

13. SEGMENT INFORMATION
Our business consists of four operating segments, which have been determined based on the asset type and specifications and services we provide. These operating segments are Floaters, Jackups, ARO and Other. The Floaters segment consists of our drillships and semisubmersible rigs, which can generally drill in water depths up to 12,000 feet and 8,000 feet, respectively. Floaters are generally considered to be more advanced, typically earn higher day rates and require a larger crew complement to operate. The Jackups segment consists of our jackup rigs, which generally operate in water depths of 400 feet or less. As Jackups have a simpler design and operate in shallow waters, they typically earn lower day rates and require a smaller crew to operate. The ARO segment consists of the full operations of ARO, which operates jackup drilling rigs in Saudi Arabia for Saudi Aramco. The Other segment consists of management services on rigs owned by third parties and the activities associated with our arrangements with ARO under the Lease Agreements.
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Each of the reporting segments earn revenues through drilling contracts, in which we provide a drilling rig and/or drilling services, inclusive of rig crews, on a day rate basis. Floaters, Jackups and ARO are also reportable segments.
Our chief operating decision maker (“CODM”) is the executive management committee, which is comprised of the Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, Chief Commercial Officer, General Counsel & Secretary, Chief Human Resources Officer, Vice President – Strategy and Sustainability and Vice President – Operational Integrity. The CODM assesses segment performance based on their review of the operating income (loss) of each segment, which measures profitability after deducting normal operating costs. Components within operating income (loss), such as revenues and contract drilling expenses, are used to monitor actual performance against budget and monthly forecasted results for each segment. Further, the CODM utilizes revenue to derive a segment’s asset utilization, average daily revenue and revenue efficiency. Using these metrics, the CODM can identify potentially underperforming segments and develop strategies to increase profits or reduce costs, make investment decisions and allocate resources as needed. The disaggregated segment information, as presented in the tables below, aligns with the segment level information that is regularly provided to the CODM.
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." We measure segment assets as Property and equipment, net.
The full operating results included below for ARO are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See "Note 3 - Equity Method Investment in ARO" for additional information on ARO and related arrangements.
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Segment information for the years ended December 31, 2025, 2024 and 2023 are presented below (in millions).
Year Ended December 31, 2025

| Floaters |  | Jackups |  | ARO |  | Other |  | Reconciling Items |  | Consolidated Total
Operating revenues: |  |  |  |  |  |  |  |  |  |  |
Revenues (exclusive of reimbursable revenues) | $ | 1,224.1 |  |  | $ | 823.4 |  |  | $ | 571.0 |  |  | $ | 160.4 |  |  | $ | (571.0) |  |  | $ | 2,207.9 |
Reimbursable revenues | 36.5 |  |  | 89.4 |  |  | — |  |  | 35.2 |  |  | — |  |  | 161.1 |
Total operating revenues | 1,260.6 |  |  | 912.8 |  |  | 571.0 |  |  | 195.6 |  |  | (571.0) |  |  | 2,369.0 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |
Contract drilling expenses (exclusive of depreciation and reimbursable expenses) | 765.6 |  |  | 486.5 |  |  | 360.7 |  |  | 70.6 |  |  | (206.3) |  |  | 1,477.1 |
Reimbursable expenses | 34.3 |  |  | 83.5 |  |  | — |  |  | 34.8 |  |  | — |  |  | 152.6 |
Total contract drilling expenses (exclusive of depreciation) | 799.9 |  |  | 570.0 |  |  | 360.7 |  |  | 105.4 |  |  | (206.3) |  |  | 1,629.7 |
Loss on impairment | 23.6 |  |  | 3.7 |  |  | — |  |  | — |  |  | — |  |  | 27.3 |
Depreciation | 60.5 |  |  | 58.6 |  |  | 114.9 |  |  | 13.2 |  |  | (100.9) |  |  | 146.3 |
General and administrative | — |  |  | — |  |  | 28.8 |  |  | — |  |  | 68.3 |  |  | 97.1 |
Equity in earnings of ARO | — |  |  | — |  |  | — |  |  | — |  |  | 8.4 |  |  | 8.4 |
Operating income | $ | 376.6 |  |  | $ | 280.5 |  |  | $ | 66.6 |  |  | $ | 77.0 |  |  | $ | (323.7) |  |  | $ | 477.0 |
Property and equipment, net | $ | 1,225.0 |  |  | $ | 630.8 |  |  | $ | 1,236.7 |  |  | $ | 174.2 |  |  | $ | (1,177.9) |  |  | $ | 2,088.8 |
Capital expenditures | $ | 144.7 |  |  | $ | 192.0 |  |  | $ | 95.6 |  |  | $ | — |  |  | $ | (88.8) |  |  | $ | 343.5 |

