What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-26 compared with 2025-02-27 · 148 added, 193 removed, 252 unchanged (58% of the section changed)

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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 year ended December 31, 2023, the periods from February 23, 2022 through December 31, 2022 (Successor) and from January 1, 2022 through February 22, 2022 (Predecessor), see Part I, Item 5, "Operating and Financial Review and Prospects” of our annual report on Form 20-F for the year ended December 31, 202 3 , filed with the SEC on March 27, 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.

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.

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In addition, we provide management services to certain affiliated entities.

As of December 31, 2024, we owned a total of 15 drilling units, of which 11 were operating (inclusive of one leased to the Sonadrill joint venture), one 6th generation drillship was undergoing contract preparations for a contract that commenced during February 2025, and three were cold stacked.

The 11 operating units include 10 benign floaters (comprising seven 7th generation drillships, two 6th generation drillships and one benign environment semi-submersible) and one harsh environment unit (comprising of one jackup).

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.

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Significant Developments

Share Repurchase Program

On June 25, 2024, the Company announced it had completed the additional $250 million of share repurchases initiated in December 2023, having repurchased an aggregate of 5,250,707 common shares, with a weighted average share price of $47.61, amounting to $250 million.

During the second quarter of 2024, as announced on May 16, 2024, the Company's 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.

Under the Current Repurchase Program, the Company repurchased an aggregate of 6,714,252 Shares, with a weighted average share price of $43.52, amounting to $292 million.

As of December 31, 2024, $208 million of the $500 million authorized amount remained available.

Refer to “Liquidity and Capital Resources - 2) Capital allocation framework and share repurchase program ” and Note 22 - "Common shares" for additional information about the Company's share repurchases.

Disposal of Jackup Rigs and Equity Interest in Gulfdrill Joint Venture

On May 16, 2024, Seadrill entered into a definitive agreement to sell three jackup rigs, the West Castor , West Telesto , and West Tucana , and its 50% equity interest in the joint venture that operated these rigs offshore Qatar, to Seadrill's joint venture partner, Gulf Drilling International, for cash proceeds of $338 million.

The closing of the sale occurred in June 2024, and a gain of $203 million, net of transaction costs, was recognized in the second quarter of 2024 associated with the disposal of these assets.

On November 23, 2024, Seadrill executed a Sale and Purchase Agreement with Petrovietnam Drilling & Well Service Corporation to divest the West Prospero for cash proceeds of $45 million.

The closing of the sale occurred in December 2024, and a gain of $31 million, net of transaction costs, was recognized in the fourth quarter of 2024 associated with the disposal of the jackup rig.

OSE Delisting

As contemplated by our proxy statement, dated March 21, 2024, we submitted an application to delist our common shares on the OSE, on April 30, 2024.

Oslo Bors approved the Company’s delisting from the OSE, following an affirmative shareholder vote at the Company’s Annual General Meeting in April 2024.

The last day of trading our common shares on the OSE was September 9, 2024, with our common shares being delisted from the OSE on September 10, 2024.

Loss of Foreign Private Issuer Status

We determined the Company ceased to qualify as a foreign private issuer effective as of January 1, 2025 and commenced reporting as a domestic issuer under the Exchange Act from that date.

As a result, among other consequences, we are no longer permitted to follow certain home country practices in relation to our corporate governance instead of NYSE rules.

See Part I, Item 1A, “Risk Factors - Regulatory and Legal Risks - The loss of our status as a “foreign private issuer” could result in additional cost.”

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

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Average Brent oil price ($/bbl) 68 80 82 101 71

In 2020, the oil and gas industry faced significant uncertainty due to a substantial reduction in oil and gas prices caused by the pandemic, despite Brent prices stabilizing in previous years.

However, production cuts by OPEC and non-OPEC members, along with effective vaccination campaigns, had positive impacts on the industry, leading to a recovery in oil demand throughout 2021 and 2022.

