# Valaris Ltd (VAL) Informational only - not investment advice. CIK: 0000314808 SIC: 1381 Drilling Oil & Gas Wells SIC breadcrumb: [Mining](/division/B/) > [SIC Major Group 13](/major-group/13/) > [SIC 1381 Drilling Oil & Gas Wells](/industry/1381/) Latest 10-K filed: 2026-02-20 SEC page: https://www.sec.gov/edgar/browse/?CIK=314808 Filing source: https://www.sec.gov/Archives/edgar/data/314808/000031480826000029/val-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 2369000000 | USD | 2025 | 2026-02-20 | | Net income | 982800000 | USD | 2025 | 2026-02-20 | | Assets | 5304800000 | USD | 2025 | 2026-02-20 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-20. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000314808.json. Derived margins are computed from the extracted annual SEC facts. | Metric | 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | | | | | | 2,776,400,000 | 1,843,000,000 | 1,705,400,000 | 2,053,200,000 | 1,427,200,000 | | 1,602,500,000 | 1,784,200,000 | 2,362,600,000 | 2,369,000,000 | | Net income | | | | | -1,594,800,000 | 890,200,000 | -303,700,000 | -639,700,000 | -198,000,000 | -4,855,500,000 | | 176,500,000 | 865,400,000 | 373,400,000 | 982,800,000 | | Operating income | | | | | -1,243,500,000 | 929,300,000 | -132,000,000 | -235,900,000 | -669,800,000 | -4,334,500,000 | | 37,200,000 | 53,500,000 | 352,300,000 | 477,000,000 | | Diluted EPS | 3.08 | 5.04 | 6.07 | -16.88 | -6.88 | | | | | -24.42 | | 2.33 | 11.51 | 5.12 | 13.86 | | Assets | | | | | | 14,374,500,000 | 14,625,900,000 | 14,023,700,000 | 16,931,200,000 | 12,873,200,000 | 2,595,600,000 | 2,860,300,000 | 4,322,200,000 | 4,419,800,000 | 5,304,800,000 | | Liabilities | | | | | | | | | | | | 1,562,400,000 | 2,325,200,000 | 2,175,500,000 | 2,133,100,000 | | Stockholders' equity | | | | | | 8,250,600,000 | 8,732,100,000 | 8,091,400,000 | 9,310,900,000 | 4,374,600,000 | 1,095,900,000 | 1,289,900,000 | 1,987,600,000 | 2,238,500,000 | 3,169,600,000 | | Cash and cash equivalents | | | | | | 1,159,700,000 | 445,400,000 | 275,100,000 | 97,200,000 | 325,800,000 | 607,600,000 | 724,100,000 | 620,500,000 | 368,200,000 | 599,400,000 | | Net margin | | | | | | 32.06% | -16.48% | -37.51% | -9.64% | | | 11.01% | 48.50% | 15.80% | 41.49% | | Operating margin | | | | | | 33.47% | -7.16% | -13.83% | -32.62% | | | 2.32% | 3.00% | 14.91% | 20.14% | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-05. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000314808.json. Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-06-30 | | | 1.48 | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | 0.98 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | 0.61 | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 415,200,000 | -29,400,000 | -0.39 | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 455,100,000 | 12,900,000 | 0.17 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 483,800,000 | 835,200,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 525,000,000 | 25,500,000 | 0.35 | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 610,100,000 | 149,600,000 | 2.03 | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 643,100,000 | 64,600,000 | 0.88 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 584,400,000 | 133,700,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 620,700,000 | -37,900,000 | -0.53 | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 615,200,000 | 115,100,000 | 1.61 | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 595,700,000 | 188,100,000 | 2.65 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 537,400,000 | 717,500,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 465,400,000 | -16,400,000 | -0.24 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/314808/000031480826000103/val-20260331.htm Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high Filing date: 2026-05-05 Report date: 2026-03-31 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and related notes thereto included in "Item 1. Financial Statements" and with our annual report on Form 10-K for the year ended December 31, 2025. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A of our annual report and elsewhere in this quarterly report. See “Forward-Looking Statements.” EXECUTIVE SUMMARY 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 May 5, 2026, we own 45 rigs, including 13 drillships, one semisubmersible rig, 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. Pending Business Combination with Transocean On February 9, 2026, Valaris and Transocean Ltd. ("Transocean"), 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 common share (the "Business Combination"). 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%. The completion of the Business Combination is subject to customary closing conditions, including shareholder and regulatory approvals. See "Note 1 - Unaudited Condensed Consolidated Financial Statements - Pending Business Combination with Transocean" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for information regarding the Business Combination. Our Industry The offshore drilling industry is cyclical and primarily influenced by global energy demand, oil and gas supply dynamics, geopolitical factors 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 began the year in a period of oversupply, the current conflicts in the Middle East have constrained supply and increased uncertainty and volatility in global energy markets. It has also reinforced the strategic importance of energy security and market participants generally expect the global oil and gas market to tighten 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. 