Year Ended December 31, 2024

| Floaters |  | Jackups |  | ARO |  | Other |  | Reconciling Items |  | Consolidated Total
Operating revenues: |  |  |  |  |  |  |  |  |  |  |
Revenues (exclusive of reimbursable revenues) | $ | 1,382.8 |  |  | $ | 686.5 |  |  | $ | 512.5 |  |  | $ | 142.6 |  |  | $ | (512.5) |  |  | $ | 2,211.9 |
Reimbursable revenues | 57.9 |  |  | 68.4 |  |  | — |  |  | 24.4 |  |  | — |  |  | 150.7 |
Total operating revenues | 1,440.7 |  |  | 754.9 |  |  | 512.5 |  |  | 167.0 |  |  | (512.5) |  |  | 2,362.6 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |
Contract drilling expenses (exclusive of depreciation and reimbursable expenses) | 930.3 |  |  | 477.1 |  |  | 367.7 |  |  | 63.6 |  |  | (220.2) |  |  | 1,618.5 |
Reimbursable expenses | 54.9 |  |  | 64.3 |  |  | — |  |  | 23.2 |  |  | — |  |  | 142.4 |
Total contract drilling expenses (exclusive of depreciation) | 985.2 |  |  | 541.4 |  |  | 367.7 |  |  | 86.8 |  |  | (220.2) |  |  | 1,760.9 |
Loss on impairment | — |  |  | — |  |  | 28.4 |  |  | — |  |  | (28.4) |  |  | — |
Depreciation | 58.1 |  |  | 45.0 |  |  | 89.2 |  |  | 9.5 |  |  | (79.7) |  |  | 122.1 |
General and administrative | — |  |  | — |  |  | 23.7 |  |  | — |  |  | 92.6 |  |  | 116.3 |
Equity in losses of ARO | — |  |  | — |  |  | — |  |  | — |  |  | (11.0) |  |  | (11.0) |
Operating income | $ | 397.4 |  |  | $ | 168.5 |  |  | $ | 3.5 |  |  | $ | 70.7 |  |  | $ | (287.8) |  |  | $ | 352.3 |
Property and equipment, net | $ | 1,174.2 |  |  | $ | 575.3 |  |  | $ | 1,253.1 |  |  | $ | 132.8 |  |  | $ | (1,202.5) |  |  | $ | 1,932.9 |
Capital expenditures | $ | 239.7 |  |  | $ | 213.1 |  |  | $ | 285.0 |  |  | $ | — |  |  | $ | (282.7) |  |  | $ | 455.1 |

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Year Ended December 31, 2023

| Floaters |  | Jackups |  | ARO |  | Other |  | Reconciling Items |  | Consolidated Total
Operating revenues: |  |  |  |  |  |  |  |  |  |  |
Revenues (exclusive of reimbursable revenues) | $ | 902.8 |  |  | $ | 620.6 |  |  | $ | 496.6 |  |  | $ | 152.6 |  |  | $ | (496.6) |  |  | $ | 1,676.0 |
Reimbursable revenues | 45.9 |  |  | 39.0 |  |  | — |  |  | 23.3 |  |  | — |  |  | 108.2 |
Total operating revenues | 948.7 |  |  | 659.6 |  |  | 496.6 |  |  | 175.9 |  |  | (496.6) |  |  | 1,784.2 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |
Contract drilling expenses (exclusive of depreciation and reimbursable expenses) | 768.4 |  |  | 480.4 |  |  | 365.9 |  |  | 52.6 |  |  | (226.9) |  |  | 1,440.4 |
Reimbursable expenses | 43.6 |  |  | 37.0 |  |  | — |  |  | 22.6 |  |  | — |  |  | 103.2 |
Total contract drilling expenses (exclusive of depreciation) | 812.0 |  |  | 517.4 |  |  | 365.9 |  |  | 75.2 |  |  | (226.9) |  |  | 1,543.6 |
Depreciation | 55.8 |  |  | 40.0 |  |  | 65.9 |  |  | 5.0 |  |  | (65.6) |  |  | 101.1 |
General and administrative | — |  |  | — |  |  | 22.2 |  |  | — |  |  | 77.1 |  |  | 99.3 |
Equity in earnings of ARO | — |  |  | — |  |  | — |  |  | — |  |  | 13.3 |  |  | 13.3 |
Operating income | $ | 80.9 |  |  | $ | 102.2 |  |  | $ | 42.6 |  |  | $ | 95.7 |  |  | $ | (267.9) |  |  | $ | 53.5 |
Property and equipment, net | $ | 1,035.5 |  |  | $ | 480.8 |  |  | $ | 1,036.6 |  |  | $ | 52.1 |  |  | $ | (971.2) |  |  | $ | 1,633.8 |
Capital expenditures | $ | 562.0 |  |  | $ | 132.3 |  |  | $ | 300.8 |  |  | $ | — |  |  | $ | (299.0) |  |  | $ | 696.1 |

Information about Geographic Areas
As of December 31, 2025, our Floaters segment consisted of 13 drillships and two semisubmersible rigs. Our Jackups segment consisted of 24 jackup rigs which were deployed in various locations and our Other segment consisted of seven jackup rigs which are leased to our 50/50 unconsolidated joint venture with Saudi Aramco.
As of December 31, 2025, the geographic distribution of our and ARO's drilling rigs was as follows:

| Floaters |  | Jackups |  | Other |  | Total Valaris |  | ARO
Europe | 6 |  | 11 |  | — |  | 17 |  | —
Middle East & Africa | 2 |  | 7 |  | 7 |  | 16 |  | 9
North & South America | 5 |  | 3 |  | — |  | 8 |  | —
Asia & Pacific Rim | 1 |  | 3 |  | — |  | 4 |  | —
Held for sale (1) | 1 |  | — |  | — |  | 1 |  | —
Total | 15 |  | 24 |  | 7 |  | 46 |  | 9

