SEADRILL Ltd (SDRL)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with the unaudited Condensed Consolidated Financial Statements and related notes included in Part I, Item 1. "Financial Statements" of this Quarterly Report on Form 10-Q, as well as the Consolidated Financial Statements and related notes included in our 2025 10-K.

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 Part I, Item 1A. of our 2025 10-K and "Forward-Looking Statements" in this Quarterly Report on Form 10-Q.

Our Business

We are an offshore drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership and operation of drillships and semi-submersible rigs for operations in shallow to ultra-deepwater in both benign and harsh environments. We contract our drilling units to drill wells for our customers on a dayrate basis. Our customers include oil super-majors, state-owned national oil companies and independent oil and gas companies. In addition, we provide management services to certain affiliated entities.

As of March 31, 2026, we owned a total of 15 drilling rigs. In addition to our owned assets, as of March 31, 2026, we managed two 7th generation drillships owned by Sonangol EP.

Significant Developments

Oil price volatility

The price of oil has experienced increased volatility and has risen in response to the ongoing conflicts in the Middle East, including the current conflict in Iran, which started on February 28, 2026, and the unprecedented closure of the Strait of Hormuz. The Brent oil price was $71 per barrel on February 27, 2026 and increased to an average price of approximately $103 per barrel for the month of March 2026. We continue to evaluate and monitor the impacts of the recent oil price volatility and the ongoing conflicts in the Middle East on our business and operations; however, it is not possible to predict the long-term impact, if any, of the disruptions to commodity prices, global energy supplies, energy markets and economic conditions, on our business and operations.

U.S. global trade policy changes

Ongoing and recently proposed changes to U.S. global trade policy, along with potential international retaliatory measures, have continued to cause high volatility in global markets and uncertainty around short- and long-term economic impacts in the U.S., including concerns over inflation, recession and slowing growth. We continue to evaluate and monitor the potential impacts of these changes and measures, including the imposition of tariffs and ongoing legal challenges to such tariffs, on our business and operations; however, it is not possible to predict the impact, if any, of any changes or proposed changes to the U.S. global trade policy, or any international retaliatory measures, on our business and operations.

Contract Backlog

Contract backlog includes all firm contracts at the contractual operating dayrate multiplied by the number of days remaining in the firm contract period. For contracts which include a market indexed rate mechanism, we utilize the current applicable dayrate multiplied by the number of days remaining in the firm contract period. Contract backlog includes management contract revenues and leasing revenues from bareboat charter arrangements, denoted as "other" in the tables below. Contract backlog excludes revenues for mobilization, demobilization and contract preparation or other incentive provisions and excludes backlog relating to non-consolidated entities.

The contract backlog for our fleet was as follows as of the dates specified:

Our contract backlog includes only firm commitments represented by signed drilling contracts. The full contractual operating dayrate may differ from the actual dayrate we ultimately receive. For example, an alternative contractual dayrate, such as a waiting‑on‑weather rate, repair rate, standby rate or force majeure rate, may apply under certain circumstances. The contractual operating dayrate may also differ from the actual dayrate we ultimately receive because of several other factors, including rig downtime or suspension of operations. In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period.

We estimate the March 31, 2026 contract backlog to be realized over the following periods:

(1) Remainder of 2026.

14

The actual amount of revenues earned and the actual periods during which revenues are earned will differ from the amounts and periods shown in the tables above due to various factors, including shipyard and maintenance, surveys, upgrades and regulatory projects, unplanned downtime and other factors that result in a lower applicable dayrate than the full contractual operating dayrate. Additional factors that could affect the amount and timing of actual revenue to be recognized include customer liquidity issues and contract terminations, which are available to our customers under certain circumstances.

Business Environment

The table below shows the average oil price for the three months ended March 31, 2026 and year ended December 31, 2025. The Brent oil price as of May 6, 2026 was $101/bbl.

Source: Bloomberg

In recent years, oil prices have generally remained at levels that support offshore exploration and development activity, where global rig demand has been steady. This level of demand was sustained by the combination of commodity prices, heightened focus on energy security, and relative attractiveness of offshore plays with respect to both cost and carbon emissions. Recently, however, the ongoing conflict in Iran and the unprecedented closure of the Strait of Hormuz have caused significant disruption in the normal flow of oil, refined petroleum products, and related commodities, resulting in higher oil prices.

The price of Brent oil averaged $78 per barrel during the three months ended March 31, 2026 up from $68 per barrel in 2025, driven primarily by ongoing conflicts in the Middle East that disrupted global oil supply during the first quarter of 2026.

Uncertainty persists in the market, particularly in light of concerns over global economic conditions (including the current conflict in Iran), government trade policies and output increases by the Organization of the Petroleum Exporting Countries and other major international producers. This has led to the continued deferral of offshore capital expenditures and could have a negative impact on near-term future demand for offshore drilling services. In addition, inflationary pressures may impact the cost base in our industry, including personnel costs and the prices of goods and services required to reactivate or operate rigs.