The price of Brent crude oil averaged $80 per barrel in 2024, down from $82 per barrel in 2023.

Global growth in the production of oil and slower demand growth has put downward pressure on prices, while heightened geopolitical risks and voluntary production restrictions among OPEC and non-OPEC members has supported prices.

Overall, in recent years, oil prices have generally remained at levels that are supportive of offshore exploration and development activity, and global rig demand has been steady.

This level of demand has been sustained by the combination of growing confidence in commodity prices, heightened focus on energy security, and relative attractiveness of offshore plays with respect to both cost and carbon emissions.

During the first quarter of 2024, Brent oil prices generally rose due to heightened geopolitical risks largely associated with the growing Middle East conflict.

Brent crude oil prices were highest in 2024 during April, closing at $91 per barrel.

Prices generally declined through the remainder of 2024, with smaller price rallies driven by OPEC and non-OPEC announcements in June and September regarding delayed production increases.

Economic weakness and concerns about oil consumption, particularly regarding trends in consumption of diesel and gasoline in China weighed on prices during the second half of 2024.

As a result, uncertainty persists in the market, which is primarily driven by concerns over the global economic conditions.

Such concerns have led to continued deferral of offshore capital expenditures and contracting of offshore drilling services, and could have a negative impact on future demand for offshore drilling services, as the industry faces volatility in oil prices and growth trajectory for oil demand.

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.

The below table shows the global number of rigs on contract and marketed utilization for the year ended December 31, 2024, and for each of the four preceding years.

2024 2023 2022 2021 2020

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.

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:

December 31, 2025 December 31, 2024

Contracted rigs

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Harsh environment jackup

90 % 83 % 92 % 80 % 75 %

Global benign environment floaters

In 2024, marketed utilization declined slightly mainly due to an increase in supply and a larger number of units rolling off contract.

As of December 31, 2024, the drillship utilization performed better at around 88 % compared to 78% for semi-submersibles.

While the utilization for drillships declined year on year, the benign-environment semi-submersibles utilization saw a slight improvement compared to 2023.

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 remained steady year on year in the harsh environment floater segment due to the supply and demand balance.

Harsh environment jackup utilization improved at a faster rate through 2024 closing the year at 90%.

The decrease in harsh environment floater contracted rigs is mainly attributable to the reduction in supply, as a number of harsh environment units were contracted in the benign environment segment.

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

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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 increase in our owned fleet in 2023 was due to the acquisition of Aquadrill.

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

Drilling units managed December 31, 2025 December 31, 2024 December 31, 2023

Floater 2 2 2

Jackup rigs — — 5

Benign environment drillships 2 2 2

Total managed rigs 2 2 2

The decrease in managed jackup rigs during 2023 was due to the termination of the SeaMex MSA on November 17, 2023.

Contract backlog

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Drilling contracts 2,095 3,034 2,612

Other 285 146 408

Total 2,380 3,180 3,020

(1) Decrease is primarily due to divestment of three Qatar jackup rigs, partially offset by increased bareboat charter rate on West Gemini.

Our contract backlog includes only firm commitments represented by signed drilling contracts.

The full contractual operating dayrate may differ to the actual dayrate we ultimately receive.

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 to the actual dayrate we ultimately receive because of several other factors, including rig downtime or suspension of operations.

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.

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RESULTS OF OPERATIONS

The tables included below set out financial information for the years ended December 31, 2024 and December 31, 2023 (Successor).

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

(In $ millions, except percentages) Year ended December 31, 2025 Year ended December 31, 2024 Change Change %

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Other financial and non-operating items (37) (18) (19) 106 %

Profit before income taxes 333 317 16 5 %

Income tax benefit/(expense) 113 (17) 130 (765) %

Net income 446 300 146 49 %

(Loss)/profit before income taxes (51) 333 (384) (115) %

Income tax (expense)/benefit (26) 113 (139) (123) %

Net (loss)/income (77) 446 (523) (117) %

1) Operating revenues

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33 54 (21) (39) %

Other revenues (e)

5 12 (7) (58) %

Operating revenues 1,385 1,502 (117) (8) %

Other revenues 3 5 (2) (40) %

Total operating revenues 1,437 1,385 52 4 %

a) Contract revenues

Contract revenues represent the revenues we earn from contracting drilling units to customers, primarily on a dayrate basis, and are primarily 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.