(1)VALARIS DPS-1 was classified as held for sale and warm stacked in Asia Pacific as of December 31, 2025. See "Note 5 - Property and Equipment" for more information regarding VALARIS DPS-1.
We provide management services in the U.S. Gulf of America on two rigs owned by a third party not included in the table above.
ARO ordered two newbuild jackup rigs Kingdom 3 and Kingdom 4, which are under construction in the Middle East and are not included in table above.
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Information by country for those countries that account for more than 10% of our long-lived assets was as follows (in millions):

| Long-lived Assets
| December 31,
| 2025 |  | 2024
Spain (1) | $ | 627.4 |  |  | $ | 484.8 |
Brazil | 352.2 |  |  | 413.9 |
United States | 268.7 |  |  | 314.3 |
United Kingdom | 262.1 |  |  | 290.4 |
Angola | 234.6 |  |  | 132.6 |
Other countries (2) | 419.5 |  |  | 381.4 |
Total | $ | 2,164.5 |  |  | $ | 2,017.4 |

(1)Long-lived assets located in Spain primarily consist of rigs which were idle or preservation stacked.
(2)Other countries includes countries where individually we had long-lived assets representing less than 10% of total long-lived assets.
For purposes of our geographic disclosures above, we attribute assets to the geographic location of the drilling rig or operating lease, in the case of our right-of-use assets, as of the end of the applicable year.
14. SUPPLEMENTAL FINANCIAL INFORMATION
Consolidated Balance Sheet Information
Accounts receivable, net, consisted of the following (in millions):

| December 31,
| 2025 |  | 2024
Trade | $ | 424.1 |  |  | $ | 502.4 |
Income tax receivables | 49.8 |  |  | 76.2 |
Other | 15.8 |  |  | 9.2 |
| 489.7 |  |  | 587.8 |
Allowance for doubtful accounts | (14.9) |  |  | (16.6) |
| $ | 474.8 |  |  | $ | 571.2 |

Other current assets consisted of the following (in millions):

| December 31,
| 2025 |  | 2024
Prepaid taxes | $ | 58.2 |  |  | $ | 48.5 |
Deferred costs | 37.7 |  |  | 38.6 |
Prepaid expenses | 13.3 |  |  | 13.0 |
Other | 35.5 |  |  | 39.2 |
| $ | 144.7 |  |  | $ | 139.3 |

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Accrued liabilities and other consisted of the following (in millions):

| December 31,
| 2025 |  | 2024
Current contract liabilities (deferred revenues) | $ | 87.7 |  |  | $ | 87.2 |
Personnel costs | 81.6 |  |  | 89.2 |
Income and other taxes payable | 73.9 |  |  | 57.2 |
Lease liabilities | 35.6 |  |  | 28.0 |
Accrued claims | 21.3 |  |  | 39.5 |
Accrued interest | 15.4 |  |  | 15.3 |
Other | 27.9 |  |  | 34.6 |
| $ | 343.4 |  |  | $ | 351.0 |

Other liabilities consisted of the following (in millions):

| December 31,
| 2025 |  | 2024
Unrecognized tax benefits (inclusive of interest and penalties) | $ | 136.2 |  |  | $ | 128.3 |
Pension and other post-retirement benefits | 68.3 |  |  | 106.5 |
Noncurrent contract liabilities (deferred revenues) | 63.2 |  |  | 71.4 |
Lease liabilities | 37.3 |  |  | 56.9 |
Other | 20.8 |  |  | 20.1 |
| $ | 325.8 |  |  | $ | 383.2 |

Consolidated Statements of Operations Information
Repair and maintenance expense related to continuing operations was as follows (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Repair and maintenance expense | $ | 236.2 |  |  | $ | 239.6 |  |  | $ | 203.3 |

Other, net, consisted of the following (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Net gain (loss) on sale of property | $ | 118.6 |  |  | $ | (0.2) |  |  | $ | 28.6 |
Net foreign currency exchange gains (losses) | (14.3) |  |  | 13.8 |  |  | (3.5) |
Net periodic pension and retiree medical income (loss) | (0.9) |  |  | 2.4 |  |  | 0.9 |
Loss on extinguishment of debt | — |  |  | — |  |  | (29.2) |
Other income (expense) | (0.1) |  |  | 0.6 |  |  | 1.4 |
| $ | 103.3 |  |  | $ | 16.6 |  |  | $ | (1.8) |

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Consolidated Statements of Cash Flows Information
The following table provides a reconciliation of the amount of cash and cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts shown within the Consolidated Statements of Cash Flows (in millions):

| December 31,
| 2025 |  | 2024
Cash and cash equivalents | $ | 599.4 |  |  | $ | 368.2 |
Restricted cash—current (1) | 7.0 |  |  | 12.3 |
Restricted cash—non-current (1) | 11.1 |  |  | — |
| $ | 617.5 |  |  | $ | 380.5 |