As global tendering activity accelerates, we see signs that point towards a market recovery in 2027. In addition, we believe oil majors are calling for renewed focus on large-scale exploration and investment, and there is also growing consensus that U.S. shale production is plateauing. As a result, with projections of growing oil and gas demand and the lagging energy transition, operators are pivoting back towards deepwater exploration in order to replace reserves and sustain production growth.

The table below shows the global number of rigs on contract and marketed utilization for the three months ended March 31, 2026 and year ended December 31, 2025:

Source: RigLogix

Global benign-environment floaters

Marketed utilization and the number of contracted rigs remained relatively consistent in the three months ended March 31, 2026 compared to the year ended December 31, 2025.

Global harsh environment units

Marketed utilization for harsh environment floaters improved in the three months ended March 31, 2026 compared to the year ended December 31, 2025, whereas utilization for harsh environment jackups remained consistent over the same periods, reflecting continued demand for high-specification assets.

15

Results of operations

Results for the three months ended March 31, 2026 and March 31, 2025

The tables included below set out financial information for the three months ended March 31, 2026 and March 31, 2025:

1) Operating revenues

Operating revenues consist of contract revenues, reimbursable revenues, management contract revenues, leasing revenues and other revenues.

a) Contract revenues

Contract revenues represent the revenues we earn from contracting our drilling units to customers, primarily on a dayrate basis, and are predominately driven by the average number of rigs under contract during a period, the average dayrates earned and economic utilization achieved by those rigs under contract. We have set out movements in these key indicators of performance in the sections below.

i.Average number of rigs on contract

We calculate the average number of rigs on contract by dividing the aggregate days our rigs (excluding managed rigs) were on contract during the reporting period by the number of days in that reporting period.

The average number of rigs on contract remained consistent at nine in each of the three months ended March 31, 2026 and 2025; however, there was a de

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

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

In this section, we present management’s discussion and analysis of results of operations and financial condition. It should be read in conjunction with our Consolidated Financial Statements and accompanying notes thereto included in this annual report for the year ended December 31, 2025. You should also carefully read the following sections of this annual report entitled "Forward-Looking Statements," Part I, Item 1, "Business" and Part I, Item 1A, "Risk Factors".

The discussion of our results of operations and liquidity in this section includes comparisons for the years ended December 31, 2025 and December 31, 2024. For a similar discussion, including comparisons for the years ended December 31, 2024 and December 31, 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 27, 2025.

Introduction

Seadrill Limited (along with any one or more of its consolidated subsidiaries, or to all such entities, referred to as "Seadrill", "we", "us", "our", and "the Company") is an offshore drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership and operation of drillships and semi-submersible rigs for operations in shallow to ultra-deepwater in both benign and harsh environments. We contract our drilling units to drill wells for our customers on a dayrate basis. Our customers include oil super-majors, state-owned national oil companies, and independent oil and gas companies. In addition, we provide management services to certain affiliated entities.

As of December 31, 2025, we owned a total of 15 drilling units, of which 10 were operating, one was undergoing capital upgrade projects for a contract commencing in the second quarter of 2026, one was undergoing repairs and maintenance projects and three were cold stacked. The 10 operating units include nine benign floaters (comprising six 7th generation drillships, two 6th generation drillships and one benign environment semi-submersible) and one harsh environment jackup. In addition to our owned assets, as of December 31, 2025, we managed two drilling units owned by Sonangol.

For a detailed description of our business, please read Part I, Item 1, "Business".

Significant Developments

U.S. global trade policy changes

Ongoing and recently proposed changes to U.S. global trade policy, along with potential international retaliatory measures, have continued to cause high volatility in global markets and uncertainty around short- and long-term economic impacts in the U.S., including concerns over inflation, recession and slowing growth. We continue to evaluate and monitor the potential impacts of these changes and measures, including the imposition of tariffs and any legal challenges to such tariffs, on our business and operations; however, it is not possible to predict the impact, if any, of any changes or proposed changes to the U.S. global trade policy, or any international retaliatory measures, on our business and operations.

Market Overview and Trends

The below table shows the average annual oil price over the period from 2021 to 2025. The Brent oil price on February 20, 2026 was $72.23.

Source: Bloomberg

In recent years, oil prices have generally remained at levels that support offshore exploration and development activity, where global rig demand has been steady. This level of demand was sustained by the combination of commodity prices, heightened focus on energy security, and relative attractiveness of offshore plays with respect to both cost and carbon emissions.

The price of Brent oil averaged $68 per barrel in 2025, down from $80 per barrel in 2024. Global growth in oil production and slower growth in demand have put downward pressure on prices.