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.

Average number of rigs on contract

We calculate the average number of rigs o n contract by dividing the aggregate days our rigs were on contract during the reporting period by the number of days in that reporting period.

The average number of rigs on contract decreased from 11 in the year ended December 31, 2023 to 9 in the year ended December 31, 2024, resulting in a $170 million decrease in contract revenues in the year ended December 31, 2024 compared to the year ended December 31, 2023.

The decrease is primarily related to the West Auriga and West Polaris operating for fewer days during the year ended December 31, 2024, as the rigs underwent preparation work for contracts with Petrobras in Brazil, with the West Auriga commencing work in late December 2024, and the West Polaris commencing work in the first quarter of 2025.

In addition, the Sevan Louisiana was not operating during the first quarter of 2024 due to its special periodic survey, and the West Phoenix was cold stacked in the fourth quarter of 2024.

Therefore, each had fewer days on contract during the year ended December 31, 2024 compared to the year ended December 31, 2023.

These decreases were partially offset by the West Capella and West Vela operating for more days during the year ended December 31, 2024, compared to the year ended December 31, 2023, as the rigs were acquired in April 2023 as a part of the Aquadrill acquisition.

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.

Average contractual dayrates

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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.

Improvements during the year ended December 31, 2024 included higher dayrates for the West Neptune , the West Capella operating at higher dayrates in Indonesia and South Korea, along with a lower contractual rate for the T-15 , which was disposed of in July 2023.

These improvements were partially offset by the Sevan Louisiana operating at a below average dayrate for a well intervention contract during the year ended December 31, 2024, and the West Auriga earning an above average contractual rate for more days during the year ended December 31, 2023, which ended February 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.

Economic utilization for rigs on contract

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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 a contractual operating rate, such as planned downtime for maintenance.

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%.

Economic utilization increased to 95% for the year ended December 31, 2024, compared to 93% for the year ended December 31, 2023, resulting in a $24 million increase in contract revenues in the year ended December 31, 2024 compared to the year ended December 31, 2023.

The increase was primarily due to planned downtime and operational events related to blowout preventer reliability and weather-related impacts on certain rigs within the fleet in 2023.

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.

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 drilling revenue as services are rendered over the initial term of the related drilling contract.

Amortization of deferred mobilization revenues decreased by $19 million during the year ended December 31, 2024, compared to the year ended December 31, 2023.

This was primarily related to the West Capella, West Polaris and West Phoenix, as their respective contracts ended in 2024.

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.

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

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We classify such revenues as reimbursable revenues.

For the year ended 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 , and for the year ended December 31, 2023 , reimbursable revenues related to services provided across various customers.

The increase for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to additional reimbursable services provided to the Libongos and Quenguela for long-term maintenance.

Please refer to Note 1 - "General information" for reclassifications of reimbursable revenues and reimbursable expenses related to our joint ventures, including $26 million of management contract revenues and management contract expenses for the year ended December 31, 2023 , reclassified to reimbursable revenues and reimbursable expenses, respectively.

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 comprise revenue from our joint venture, Sonadrill, relating to the Libongos , Quenguela and the West Gemini .

Management contract revenues for the year ended December 31, 2024 were relatively consistent with the year ended December 31, 2023.

An increase in management fees on the three Sonadrill rigs during the year ended December 31, 2024 of $16 million, was offset by a $14 million decrease in management services provided to SeaMex during the year ended December 31, 2023, which ended in November 2023.

Refer to Note 24 - "Related party transactions" for further details on these related parties.