(1)Restricted cash consists primarily of collateral on letters of credit of $16.3 million and $10.8 million as of December 31, 2025 and 2024, respectively. Restricted cash—current is included in Other current assets and restricted cash—non-current is included in Other assets in our Consolidated Balance Sheets. See "Note 11 - Commitments and Contingencies" for more information regarding our letters of credit.
Net cash provided by operating activities attributable to the net change in operating assets and liabilities was as follows (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
(Increase) decrease in accounts receivable | $ | 119.2 |  |  | $ | (64.9) |  |  | $ | 44.9 |
(Increase) decrease in other assets | 2.6 |  |  | 23.4 |  |  | (6.5) |
Increase (decrease) in liabilities | (42.9) |  |  | (91.7) |  |  | 82.8 |
| $ | 78.9 |  |  | $ | (133.2) |  |  | $ | 121.2 |

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Cash paid (received) for income taxes, net, which includes taxes withheld by third parties on our behalf, for the year ended December 31, 2025 was as follows (in millions) (1):

Bermuda federal | $ | — |
Foreign |
Australia (2) | (23.7) |
Brazil | 18.6 |
United States | 16.8 |
Angola | 13.1 |
Malaysia | 8.0 |
Trinidad | 6.9 |
Saudi Arabia | 4.2 |
Other (3) | 17.6 |
Total foreign | 61.5 |
| $ | 61.5 |

(1)During the fourth quarter of 2025, we adopted Update 2023-09 (see "Note 1 - Description of the Business and Summary of Significant Accounting Policies" for further discussion on Update 2023-09) on a prospective basis. As such, we have updated the cash paid for income tax disclosure presentation for the year ended December 31, 2025 in order to comply with the new guidance, but have not retrospectively applied these presentational changes to any of the prior periods presented.
(2)During 2025, we received income tax refunds of approximately $26.0 million from the Australian tax authorities in connection with a settlement agreement for previously issued tax assessments. Refer to "Note 10 - Income Taxes" for further information regarding this settlement agreement.
(3)Other represents the aggregation of jurisdictions which did not individually exceed the 5% disaggregation threshold.
Cash paid (refunded) for income taxes, net, which includes withholding taxes withheld by third parties on our behalf, for the years ended December 31, 2024 and 2023 were as follows (in millions):

| Years Ended December 31,
| 2024 |  | 2023
Income taxes paid (refunded), net (1) (2) | $ | 55.6 |  |  | $ | (8.3) |

(1)We received U.S. income tax refunds totaling $35.9 million in 2024 primarily related to an Internal Revenue Service examination of one of our subsidiaries' 2009-2012 tax returns.
(2)We received an income tax refund of $45.9 million in 2023 related to the U.S. Coronavirus Aid, Relief, and Economic Security Act.
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Additional cash flow information was as follows (in millions):

| Years Ended December 31,
| 2025 |  | 2024 |  | 2023
Cash paid for interest |  |  |  |  |
Interest paid, net of amounts capitalized | $ | 90.5 |  |  | $ | 78.3 |  |  | $ | 32.3 |
Non-cash investing activities |  |  |  |  |
Accruals for capital expenditures as of period end (1) | $ | 52.0 |  |  | $ | 36.2 |  |  | $ | 71.5 |

(1)Accruals for capital expenditures were excluded from investing activities in our Consolidated Statements of Cash Flows.
During the years ended December 31, 2025, 2024 and 2023, the capitalized interest totaled $1.9 million, $15.9 million and $5.6 million, respectively.
Concentration of Risk
Credit Risk - We are exposed to credit risk relating to our cash and cash equivalents and receivables from customers. Our cash and cash equivalents are primarily held by various well-capitalized and credit-worthy financial institutions. We monitor the credit ratings of these institutions and limit the amount of exposure to any one institution and therefore, do not believe a significant credit risk exists for these balances. We mitigate our credit risk relating to receivables from customers, which consist primarily of major international, government-owned and independent oil and gas companies, by performing ongoing credit evaluations. We also maintain reserves for potential credit losses, which generally have been within our expectations.
Customer Concentration - Consolidated revenues with customers that individually contributed 10% or more of revenue in the years ended December 31, 2025, 2024 and 2023 were as follows:
Year Ended December 31, 2025

| Floaters |  | Jackups |  | Other |  | Total
Petróleo Brasileiro S.A. ("Petrobras") | 13 | % |  | — | % |  | — | % |  | 13 | %
BP plc ("BP") | 3 | % |  | 3 | % |  | 6 | % |  | 12 | %
Azule Energy ("Azule") | 7 | % |  | 3 | % |  | — | % |  | 10 | %
Other customers (1) | 30 | % |  | 33 | % |  | 2 | % |  | 65 | %
| 53 | % |  | 39 | % |  | 8 | % |  | 100 | %

Year Ended December 31, 2024

| Floaters |  | Jackups |  | Other |  | Total |  |  |  |  |
BP | 9 | % |  | 3 | % |  | 5 | % |  | 17 | % |  |  |  |  |
Petrobras | 9 | % |  | — | % |  | — | % |  | 9 | % |  |  |  |  |
Azule | 4 | % |  | — | % |  | — | % |  | 4 | % |  |  |  |  |
Other customers (1) | 39 | % |  | 29 | % |  | 2 | % |  | 70 | % |  |  |  |  |
| 61 | % |  | 32 | % |  | 7 | % |  | 100 | % |  |  |  |  |