Uncertainty persists in the market, particularly in light of concerns over global economic conditions, government trade policies and output increases by the OPEC and other major international producers. This has led to the continued deferral of offshore capital expenditures and contracting of offshore drilling services and could have a negative impact on near-term future demand for offshore drilling services. In addition, inflationary pressures may impact the cost base in our industry, including personnel costs and the prices of goods and services required to reactivate or operate rigs. As anticipated, 2025 was a year marked by softer utilization and a corresponding increase in competition, placing downward pressure on near term dayrates; however, as global tendering activity accelerates, we see signs that point towards a market recovery in 2027. In addition, we believe oil majors are calling for renewed focus on large-scale exploration and investment, and there is also growing consensus that U.S. shale production is plateauing. As a result, with projections of growing oil and gas demand and the lagging energy transition, operators are pivoting back towards deepwater exploration in order to replace reserves and sustain production growth.

36

The below table shows the global number of rigs on contract and marketed utilization for the years ended December 31, 2025 and December 31, 2024:

Source: RigLogix

Global benign environment floaters

Marketed utilization decreased in 2025 compared to the prior year, mainly due to fewer contracted floaters, which were primarily benign environment semi-submersibles.

Global harsh environment units

Marketed utilization for harsh environment floaters and jackups declined in 2025 compared to the prior year, primarily reflecting reduced capital spending on drilling activities.

Changes to our fleet

The below table shows the number of owned drilling units included in our fleet for each of the periods covered by this report:

The decrease in benign environment jackup rigs during 2024 was due to the disposal of the West Castor, West Tucana, West Telesto and West Prospero.

The below table shows the number of managed drilling units included in our fleet for each of the periods covered by this report:

Contract backlog

Contract backlog includes all firm contracts at the contractual operating dayrate multiplied by the number of days remaining in the firm contract period. For contracts which include a market indexed rate mechanism, we utilize the current applicable dayrate multiplied by the number of days remaining in the firm contract period. Contract backlog includes management contract revenues and leasing revenues from bareboat charter arrangements, denoted as "other" in the tables below. Contract backlog excludes revenues for mobilization, demobilization and contract preparation or other incentive provisions and excludes backlog relating to non-consolidated entities.

37

The contract backlog for our fleet was as follows as of the dates specified:

Our contract backlog includes only firm commitments represented by signed drilling contracts. The full contractual operating dayrate may differ from the actual dayrate we ultimately receive. For example, an alternative contractual dayrate, such as a waiting‑on‑weather rate, repair rate, standby rate or force majeure rate, may apply under certain circumstances. The contractual operating dayrate may also differ from the actual dayrate we ultimately receive because of several other factors, including rig downtime or suspension of operations. In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period.

We estimate the December 31, 2025 contract backlog to be realized over the following periods:

The actual amounts of revenues earned and the actual periods during which revenues are earned will differ from the amounts and periods shown in the tables above due to various factors, including shipyard and maintenance, survey, upgrade and regulatory projects, unplanned downtime and other factors that result in lower applicable dayrates than the full contractual operating dayrate. Additional factors that could affect the amount and timing of actual revenue to be recognized include customer liquidity issues and contract terminations, which are available to our customers under certain circumstances.

RESULTS OF OPERATIONS

The tables included below set out financial information for the years ended December 31, 2025 and December 31, 2024.

38

1) Operating revenues

Operating revenues consist of contract revenues, reimbursable revenues, management contract revenues, leasing revenues and other revenues.

a) Contract revenues

Contract revenues represent the revenues we earn from contracting our drilling units to customers, primarily on a dayrate basis, and are predominately driven by the average number of rigs under contract during a period, the average dayrates earned and economic utilization achieved by those rigs under contract. We have set out movements in these key indicators of performance in the sections below.

i.Average number of rigs on contract

We calculate the average number of rigs on contract by dividing the aggregate days our rigs (excluding managed rigs) were on contract during the reporting period by the number of days in that reporting period.

The average number of rigs on contract increased to 10 in the year ended December 31, 2025 from nine in the year ended December 31, 2024, resulting in a $27 million increase in contract revenues in the year ended December 31, 2025 compared to the year ended December 31, 2024.

The increase was primarily related to the West Auriga and West Polaris having commenced work in Brazil in December 2024 and February 2025, respectively, and therefore, were operating for more days during the year ended December 31, 2025, compared to the year ended December 31, 2024, along with the Sevan Louisiana and West Neptune operating for more days during the year ended December 31, 2025 due to special periodic survey activities during the year ended December 31, 2024.

The increase was partially offset by the impact of the West Phoenix and West Capella being stacked for the majority of the year ended December 31, 2025, compared to operating for most of the year ended December 31, 2024.

ii.Average contractual dayrates

We calculate the average contractual dayrate by dividing the aggregate contractual dayrates during a reporting period by the aggregate number of days for the reporting period.