27 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 65% of this expected activity is associated with projects with breakeven oil prices below $50 per barrel and approximately 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. Conflicts in the Middle East Our operations and assets located in the Middle East have recently been subject to elevated geopolitical risk due to ongoing conflicts and military activity in the region. As a result of the conflicts, during the first quarter of 2026 we experienced impacts, including operational downtime at reduced rates, delays in shipyard projects and higher operating costs. ARO also experienced similar impacts in the region. For our operations, the financial impact in the first quarter was $7.5 million, primarily associated with incremental costs to maintain insurance coverage for war-related risks for jackups that we operate in the region. The geopolitical environment in the Middle East remains volatile, and if the conflicts persist or escalate, including an expansion of hostilities, the negative impact on our operating income could be significantly higher than amounts incurred to date and could also adversely affect the operating performance of ARO. An escalation of conflict could result in additional military actions, economic sanctions or other governmental measures, including disruptions to regional ports or restrictions on maritime traffic through key waterways such as the Strait of Hormuz. Continued disruptions or closures affecting the Strait of Hormuz, through which a substantial portion of the region’s maritime traffic and energy‑related logistics transit, could materially affect our ability, and that of ARO, to mobilize assets, transport personnel and supplies, or perform drilling and related services in a timely and cost‑effective manner. In addition, any such escalation could lead to further increases in insurance premiums, reductions in coverage limits or scope or the unavailability of coverage, as well as limitations on vessel access or port services, delays in customs and regulatory approvals, supply chain disruptions and increased security‑related expenditures. These risks could result in prolonged rig downtime, including for rigs operated by ARO, contract suspensions or terminations, delayed commencement of contracted operations, loss of revenue, impairment of assets or additional force majeure claims by us or our customers. Ongoing or future instability in the region, including actions taken in response to geopolitical developments, could materially and adversely affect our operating costs, financial condition, and results of operations. 28 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 Condensed 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 condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information. The following table summarizes our and 100% of ARO's contract backlog of business as of May 4, 2026 and February 17, 2026 (in millions): May 4, 2026 February 17, 2026 Floaters (1) $ 3,319.8  $ 3,030.8  Jackups 1,135.6  1,125.8  Other (2) 473.7  515.7  Total $ 4,929.1  $ 4,672.3  ARO $ 1,916.7  $ 2,011.3  (1)The increase for Floaters is primarily due to a contract extension for VALARIS DS-4, which resulted in incremental aggregate backlog of approximately $426.0 million, partially offset by revenues realized. (2)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. BUSINESS ENVIRONMENT Floaters Within the floater segment, utilization for the global marketed drillship fleet was approximately 92% as of March 31, 2026 and included 12 drillships across the industry which were not working at quarter-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 this year following idle periods between contracts. Some customers continue to favor more technically capable and efficient assets particularly to support complex deepwater developments. Seventh-generation drillships may be preferred and 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 with 12 of 13 of our drillships being seventh-generation units, although we continue to face competition from other types of floaters, including those of older generations. Utilization for benign environment semisubmersibles, such as the remaining semisubmersible in our active fleet, continues to be lower than for drillships. In response to this environment, we retired three benign environment semisubmersibles in 2025 and sold VALARIS DPS-1 for recycling in April 2026. 29 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 March 31, 2026. This decrease is primarily attributable [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high 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. 51 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. 52 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. 53 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. 54 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. 55 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. 56 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. 57 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. 58 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. 59 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  60 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. 61 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. 62 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. 63 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. 64 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. 65 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. 66 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. 67 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. 68 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  69 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. 70 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. 71 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. 72 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. 73 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. 74 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.