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Year Ended December 31, 2023

| Floaters |  | Jackups |  | Other |  | Total |  |  |  |  |
BP | — | % |  | 5 | % |  | 6 | % |  | 11 | % |  |  |  |  |
Petrobras | 4 | % |  | — | % |  | — | % |  | 4 | % |  |  |  |  |
Other customers (1) | 49 | % |  | 32 | % |  | 4 | % |  | 85 | % |  |  |  |  |
| 53 | % |  | 37 | % |  | 10 | % |  | 100 | % |  |  |  |  |

(1)Other customers includes customers that individually contributed to less than 10% of our total revenues.
Geographic Concentration - For purposes of our geographic disclosure, we attribute revenues to the geographic location where such revenues are earned. Consolidated revenues for locations that individually had 10% or more of revenue were as follows (in millions):
Year Ended December 31, 2025

| Floaters |  | Jackups |  | Other |  | Total
Brazil | $ | 587.3 |  |  | $ | — |  |  | $ | — |  |  | $ | 587.3 |
United Kingdom | — |  |  | 391.8 |  |  | — |  |  | 391.8 |
Gulf of America | 223.3 |  |  | — |  |  | 119.1 |  |  | 342.4 |
Angola | 219.5 |  |  | 74.0 |  |  | — |  |  | 293.5 |
Australia | 145.9 |  |  | 128.2 |  |  | — |  |  | 274.1 |
Other countries (1) | 84.6 |  |  | 318.8 |  |  | 76.5 |  |  | 479.9 |
| $ | 1,260.6 |  |  | $ | 912.8 |  |  | $ | 195.6 |  |  | $ | 2,369.0 |

Year Ended December 31, 2024

| Floaters |  | Jackups |  | Other |  | Total |  |  |  |  |
Brazil | $ | 497.9 |  |  | $ | — |  |  | $ | — |  |  | $ | 497.9 |  |  |  |  |  |
United Kingdom | — |  |  | 375.2 |  |  | — |  |  | 375.2 |  |  |  |  |  |
Gulf of America | 245.4 |  |  | 10.3 |  |  | 111.7 |  |  | 367.4 |  |  |  |  |  |
Australia | 172.1 |  |  | 104.3 |  |  | — |  |  | 276.4 |  |  |  |  |  |
Angola | 196.7 |  |  | — |  |  | — |  |  | 196.7 |  |  |  |  |  |
Other countries (1) | 328.6 |  |  | 265.1 |  |  | 55.3 |  |  | 649.0 |  |  |  |  |  |
| $ | 1,440.7 |  |  | $ | 754.9 |  |  | $ | 167.0 |  |  | $ | 2,362.6 |  |  |  |  |  |

Year Ended December 31, 2023

| Floaters |  | Jackups |  | Other |  | Total |  |  |  |  |
Gulf of America | $ | 220.9 |  |  | $ | 27.2 |  |  | $ | 104.7 |  |  | $ | 352.8 |  |  |  |  |  |
United Kingdom | — |  |  | 267.2 |  |  | — |  |  | 267.2 |  |  |  |  |  |
Angola | 210.9 |  |  | — |  |  | — |  |  | 210.9 |  |  |  |  |  |
Brazil | 195.0 |  |  | — |  |  | — |  |  | 195.0 |  |  |  |  |  |
Australia | 157.0 |  |  | 29.9 |  |  | — |  |  | 186.9 |  |  |  |  |  |
Other countries (1) | 164.9 |  |  | 335.3 |  |  | 71.2 |  |  | 571.4 |  |  |  |  |  |
| $ | 948.7 |  |  | $ | 659.6 |  |  | $ | 175.9 |  |  | $ | 1,784.2 |  |  |  |  |  |