The average contractual dayrate earned for the year ended December 31, 2025 was $326 thousand, compared to $296 thousand for the year ended December 31, 2024, resulting in a $75 million increase in contract revenues in the year ended December 31, 2025 compared to the year ended December 31, 2024.

The increase was driven by higher-than-average dayrates for the West Neptune and West Vela operating in the U.S. Gulf, the West Auriga and West Polaris operating in Brazil, and the West Elara operating in Norway during the year ended December 31, 2025, compared to the year ended December 31, 2024. These impacts were partially offset by higher-than-average dayrates for the West Phoenix and West Capella during the year ended December 31, 2024, in contrast to the year ended December 31, 2025, during which such rigs were predominately not on contract.

iii.Economic utilization for rigs on contract

We define economic utilization as dayrate revenue earned during the period, excluding bonuses, divided by the contractual operating dayrate multiplied by the number of days on contract in the period. If a drilling unit earns its full operating dayrate throughout a reporting period, its economic utilization would be 100%. However, there are many situations that give rise to a dayrate being earned that is less than the contractual operating rate, such as planned downtime for maintenance. In such situations, economic utilization reduces below 100%.

The economic utilization was 90% for the year ended December 31, 2025, compared to 95% for the year ended December 31, 2024, resulting in a $37 million decrease in contract revenues in the year ended December 31, 2025 compared to the year ended December 31, 2024. The decrease during the year ended December 31, 2025 was primarily due to unplanned downtime related to regulatory matters impacting the West Tellus and downtime on the West Polaris, West Auriga, West Elara, West Carina and Sevan Louisiana, partially offset by improved economic utilization on the West Neptune, West Saturn and West Jupiter compared to the year ended December 31, 2024.

iv. Deferred mobilization revenues

We receive fees for the mobilization of our rigs, where the associated revenue is recognized ratably over the expected term of the related drilling contract. As a result, we record a contract liability for mobilization fees received, which is amortized ratably to contract revenues as services are rendered over the initial term of the related drilling contract.

The amortization of deferred mobilization revenues increased by $27 million during the year ended December 31, 2025, compared to the year ended December 31, 2024. The increase was primarily attributable to mobilization fees received on the West Capella, West Polaris and West Auriga, which commenced operations within the last 13 months.

39

v. Other items

Contract revenues include add-on services and performance bonuses.

There was a decrease in contract revenues, from add-on services and performance bonuses of $12 million during the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily attributable to the West Phoenix earning revenues from add-on services and a performance bonus during the year ended December 31, 2024, which did not recur during the year ended December 31, 2025.

b) Reimbursable revenues

We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel and other services provided at their request in accordance with a drilling contract. We classify such revenues as reimbursable revenues.

For the years ended December 31, 2025 and December 31, 2024, reimbursable revenues primarily related to rigs managed for the Sonadrill joint venture for long term maintenance projects on the Libongos and Quenguela, along with some reimbursable revenues related to services provided across various customers.

The $12 million decrease for the year ended December 31, 2025 compared to the year ended December 31, 2024 was primarily due to reduced reimbursable services provided to the Libongos and Quenguela for long-term maintenance during the year ended December 31, 2025, compared to the year ended December 31, 2024.

c) Management contract revenues

Management contract revenues include revenues related to contracts where we provide management, operational and technical support services and are comprised of revenues from our joint venture, Sonadrill, relating to the Libongos, Quenguela and West Gemini.

Management contract revenues for the year ended December 31, 2025 increased by $7 million compared to the year ended December 31, 2024, primarily driven by higher management fees and add-on services on the three managed rigs.

Refer to Note 21 - "Related party transactions" for further details.

d) Leasing revenues

Leasing revenues relate to the charter of the West Gemini to Sonadrill and the West Castor, West Telesto and West Tucana to Gulfdrill prior to their disposal in June 2024.

Leasing revenues decreased by $21 million for the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily attributable to the disposal of the Gulfdrill rigs in June 2024.

Refer to Note 21 - "Related party transactions" for further details.

2) Operating expenses

Total operating expenses include vessel and rig operating expenses, reimbursable expenses, depreciation of drilling units and equipment, amortization of intangibles, management contract expenses, merger and integration related expenses, and selling, general and administrative expenses.

i.Vessel and rig operating expenses

Vessel and rig operating expenses represent the costs we incur to operate a drilling unit that is either in operation or stacked. This includes the remuneration of offshore crews, rig supplies, expenses for repair and maintenance, onshore support costs, and the amortization of deferred mobilization costs. Vessel and rig operating expenses are mainly driven by rig activity. On average, we incur higher vessel and rig operating expenses when a rig is operating compared to when it is stacked. For stacked rigs, we incur higher vessel and rig expenses for warm stacked rigs compared to cold stacked rigs. We incur one-time costs for activities such as preservation and severance when we cold stack a rig. We also incur significant costs when re-activating a rig from cold stack, a proportion of which is expensed as incurred. Where a rig is leased to another operator, the majority of vessel and rig expenses are incurred by the operator.