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 Castor , West Telesto and West Tucana to Gulfdrill prior to disposal in June 2024, and West Gemini to Sonadrill.

The increase to leasing revenues of $21 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, is primarily due to an amended bareboat charter rate for West Gemini , retroactively effective from January 1, 2024, as well as a higher bareboat charter rate for the West Castor , which was effective in September 2023, partially offset by a decrease of leasing revenues attributable to the Gulfdrill rigs, disposed in June 2024.

Refer to Note 24 - "Related party transactions" for further details and to Note 1 - "General information" for reclassifications of leasing revenues, including $33 million of other revenues for the year ended December 31, 2023, reclassified to 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, depreciation of drilling units and equipment, amortization of intangibles, reimbursable expenses, management contract expenses, selling, general and administrative expenses and merger and integration related 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.

(In $ millions, except percentages) Year ended December 31, 2025 Year ended December 31, 2024 Change Change %

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(232) (175) (57) 33 %

Merger and integration related expenses (24) (24) — — %

Selling, general and administrative expenses (iv)

Merger and integration related expenses (iv)

(2) (24) 22 (92) %

Operating expenses (1,223) (1,187) (36) 3 %

Selling, general and administrative expenses (103) (107) 4 (4) %

Total operating expenses (1,369) (1,223) (146) 12 %

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 and onshore support costs.

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.

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Where a rig is leased to another operator, the majority of vessel and rig expenses are incurred by the operator.

The average number of rigs on contract decreased for the year ended December 31, 2024 compared to the year ended December 31, 2023 , driven primarily by the West Auriga and West Polaris undergoing preparations for contracts with Petrobras in Brazil during the year ended December 31, 2024 , with certain operating expenses being capitalized.

In addition, there has also been a decrease in costs associated with MSA (as defined below) fees, as the majority of rigs acquired through the Aquadrill transaction are now managed by Seadrill, rather than by third parties.

As a result, our vessel and rig operating expenses was $57 million lower for the year ended December 31, 2024 compared to the year ended December 31, 2023 .

This was partially offset by a $36 million increase in vessel and rig operating expenses attributable to the West Vela and West Capella operating for more days during the year ended December 31, 2024, compared to the year ended December 31, 2023, as the rigs were acquired in April 2023 as a part of the Aquadrill acquisition.

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.

Depreciation and amortization

The $13 million increase in depreciation and amortization for the year ended December 31, 2024 compared to the year ended December 31, 2023 , was primarily due to a $10 million increase in the depreciation of drilling units and equipment as a result of the additional rigs from the Aquadrill acquisition completed in April 2023, partially offset by the disposal of the Gulfdrill rigs in June 2024.

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

We record depreciation expense to reduce the carrying value of drilling unit and equipment balances to their residual value over their expected remaining useful economic lives.

Depreciation increased by $10 million in the year ended December 31, 2024 compared to the year ended December 31, 2023 , primarily due to the additional rigs from the Aquadrill acquisition completed in April 2023, partially offset by the disposal of the Gulfdrill rigs in June 2024.

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 increased by $3 million during the year ended December 31, 2024 compared to the year ended December 31, 2023, primarily due to unfavorable contracts being fully amortized related to the West Polaris , which was fully amortized in 2023, and the West Auriga and West Vela , which were fully amortized in February 2024.

These were partially offset by lower amortization related to favorable contracts for the West Phoenix , Quenguela , West Capella and SeaMex, which were fully amortized during 2023.

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 .

Management contract expenses

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

For the year ended December 31, 2023, management contract expenses also included SeaMex's five jackup units.

Management contract expenses remained consistent during the year ended December 31, 2024, compared to the year ended December 31, 2023.

During the year ended December 31, 2024, there was an increase of $11 million in the managed contract expenses, primarily related to higher repair and maintenance costs pertaining to the Sonadrill managed rigs.