(1)Other countries includes locations that individually contributed to less than 10% of total revenues.
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15. SUBSEQUENT EVENTS
Pending Business Combination with Transocean
On February 9, 2026, we entered into a business combination agreement (the "Business Combination Agreement") with Transocean Ltd., a Swiss corporation ("Transocean"). The Business Combination Agreement provides, among other things, and subject to the satisfaction or waiver of the conditions set forth therein, that Transocean will acquire Valaris in an all-stock transaction valued at approximately $5.8 billion (based on the price of Valaris common shares on the last trading day before the public announcement of the transaction). Under the terms of the Business Combination Agreement, holders of Valaris common shares will receive 15.235 shares of Transocean stock for each common share of Valaris. In addition, Warrants that are outstanding as of immediately prior to the transaction closing date will be assumed by Transocean and remain outstanding and be exercisable for the Fundamental Transaction Consideration (as defined in the Valaris Warrant Agreement dated as of April 30, 2021) multiplied by the number of Valaris common shares for which each warrant is exercisable immediately prior to the transaction closing date. 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. Upon completion and on a fully diluted basis assuming conversion to shares of Transocean’s exchangeable bonds due 2029, Transocean shareholders would own approximately 53% of the combined company, with Valaris shareholders owning the remaining 47%.
Completion of the business combination is subject to customary closing conditions, including (i) the receipt of the requisite approvals of the Valaris shareholders and the Transocean shareholders, (ii) the granting of the sanction order on terms consistent with the Business Combination Agreement, (iii) the Transocean shares issued pursuant to the Business Combination Agreement having been approved for listing on the NYSE, (iv) certain regulatory approvals having been obtained or any applicable waiting period having expired or been terminated, (v) no governmental authority within applicable jurisdictions having enacted or issued any law or order preventing or prohibiting the consummation of the business combination and (vi) the absence of a Transocean Material Adverse Effect or a Valaris Material Adverse Effect (as defined within the Business Combination Agreement). Under certain specified circumstances in which the Business Combination Agreement is terminated, we would be required to pay a termination fee equal to $173.0 million.
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures – We have established disclosure controls and procedures to ensure that the information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that such information is accumulated and made known to the officers who certify the Company’s financial reports and to other members of senior management and the board of directors as appropriate to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has concluded that our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, are effective.
Changes in Internal Controls – There were no material changes in our internal control over financial reporting during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.
Item 9B. Other Information
During the quarter ended December 31, 2025, no director or officer of the Company adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
132

PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item with respect to our directors, corporate governance matters, committees of the board of directors and Section 16(a) of the Exchange Act is contained in our Proxy Statement for the Annual General Meeting of Shareholders ("Proxy Statement") to be filed with the SEC not later than 120 days after the end of our fiscal year ended December 31, 2025 and incorporated herein by reference.
The information required by this item with respect to our executive officers is set forth in "Executive Officers" in Part I of this Annual Report on Form 10-K.
The guidelines and procedures of the board of directors are outlined in our Corporate Governance Policy. The committees of the board of directors operate under written charters adopted by the board of directors. The Corporate Governance Policy and committee charters are available on our website at www.valaris.com in the Governance Documents section and are available in print without charge by contacting our Investor Relations Department.
We have a Code of Conduct that applies to all directors and employees, including our principal executive officer, principal financial officer and principal accounting officer. The Code of Conduct is available on our website at www.valaris.com in the Governance Documents section and is available in print without charge by contacting our Investor Relations Department. We intend to disclose any amendments to or waivers from our Code of Conduct by posting such information on our website. Our Proxy Statement contains governance disclosures, including information on our Code of Conduct, our Corporate Governance Policy, the director nomination process, shareholder director nominations, shareholder communications to the board of directors and director attendance at the Annual General Meeting of Shareholders.
Item 11. Executive Compensation
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Equity Compensation Plan Information
The following table summarizes certain information related to our compensation plans under which our shares are authorized for issuance as of December 31, 2025:

Plan category |  | Number of securities to be issued upon exercise of outstanding options, warrants and rights |  | Weighted-average exercise price of outstanding options, warrants and rights |  | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(1)
|  | (a) |  | (b)(1) |  | (c)
Equity compensation plans approved by security holders |  | — |  |  | $ | — |  |  | — |
Equity compensation plans not approved by security holders (2) |  | 1,288,171 |  |  | — |  |  | 6,212,477 |
Total |  | 1,288,171 |  |  | $ | — |  |  | 6,212,477 |

(1)Restricted share units do not have an exercise price and, thus, are not reflected in this column.
(2)The number of awards granted for performance awards reflect the shares that would be issued if the target level of performance were to be achieved.
Additional information required by this item is included in our Proxy Statement and incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
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PART IV
Item 15. Exhibits, Financial Statement Schedules
(1) Index to Financial Statements

Included in Part II of this report: |
| Management's Report on Internal Control Over Financial Reporting | 76
| Reports of Independent Registered Public Accounting Firm (KPMG LLP, Houston, Texas, Auditor Firm ID: 185) | 77
| Consolidated Statements of Operations | 81
| Consolidated Statements of Comprehensive Income | 82
| Consolidated Balance Sheets | 83
| Consolidated Statements of Cash Flows | 84
| Notes to Consolidated Financial Statements | 85

(2) Financial Statement Schedules
All required schedules are omitted because they are either not applicable or the required information is shown in the financial statements or notes thereto.
135