40

Vessel and rig operating expenses increased by $55 million during the year ended December 31, 2025 compared to the year ended December 31, 2024. During the year ended December 31, 2025, there was a $155 million increase in vessel and rig operating expenses compared to the year ended December 31, 2024, primarily related to the West Auriga and West Polaris commencing operations in Brazil, of which $43 million related to increased amortization of deferred mobilization costs, along with higher repair and maintenance costs across the fleet. This was partially offset by a $73 million decrease in vessel and rig operating expenses during the year ended December 31, 2025 primarily related to the West Phoenix and West Capella, which were stacked for the majority of the year ended December 31, 2025, and lower managed service agreement fees of $27 million, as the rigs acquired through the Aquadrill transaction are now managed by Seadrill, rather than by third parties.

ii.Depreciation and amortization

The $70 million increase in depreciation and amortization for the year ended December 31, 2025 compared to the year ended December 31, 2024 was mainly attributable to the capital projects on the West Auriga and West Polaris and unfavorable contracts being fully amortized during 2024.

Depreciation of drilling units and equipment

Depreciation increased by $60 million in the year ended December 31, 2025 compared to the year ended December 31, 2024, mainly attributable to the capital projects on the West Auriga and West Polaris related to their respective contracts in Brazil.

Amortization of intangibles

Amortization expense increased by $10 million during the year ended December 31, 2025 compared to the year ended December 31, 2024 mainly attributable to unfavorable contracts being fully amortized related to the West Jupiter and West Tellus during the third quarter of 2025, and the West Auriga and West Vela during the year ended December 31, 2024.

iii. Management contract expenses

Management contract expenses include costs related to Sonadrill's rigs, Quenguela and Libongos, and the Seadrill rig leased to Sonadrill, the West Gemini.

Management contract expenses increased by $57 million during the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily attributable to estimated damages following the unfavorable court judgment related to fees for arranging the Sonadrill joint venture.

iv. Merger and integration related expenses

Merger and integration related expenses include costs related to Seadrill's acquisition of Aquadrill, completed during the second quarter of the year ended December 31, 2023.

Merger and integration related expenses decreased by $22 million during the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily attributable to lower integration costs incurred related to the acquisition of Aquadrill.

3) Other operating items

Other operating items include loss on impairment of long-lived assets, gain on the sale of assets and other operating income.

i.Loss on impairment of long-lived assets

Loss on impairment of long-lived assets of $22 million for the year ended December 31, 2025 related to an impairment of the West Eclipse due to a sustained lack of future utilization plans.

ii . Gain on disposals

Gain on disposal of $234 million during the year ended December 31, 2024 related to the disposal of the West Castor, West Telesto and West Tucana jackup rigs, along with our 50% equity interest in the Gulfdrill joint venture during the second quarter of 2024, and the disposal of the West Prospero during the fourth quarter of 2024.

iii. Other operating income

Other operating income for the year ended December 31, 2024 related to the recovery of historical import duties in the form of tax credits following the approval by the applicable tax authorities, which did not recur during the year ended December 31, 2025.

41

4) Interest expense

i.Interest on debt facilities

We incur interest on our debt facilities as summarized below.

5) Other financial and non-operating items

i.Interest income

Interest income relates to interest earned on bank deposits. The $11 million decrease in interest income for the year ended December 31, 2025 compared to the year ended December 31, 2024, was primarily attributable to lower cash balances.

ii. Other financial and non-operating items

Other financial and non-operating items increased by $7 million during the year ended December 31, 2025 compared to the year ended December 31, 2024, primarily related to the recognition of indirect tax liabilities and a provision related to assets sold in 2023. This was partially offset by favorable foreign exchange movements due to the depreciation of the USD against the Brazilian Real and Norwegian Krone.

6) Income tax (expense)/benefit

Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities related to our ownership and operation of drilling units and may vary significantly depending on jurisdictions and contractual arrangements. In most cases, the calculation of taxes is based on net income or deemed income, the latter generally being a function of gross revenue.

The $139 million increase in tax expense during the year ended December 31, 2025 compared to the year December 31, 2024, principally reflects resolution of significant uncertain tax positions in 2024, following settlement with Nigeria’s tax authority, partially offset by the resolution in 2025 of uncertain tax positions for Ghana, along with changes in valuation allowances established for Switzerland and Brazil and changes in the Company's mix of pre-tax income and loss among tax jurisdictions.

Refer to Note 9 –"Taxation" for further details.