This was offset by a decrease of $10 million in the managed contract expenses related to managing the SeaMex jackup units in the first quarter of 2023, and therefore, no longer managed by Seadrill during the year ended December 31, 2024.

Selling, general and administrative expenses

Selling, general and administrative expenses include the cost of our corporate and regional offices, certain legal and professional fees as well as the remuneration and other compensation of our officers, directors and employees engaged in central management and administration activities.

Selling, general and administrative expense increased by $33 million during the year ended December 31, 2024 compared to the year ended December 31, 2023 , due to increased onshore employee costs, additional costs attributable to the closure of our London office and increased professional service fees.

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.

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 gains on the sale of assets and other operating income.

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

(In $ millions, except percentages) Year ended December 31, 2025 Year ended December 31, 2024 Change Change %

Gain on disposals (i)

Loss on impairment of long-lived assets (i)

(22) — (22) 100 %

Other operating income (ii)

Gain on disposals (ii)

1 234 (233) (100) %

Other operating income (iii)

— 16 (16) (100) %

Other operating items (21) 250 (271) (108) %

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.

Gain on disposals

Gain on disposals of $234 million for the year ended December 31, 2024 relates 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, compared to the gain on disposal of $14 million during the year ended December 31, 2023 of capital spares relating to jackup rigs and to the West Hercules , and spare parts on previously recycled rigs.

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.

Other operating income

Other operating income for the year ended December 31, 2024 relates to the recovery of historical import duties in the form of tax credits following the approval by the applicable tax authorities.

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.

4) Interest expense

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Year ended December 31, 2025 Year ended December 31, 2024 Change Change %

$575 million secured bond in issue (48) (21) (27) 129 %

Post-emergence first lien senior secured — (12) 12 (100) %

Post-emergence second lien senior secured — (16) 16 (100) %

Post-emergence unsecured senior convertible bond (6) (5) (1) 20 %

$575 million secured bond (48) (48) — — %

Unsecured senior convertible bond (5) (6) 1 (17) %

Interest on debt facilities (53) (54) 1 (2) %

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14 25 (11) (44) %

Share in results from associated companies (net of tax) (ii)

Equity in losses of equity method investment (net of tax)

(10) (9) (1) 11 %

Other financial items (iii)

Other financial and non-operating items (ii)

(41) (34) (7) 21 %

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Interest income relates to interest earned on bank deposits.

The decrease in interest income for the year ended December 31, 2024 compared to the year ended December 31, 2023 , is primarily attributable to the decrease in cash and cash equivalents.

Share in results in associated companies (net of tax)

Share in results in associated companies represents our share of profits or losses in our Sonadrill and Gulfdrill investments accounted under the equity method.

The decrease of $46 million in the share in results from associated companies for the year ended December 31, 2024, compared to the year ended December 31, 2023 is due to a loss from Sonadrill, which primarily resulted from the amended bareboat charter rates and increased management fees for the Libongos , Quenguela and West Gemini , effective from January 1, 2024.

Other financial items

Other financial items remained relatively consistent for the year ended December 31, 2024 compared to the year ended December 31, 2023.

Movements to other financial items included increased foreign exchange losses of $19 million during the year ended December 31, 2024, primarily related to the strengthening of the U.S.

Dollar against Brazilian Real, Indonesian Rupiah, Norwegian Krone and Angolan Kwanza denominated cash, accounts receivable and prefunding balances.

This was partially offset by other financial items during the year ended December 31, 2023, including a make-whole fee of $10 million related to the prepayment of the first lien debt.

6) Income tax benefit/expense

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.

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 change from an income tax expense of $17 million for the year December 31, 2023, compared to an income tax benefit of $113 million for the year ended December 31, 2024, is primarily related settlements reached with tax authorities, along with the recognition of deferred tax benefits related to the partial release of the valuation allowance in Switzerland and Brazil during the year ended December 31, 2024.

Refer to Note 11 –" Taxation" to the Consolidated Financial Statements included herein for further details.