(3) Exhibits

Exhibit Number |  | Exhibit |
2.1 |  | Business Combination Agreement, dated as of February 9, 2026, between Transocean Ltd. and Valaris Limited (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on February 10, 202 6, File No. 18097). |
3.1 |  | Memorandum of Association of Valaris Limited (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 18097). |
3.2 |  | Bye-laws of Valaris Limited (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097). |
4.1 |  | Indenture, dated April 19, 2023, among Valaris Limited, Valaris Finance Company LLC, the guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee and collateral agent (including the form of Second Lien Note attached thereto) (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on April 19, 2023, File No, 1-8097) |
4.2 |  | Warrant Agreement, dated as of April 30, 2021, by and between Valaris Limited and Computershare Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097). |
4.3 |  | Description of the Company’s Common Shares (incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K filed on February 22, 2022, File No. 001-08097). |
4.4 |  | Description of the Company’s Warrants (incorporated by reference to Exhibit 4.7 to the Registrant’s Annual Report on Form 10-K filed on February 22, 2022, File No. 001-08097). |
10.1 |  | Rowan Asset Transfer and Contribution Agreement, dated as of November 21, 2016, between Rowan Rex Limited and Saudi Aramco Development Company (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097). |
10.2 |  | Amendment No. 1 to Rowan Asset Transfer and Contribution Agreement, dated as of October 17, 2017, by and between Saudi Aramco Development Company, Rowan Rex Limited and Saudi Aramco Rowan Offshore Drilling Company (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097). |
10.3 |  | Shareholders’ Agreement dated 21 November 2016 (G) between Saudi Aramco Development Company and Rowan Rex Limited Relating to the Offshore Drilling Joint Venture (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097). |
10.4 |  | Amendment No. 1 to the Shareholders' Agreement dated December 18, 2017 between Saudi Aramco Development Company, Rowan Rex Limited and ARO (incorporated by reference to Exhibit 10.17 to the Registrant's Annual Report filed on Form 10-K on March 2, 2021). |
10.5 |  | Amendment No. 2 to the Shareholders' Agreement dated June 28, 2018 between Saudi Aramco Development Company, Rowan Rex Limited, ARO and Mukamala Oil Field Services Limited (incorporated by reference to Exhibit 10.18 to the Registrant's Annual Report filed on Form 10-K on March 2, 2021). |
10.6 |  | Amendment No. 3 to the Shareholders' Agreement dated August 13, 2020 between Rowan Rex Limited, Mukamala Oil Field Services Limited and ARO (incorporated by reference to Exhibit 10.19 to the Registrant's Annual Report filed on Form 10-K on March 2, 2021) |
10.7 |  | Amendment No. 4 to the Shareholders' Agreement dated December 1, 2020 between Rowan Rex Limited, ARO and Mukamala Oil Field Services Limited (incorporated by reference to Exhibit 10.20 to the Registrant's Annual Report filed on Form 10-K on March 2, 2021) |
+10.8 |  | ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004) (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097). |
+10.9 |  | Amendment No. 1 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated March 11, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097). |

136

Exhibit Number |  | Exhibit |
+10.10 |  | Amendment No. 2 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated November 4, 2008 (incorporated by reference to Exhibit 10.57 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097). |
+10.11 |  | Amendment No. 3 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated August 4, 2009 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097). |
+10.12 |  | Amendment No. 4 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated December 22, 2009 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097). |
+10.13 |  | Amendment No. 5 to the Ensco Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated May 14, 2012 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097). |
+10.14 |  | Amendment No. 6 to the ENSCO Supplemental Executive Retirement Plan (as Amended and Restated Effective January 1, 2004), effective as of July 1, 2021, by ENSCO International Incorporated (incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report filed on Form 10-Q on August 3, 2021, File No. 1-8097). |
+10.15 |  | ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 4, 2008 (incorporated by reference to Exhibit 10.56 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097). |
+10.16 |  | Amendment No. 1 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated August 4, 2009 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097). |
+10.17 |  | Amendment No. 2 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 3, 2009 (incorporated by reference to Exhibit 10.31 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-8097). |
+10.18 |  | Amendment No. 3 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated December 22, 2009 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097). |
+10.19 |  | Amendment No. 4 to the Ensco 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 14, 2012 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097). |
+10.20 |  | Amendment No. 5 to the Ensco 2005 Amended and Restated Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 21, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 24, 2013, File No. 1-8097). |
+10.21 |  | Amendment No. 6 to the ENSCO 2005 Supplemental Executive Retirement Plan (as amended and restated effective January 1, 2005), dated December 19, 2019. (incorporated by reference to Exhibit 10.28 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2019, File No. 1-8097). |
+10.22 |  | Amendment No. 7 to the ENSCO 2005 Supplemental Executive Retirement Plan (as Amended and Restated Effective January 1, 2005), effective as of July 1, 2021, by ENSCO International Incorporated (incorporated by reference to Exhibit 10.8 to the Registrant’s Quarterly Report filed on Form 10-Q on August 3, 2021, File No. 1-8097). |
+10.23 |  | ENSCO 2005 Benefit Reserve Trust, effective January 1, 2005 (incorporated by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K filed on January 5, 2005, File No. 1-8097). |
+10.24 |  | Restoration Plan of Rowan Companies, Inc. (as amended and restated effective January 1, 2013), incorporated by reference to Exhibit 10.7 to Rowan's Annual Report on Form 10-K for the year ended December 31, 2016 (File No. 1-5491). |
+10.25 |  | Valaris Cash Incentive Plan (incorporated by reference to Exhibit 10.8 to the Registrant's Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097) |
+10.26 |  | Valaris Limited 2021 Management Incentive Plan (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097). |
+10.27 |  | Form of Director RSU Agreement (incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q filed on November 2, 2021, File No. 1-8097). |