LIQUIDITY AND CAPITAL RESOURCES

1) Capital allocation framework and share repurchase program

In July 2023, in connection with the issuance of the Notes (as defined herein), Seadrill announced capital allocation principles designed to prioritize a conservative capital structure and liquidity position, focused capital investment in its fleet, and returns to shareholders. Within this framework, Seadrill intends to maintain a net leverage target of less than 1.0x under current market conditions, with a maximum through-cycle net leverage target of less than 2.0x. Seadrill also intends to maintain a strong liquidity position to provide resilience even in a downturn scenario by establishing a target minimum cash-on-hand of $250 million. Further, Seadrill intends to evaluate the potential for accretive additions in core asset categories.

So long as Seadrill is able to meet its net leverage and liquidity targets on a forward-looking basis, as well as comply with its Revolving Credit Facility covenant requirements, Seadrill would seek to provide a return to our shareholders of at least 50% of Free Cash Flow (defined as cash flows from operating activities minus additions to drilling units and equipment) in the form of share repurchases or dividends. Seadrill will consider additional returns to shareholders from the proceeds of any asset sales in the absence of identified, accretive opportunities.

42

Dividends and share repurchases will be authorized and determined by the Board of Directors in its sole discretion and depend upon a number of factors, including those described above, its future prospects, market trend evaluation and such other factors as the Board of Directors may deem relevant. Please see Part I, Item 1A, "Risk Factors — Financial and Tax Risks — We may be unable to meet our capital allocation framework goal of returning at least 50% of Free Cash Flow to shareholders through dividends and share repurchases, which could decrease expected returns on an investment in our Shares".

On August 14, 2023, the Board of Directors authorized a share repurchase program, which was announced on August 15, 2023, under which the Company completed its repurchase of $250 million of its outstanding common shares on December 5, 2023. On November 27, 2023, the Board of Directors authorized, and the Company announced, an increase in the Company’s aggregate share repurchase authorization, allowing the Company to repurchase an additional $250 million of its outstanding common shares, taking the aggregate authorization to $500 million. On June 25, 2024, the Company announced it had completed the additional $250 million of repurchases, with the cancellation of 5,250,707 treasury shares acquired under the program on June 28, 2024.

During the second quarter of 2024, the Board of Directors authorized a new $500 million share repurchase program that will run for a period of two years from June 25, 2024, the date of completion for the programs initiated in 2023 (the "Current Repurchase Program"). In furtherance of the Current Repurchase Program, the Board authorized the Company to purchase up to $200 million of the Company's common shares (the "First Tranche") by September 30, 2024. The Company repurchased an aggregate of 4,213,349 common shares, with a weighted average share price of $46.77, amounting to $192 million of the First Tranche. On September 30, 2024, the Company cancelled the 4,213,349 treasury shares repurchased under the First Tranche.

During the fourth quarter of 2024, in furtherance of the Current Repurchase Program, the Board authorized the Company to purchase up to $100 million of the Company’s common shares (the "Second Tranche") by December 31, 2024. The Company repurchased an aggregate of 2,500,903 common shares, with a weighted average share price of $39.99, amounting to $100 million. On December 16, 2024, the Company cancelled 2,500,903 treasury shares acquired under the Second Tranche.

In aggregate, during the year ended December 31, 2024, the Company repurchased approximately 11.6 million common shares amounting to $527 million with a weighted average share price of $45.31. The Company did not repurchase any common shares during the year ended December 31, 2025.

As of December 31, 2025, $208 million of the $500 million authorized amount remained available under the Current Repurchase Program.

While the Current Repurchase Program has a fixed expiration, it may be modified, suspended or discontinued at any time. Shares may be repurchased at any time and from time to time under the program in open market purchases, privately negotiated purchases, block trades, tender offers, accelerated share repurchase transactions or other derivative transactions, through the purchase of call options or the sale of put options, or otherwise, or by any combination of the foregoing. The Company is under no obligation to purchase any Shares in respect of the repurchase program. The manner, timing, pricing and amount of any repurchases may be based upon a number of factors, including market conditions, the Company’s financial position and capital requirements, financial conditions, competing uses for cash, statutory solvency requirements, the restrictions in the Company’s debt agreements and other factors.

The Company may continue share repurchases pursuant to the Current Repurchase Program at the Board’s discretion. While we intend to announce the initiation of any Board approved repurchase programs in the future, as well as periodic information required under U.S. securities laws and regulations, we do not intend to announce any sub-authorizations for share repurchases made pursuant to the Current Repurchase Program or any successor program given that we are no longer required to comply with European regulations requiring onerous disclosure in connection with repurchase programs.

2) Liquidity

Our level of liquidity fluctuates depending on a number of factors. These include, among others, our drilling units being on contract, economic utilization achieved, average contract dayrates, timing of accounts receivable collection, capital expenditures for rig upgrades and reactivation projects, and timing of payments for operating costs and other obligations.

As of December 31, 2025, Seadrill had available liquidity of $524 million, which consisted of unrestricted cash of $339 million, and available borrowings under our Revolving Credit Facility of $185 million. Our cash on hand, available borrowings under the Revolving Credit Facility, and contract and other revenues are expected to generate sufficient cash flow to fund our anticipated debt service and working capital requirements for the next 12 months.