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) Emergence from Chapter 11 Proceedings

Seadrill successfully completed its comprehensive restructuring and emerged from Chapter 11 proceedings on February 22, 2022 (refer to Note 4 – "Chapter 11" of the accompanying financial statements).

Since our emergence from Chapter 11, we successfully refinanced the First Lien Facility (as defined below) and the secured second lien debt facility ("Second Lien Facility") in July 2023 (refer to Note 19 – "Debt" of the accompanying financial statements).

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 twelve months.

Financial information in this report has been prepared on a going concern basis of accounting, which presumes we will be able to realize our assets and discharge our liabilities in the normal course of business as they come due.

Financial information in this report does not reflect the adjustments to the carrying values of assets, liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in the normal course of operations.

Such adjustments could be material.

1) Capital allocation framework and share repurchase program

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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 capital expenditures) in the form of share repurchases or dividends.

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.

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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 Company's 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.

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.

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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, compared to 6.2 million common shares amounting to $266 million, with a weighted average share price of $43.12, during the year ended December 31, 2023.

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.

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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.

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

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(In $ millions, except percentages) Year ended December 31, 2025 Year ended December 31, 2024 Change Change %

Net cash provided by operating activities (a)

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

(28) 88 (116) (132) %

Net cash provided by investing activities (b)

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

(113) 226 (339) (150) %

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Change in period (140) (223) 83 (37) %

a) Net cash provided by operating activities

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.

Cash flows provided by operating activities during the year ended December 31, 2024 were $88 million compared to $287 million for the year ended December 31, 2023 .

The decrease is primarily related to outflows for long-term maintenance projects and contract preparation costs incurred related to the West Auriga and West Polaris , along with long-term maintenance related to West Neptune and long-lead items related to SPS activities across the fleet.

These were partially offset by increased receipts from customers and decreased disbursements to other suppliers.

b) Net cash provided by investing activities

The $226 million cash provided by investing activities during the year ended December 31, 2024 is primarily related to the proceeds received on 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.

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 r elated 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.

The $42 million cash provided by investing activities during the year ended December 31, 2023 was due to net proceeds of $43 million received on disposal of PES in February 2023, $24 million net cash received as a result of the Aquadrill acquisition, $84 million cash received on disposal of the tender-assist units, and $14 million from the disposal of equipment.

This was offset by $101 million of capital expenditures across the fleet and $22 million paid out to settle indemnity costs associated with the disposal of the entities that own and operate seven jackup units in the Kingdom of Saudi Arabia.

c) Net cash used in financing activities

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

The $200 million cash used in financing activities during the year ended December 31, 2023 related to prepayments of debt principal of $446 million and exit fees of $22 million, a make-whole fee of $10 million on the repayment of the First Lien Facility, Revolving Credit Facility costs of $13 million, $263 million of share repurchases, and share issuance costs of $4 million.

These were partially offset by proceeds of $576 million from the issuance of the Notes, excluding issuance costs of $18 million.

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, 2024, divided into (i) secured debt and (ii) unsecured senior convertible notes, is presented in the table below:

(In $ millions) Principal value as of December 31, 2024 Debt Premium Debt Issuance Costs Carrying value as of December 31, 2024 Maturity date

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:

(In $ millions) Principal value Debt Premium Debt Issuance Costs Carrying value Maturity date

$575 million secured bond 575 1 (13) 563 August 2030

Senior convertible bond 50 — — 50 August 2028

Unsecured senior convertible bond 50 — — 50 August 2028

Total debt 625 1 (13) 613

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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 (as defined in the Credit Agreement) plus 0.10%;

or (ii) the Daily Simple SOFR (as defined in the Credit Agreement) plus 0.10%.

For both the Term SOFR loans and Daily Simple SOFR loans, the applicable margin was 2.75% per annum as of December 31, 2024, and may vary based on Seadrill’s Credit Ratings (as defined in the Credit Agreement), from 2.50% to 3.50% per annum.