137

Exhibit Number |  | Exhibit |
+10.28 |  | Form of Change in Control Severance Agreement for Executive Officers (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q filed on April 28, 2016, File No. 1-8097). |
10.29 |  | Equity Registration Rights Agreement, dated as of April 30, 2021, by and among Valaris Limited and the holders party thereto (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on April 30, 2021, File No. 1-8097). |
10.30 |  | Support Agreement, dated as of December 9, 2021, among Valaris Limited, Famatown Financial Limited and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 10, 2021, File No. 1-8097). |
10.31 |  | Amendment No. 1 to Support Agreement dated as of January 25, 2023, among Valaris Limited, Famatown Financial Limited and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 27, 2023, File No. 1-8097). |
+10.32 |  | Amended and Restated Valaris Executive Severance Plan, dated as of April 14, 2022 (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on August 2, 2022, File No. 1-8097). |
+10.33 |  | Employment Agreement, effective as of December 8, 2021, by and between Anton Dibowitz, Ensco Corporate Resources LLC and Valaris Limited (incorporated by reference to Exhibit 10.43 to the Registrant’s Annual Report on Form 10-K filed on February 22, 2022, File No. 001-08097). |
+10.34 |  | Employment Agreement, commencing as of September 24, 2022, by and between Ensco Services Limited and Matthew Lyne (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on November 1, 2022, File No. 1-8097). |
+10.35 |  | Form of Indemnification Agreement, by and between Valaris and its officers and directors (incorporated by reference to Exhibit 10.37 to the Registrant's Amendment No. 1 to its Registration Statement on Form S-1 filed on June 14, 2021, File No. 001-08097). |
+10.36 |  | 2023 Form of PSU Award Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on May 2, 2023, File No. 001-8097). |
+10.37 |  | 2023 Form of RSU Award Agreement (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed on May 2, 2023, File No. 001-8097). |
+10.38 |  | 2024 Form of PSU Award Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on May 2, 2024, File No. 001-08097). |
+10.39 |  | 2024 Non-Employee Director Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on August 1, 2024, File No. 001-08097). |
+10.40 |  | First Amendment to Senior Secured Revolving Credit Facility Agreement, dated August 27, 2025, by and among the Company, Citibank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on October 3 0, 202 5, File No. 001-08097). |
10.41 |  | Credit Agreement, dated April 3, 2023, among Valaris Limited, Citibank, N.A., as administrative agent, Wilmington Savings Fund Society, FSB, as collateral trustee, the issuing banks party thereto and Citibank, N.A., Deutsche Bank Securities Inc. and DNB Markets, Inc., as joint lead arrangers and lead bookrunners (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed on May 2, 2023, File No. 001-8097). |
10.42 |  | Collateral Trust Agreement, dated April 19, 2023, by and among Valaris Limited, Valaris Finance Company LLC, the guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee and collateral agent (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filled on April 19, 2023, File No, 1-8097). |
19.1 |  | Valaris Securities Trading Policy (incorporated by reference to Exhibit 19.1 to the Registrant's Annual Report filed on Form 10-K on February 20, 2025, File No., 1-8097). |
*21.1 |  | Subsidiaries of the Registrant |
*23.1 |  | Consent of Independent Registered Public Accounting Firm. |
*31.1 |  | Certification of the Chief Executive Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
*31.2 |  | Certification of the Chief Financial Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |

138

Exhibit Number |  | Exhibit |
**32.1 |  | Certification of the Chief Executive Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
**32.2 |  | Certification of the Chief Financial Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
97.1 |  | Valaris Limited Clawback Policy (incorporated by reference to Exhibit 97.1 to the Registrant's Annual Report filed on Form 10-K on February 22, 2024). |
*101.INS |  | XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
*101.SCH |  | Inline XBRL Taxonomy Extension Schema Document |
*101.CAL |  | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
*101.DEF |  | Inline XBRL Taxonomy Extension Definition Linkbase Document |
*101.LAB |  | Inline XBRL Taxonomy Extension Label Linkbase Document |
*101.PRE |  | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
*104 |  | The cover page of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, formatted in Inline XBRL (included with Exhibit 101 attachments). |
* ** + |  | Filed herewith. Furnished herewith. Management contracts or compensatory plans and arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. |

Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10% of our total assets on a consolidated basis. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.
Item 16. Form 10-K Summary
None.
139

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on February 20, 2026.

Valaris Limited (Registrant)
By /s/ ANTON DIBOWITZ Anton Dibowitz Director, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

Signatures |  | Title |  | Date
/s/ ANTON DIBOWITZ Anton Dibowitz |  | Director, President and Chief Executive Officer (principal executive officer) |  | February 20, 2026
/s/ CHRISTOPHER T. WEBER Christopher T. Weber |  | Senior Vice President and Chief Financial Officer (principal financial officer) |  | February 20, 2026
/s/ MELISSA BARRON Melissa Barron |  | Controller (principal accounting officer) |  | February 20, 2026
/s/ ELIZABETH D. LEYKUM Elizabeth D. Leykum |  | Chair of the Board |  | February 20, 2026
/s/ DICK FAGERSTAL Dick Fagerstal |  | Director |  | February 20, 2026
/s/ JOSEPH GOLDSCHMID Joseph Goldschmid |  | Director |  | February 20, 2026
/s/ CATHERINE HUGHES Catherine Hughes |  | Director |  | February 20, 2026
/s/ KRISTIAN JOHANSEN Kristian Johansen |  | Director |  | February 20, 2026

140