The below table shows unrestricted cash balances and total available liquidity as of each date presented:

43

We have shown our sources and uses of cash by category of cash flows in the table below:

a) Net cash (used in)/provided by operating activities

Cash flows from operating activities include cash receipts from customers, cash paid to employees and suppliers (except for additions to drilling units and equipment), interest and dividends received (except for returns of capital), interest paid, income taxes paid and other operating cash payments and receipts.

Net cash used in operating activities during the year ended December 31, 2025 was $28 million compared to net cash provided by operating activities of $88 million for the year ended December 31, 2024. The $116 million decrease was primarily related to decreased operating results and increased disbursements to suppliers and a payment of damages for a legal proceeding, partially offset by reduced mobilization costs incurred in the year ended December 31, 2025 compared to the year ended December 31, 2024, which primarily related to contract preparation costs for the West Polaris and West Auriga.

b) Net cash (used in)/provided by investing activities

The $113 million net cash used in investing activities during the year ended December 31, 2025 was primarily related to capital expenditures on the West Neptune, West Elara, West Capella, West Gemini and West Auriga and the acquisition of capital spares.

The $226 million net cash provided by investing activities during the year ended December 31, 2024 was primarily related to the proceeds received on the disposal of our three jackup rigs, West Castor, West Telesto and West Tucana, together with our 50% equity interest in the Gulfdrill joint venture of $338 million during the second quarter, and the proceeds related to the disposal of the West Prospero jackup rig of $45 million during the fourth quarter. This was partially offset by capital expenditures of $157 million primarily related to capital upgrades on the West Auriga and West Polaris during their preparations for Petrobras contracts, with the West Auriga having started in December 2024 and West Polaris starting during the first quarter of 2025.

c) Net cash used in financing activities

The $3 million net cash used in financing activities during the year ended December 31, 2025 was related to taxes withheld on vested employee share-based compensation awards.

The $532 million net cash used in financing activities during the year ended December 31, 2024 was related to share repurchases.

3) Borrowing Activities

An overview of our debt as of December 31, 2025, divided into (i) secured debt and (ii) unsecured debt, is presented in the table below:

Collateral package

Revolving Credit Facility

In July 2023, the Company entered into a $225 million, 5-year Senior Secured Revolving Credit Agreement in respect of the Revolving Credit Facility (the “Credit Agreement”). Seadrill Finance (as defined herein) is the borrower under the Credit Agreement, and the facility is secured by first priority liens on substantially all of the Company’s drilling units and related assets, other than non-core assets. The Company, and certain of its subsidiaries that own collateral or are otherwise material, guarantee the obligations under the Credit Agreement. The loans outstanding under the Credit Agreement bear interest at a rate per annum equal to the applicable margin plus, at Seadrill Finance’s option, either: (i) the Term SOFR Rate (as defined in the Credit Agreement) plus 0.10%; or (ii) Daily Simple SOFR (as defined in the Credit Agreement) plus 0.10%. For both the Term SOFR Rate loans and Daily Simple SOFR loans, the applicable margin was 2.75% per annum as of December 31, 2025, and may vary based on Seadrill’s Credit Ratings (as defined in the Credit Agreement), from 2.50% to 3.50% per annum. A commitment fee is incurred under the Revolving Credit Facility on undrawn amounts, at a rate of 0.5% per annum to and including July 27, 2026, 0.75% per annum from and including July 28, 2026 to and including July 27, 2027, and 1.00% per annum thereafter.

44

In August 2025, the Company issued a NOK403 million guarantee (approximately $40 million as of December 31, 2025) under the Revolving Credit Facility related to the SFL Hercules Ltd. claim, which reduced the available borrowings under the Revolving Credit Facility to approximately $185 million.

For further details, please refer to Note 24 – "Commitments and contingencies".

$575 million Notes Offerings

In July 2023, Seadrill Finance issued the Notes in a private offering. The Notes mature on August 1, 2030. The Notes are guaranteed by the Company and the same subsidiaries of the Company that guarantee the Credit Agreement. The Notes are secured by a second priority lien on the same assets that secure the Credit Agreement.

Bilateral Facility

Seadrill Rig Holding Company Limited, a subsidiary of Seadrill Limited, has an uncommitted bilateral facility with DNB Bank ASA (the “Bilateral Facility”), which permits the issuance of letters of credit and bank guarantees for our account. Up to $25 million of reimbursement obligations under the Bilateral Facility are secured on a pari passu basis with the collateral that secures the Credit Agreement, and any additional obligations under the Bilateral Facility would need to be secured by cash or other collateral. We pay a fee of 1% on outstanding letters of credit and bank guarantees issued under the Bilateral Facility. As of December 31, 2025, we had approximately $19 million of outstanding letters of credit and bank guarantees issued under the Bilateral Facility.

Refer to Note 16 – "Debt" for further details of these facilities.

Financial covenants

The Credit Agreement obligates Seadrill and its restricted subsidiaries to comply with the following financial covenants:

•as of the last day of each fiscal quarter, the Interest Coverage Ratio (as defined in the Credit Agreement) is not permitted to be less than 2.50 to 1.00; and

•as of the last day of each fiscal quarter, the Consolidated Total Net Leverage Ratio (as defined in the Credit Agreement) is not permitted to be greater than 3.00 to 1.00.

As of December 31, 2025, Seadrill was in compliance with these financial covenants.

4) Contractual Obligations

As of December 31, 2025, we have $22 million of uncertain tax position, inclusive of interest and penalties, included on our Consolidated Balance Sheet. 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. Refer to Note 9 – "Taxation" for further details.

As of December 31, 2025, we do not have long-term debt due within the next 12 months. Principal payments of $625 million will be due in subsequent periods to 2026. Refer to Note 16 – "Debt" for further details of these facilities.

For a description for our operating lease obligations, refer to Note 18 - "Leases" for further details.

As of December 31, 2025, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include guarantees on our performance as it relates to our drilling contracts and as security for a legal matter. We expect to comply with the underlying performance requirements, and we expect obligations under these guarantees will not be called. Refer to Note 24 - "Commitments and contingencies" for further details.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States ("US GAAP") requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that we believe to be reasonable. Critical accounting estimates are important to the portrayal of both our financial position and results of operations and require us to make subjective or complex assumptions or estimates about matters that are uncertain. Actual results may differ from these estimates.

Critical accounting estimates that are significant for the year ended December 31, 2025 are as follows:

Impairment considerations (drilling units)

The carrying values of our long-lived assets are reviewed for impairment when certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be recoverable. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in significantly different carrying values of our assets and could materially affect our results of operations. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount is not recoverable.

45

Income taxes

Seadrill is a Bermuda company that has subsidiaries and affiliates in various jurisdictions. Effective January 1, 2025, Bermuda enacted a 15% corporate income tax applicable to Bermudan members of multinational enterprise groups with annual global revenue of €750 million or more. Beginning in 2025, Seadrill and its Bermuda subsidiaries are subject to Bermuda corporate income tax. Certain subsidiaries operate in or realize income from sources within other jurisdictions that impose income taxes or withholding taxes. Consequently, income taxes for these jurisdictions have been recorded when applicable. Our income tax expense is based on our income and the statutory tax rates of relevant jurisdictions. Refer to Note 9 – "Taxation".

Our income tax expense is based on our interpretation of tax laws in various jurisdictions in which we operate or derive income and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amounts, timing and character of income, deductions, and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty concerning interpretation of tax law that arises in the ordinary course of business.

We recognize liabilities for uncertain tax positions based on a two-step process. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates that it is more likely than not that the position will be sustained on audit by relevant tax authorities, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount that is more likely than not of being realized upon settlement. While we believe we have appropriate support for the positions taken on our tax returns, in assessing the adequacy of our provision for income taxes we consider developments in tax laws, regulations, administrative practices and relevant case law; the progress and findings of ongoing tax audits; and our experience with relevant taxation principles.

Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. We recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the Consolidated Statement of Operations as income tax expense (or benefit) in the period of sale or transfer occurs.

Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, and changes in prior year tax estimates as tax returns are filed or adjusted upon tax audits.

Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and their values for taxation purposes and on the future tax benefits of tax attributes. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

Business combinations

We apply the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recorded at their estimated acquisition date fair value. The acquisition method of accounting requires us to make significant estimates and assumptions regarding the fair values of the elements of a business combination as of the date of acquisition, including the fair values of drilling units, identifiable intangible assets and liabilities, deferred tax asset valuation allowances, and liabilities related to uncertain tax positions, among others. Significant estimates and assumptions are used in determining the fair value of drilling units and intangible assets and liabilities, and include off-contract revenue estimates, off-contract operating expense assumptions, contract probabilities, the weighted average cost of capital ("WACC") rate used to discount free cash flow projections and drilling unit market valuations. This method also requires us to refine these estimates over a measurement period not to exceed one year to reflect new information obtained about facts and circumstances that existed as of the acquisition date that, if known, would have affected the measurement of the amounts recognized as of that date. If we are required to retroactively adjust provisional amounts that we have recorded for the fair values of assets and liabilities in connection with acquisitions, these adjustments could have a material impact on our financial condition and results of operations.

In addition, we have estimated the economic lives of certain acquired assets and assumed liabilities and these lives are used to calculate depreciation and amortization expense. If our estimates of the economic lives change, depreciation or amortization expenses could increase or decrease. Furthermore, if the subsequent actual results and updated projections of the underlying business activity change compared with the assumptions and projections used to develop these values, we could record impairment charges.

46