(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.

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

Also in July 2023, Seadrill Finance issued the Notes in a private offering.

In July 2023, Seadrill Finance issued the Notes in a private offering.

The Notes mature on August 1, 2030.

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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.

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4) Contractual Obligations

The following table summarizes our significant contractual obligations as of December 31, 2024 and the periods in which such obligations are due:

Payments due by period

(In $ millions) 2025 2026 and 2027 2028 and 2029 Thereafter Total

Principal payments on long-term debt — — 50 575 625

Interest payments on long-term debt 54 108 100 28 290

Operating leases 4 5 3 — 12

58 113 153 603 927

(1) Contractual obligations exclude $55 million of uncertain tax position, inclusive of interest and penalties, included on our Consolidated Balance Sheet as of December 31, 2024.

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.

Additional information regarding legal proceedings is presented in “Note 27 — Commitments and Contingencies” to our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" of this annual report.

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

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Seadrill is a Bermuda company that has subsidiaries and affiliates in various jurisdictions.

As of December 31, 2024, Seadrill and our Bermudan subsidiaries and affiliates were not required to pay taxes in Bermuda on ordinary income or capital gains as they qualify as exempted companies.

Certain subsidiaries operate in other jurisdictions where taxes are imposed.

Consequently, income taxes have been recorded in these jurisdictions when applicable.

Our income tax expense is based on our income and statutory tax rates in the jurisdictions we operate.

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 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 in relation to the interpretation of tax law that arises in the ordinary course of business.

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.

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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, we regularly assess the potential outcomes of examinations by tax authorities in determining the adequacy of our provision for income taxes.

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, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments.

Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax benefits of tax attributes.

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.

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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 in determining the fair value of drilling units and intangible assets and liabilities 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.

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.

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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.

Fresh start accounting

As set forth in the Disclosure Statement approved by the Bankruptcy Court, the Company was approved to have an enterprise valuation of between $1,795 million and $2,396 million.

Using valuation models, we valued the Successor’s enterprise value to be $2.1 billion as of the Effective Date, which is equal to the mid-point of the court approved valuation range.

Enterprise value represents the estimated fair value of an entity’s shareholders’ equity plus long-term debt and other interest-bearing liabilities less unrestricted cash and cash equivalents.

The enterprise value and corresponding equity value are dependent upon achieving future financial results set forth in our valuations, as well as the realization of certain other assumptions.

All estimates, assumptions, valuations and financial projections, including the fair value adjustments, the enterprise value and equity value projections, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control.

Accordingly, the estimates, assumptions, valuations or financial projections may not be realized and actual results could vary materially.

Critical accounting estimates in relation to fresh-start valuation of our drilling units and investments included:

Off-contract revenue estimates, off-contract operating expense assumptions, contract probabilities, the WACC rate used to discount free cash flow projections and drilling unit market valuations.

Sale of subsidiaries or groups of assets

We account for the sale of a subsidiary or group of assets in accordance with ASC 810 - Consolidations.

When we sell a subsidiary or group of assets, we recognize a gain or loss measured as the difference between 1) the aggregate of (i) the fair value of any consideration received, (ii) the fair value of any retained noncontrolling investment in the former subsidiary or group of assets & (iii) the carrying amount of any noncontrolling interest in the former subsidiary;

and 2) the carrying amount of the former subsidiary’s assets and liabilities or the carrying amount of the group of assets.

Consideration transferred is the sum of the acquisition-date fair values of the assets transferred, the liabilities incurred by the acquirer to Seadrill, and the equity interests issued by the acquirer to Seadrill, but is net of any liabilities incurred by Seadrill, including warranties or indemnities made as part of the sale.

The gain or loss on sale is net of any costs to sell the subsidiary or group of assets.

Refer to Note 28 – "Discontinued Operations" for details of disposals during the comparative periods presented.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis