Seadrill Limited (SDRL) 6-KCurrent report (foreign)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE13a-16 OR15d-16

OF THE SECURITIES EXCHANGE ACT OF 1934

For the month of June 2020

Commission File Number333-224459

SEADRILL LIMITED

(Exact name of Registrant as specified in its Charter)

Par-la-Ville Place, 4th Floor

14Par-la-Ville Road

Hamilton HM 08 Bermuda

(441)295-6935

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form20-F or Form40-F.

Form20-F   ☒            Form40-F  ☐

Indicate by check mark if the registrant is submitting the Form6-K in paper as permitted by RegulationS-T Rule 101(b)(1):

Yes  ☐            No  ☒

Indicate by check mark if the registrant is submitting the Form6-K in paper as permitted by RegulationS-T Rule 101(b)(7):

Yes  ☐            No  ☒

Seadrill Limited

Report on Form6-K for the three months ended March 31, 2020

EXPLANATORY NOTE

This Form6-K contains the Management’s Discussion and Analysis of Financial Condition and Results of Operations and the unaudited interim condensed Consolidated Financial Statements and related information and data of the Company as of and for the three month period ended March 31, 2020.

This Form6-K is hereby incorporated by reference into our Registration Statements on (i) FormF-3 (RegistrationNo. 333-224459), and (ii) FormS-8 (RegistrationNo. 333-227101).

INDEX

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

We desire to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, or the PSLRA, and are including this cautionary statement in connection therewith. The PSLRA provides safe harbor protections for forward-looking statements to encourage companies to provide prospective information about their business.

Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements, which are other than statements of historical or present facts or conditions.

This report on Form6-K and any other written or oral statements made by us or on our behalf may include forward-looking statements which reflect our current views with respect to future events and financial performance. The words “believe,” “anticipate,” “intend,” “estimate,” “forecast,” “project,” “plan,” “potential,” “may,” “should,” “expect” and similar expressions identify forward-looking statements.

The forward-looking statements in this document are based upon various assumptions, many of which are based, in turn, upon further assumptions, including, without limitation, management’s examination of historical operating trends, data contained in our records and other data available from third parties. Although we believe that these assumptions were reasonable when made, because these assumptions are inherently subject to significant uncertainties and contingencies that are difficult or impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish these expectations, beliefs or projections.

In addition to these important factors and matters discussed elsewhere in this report on Form6-K, and in the documents incorporated by reference to this report, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include:

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We caution readers of this report on Form6-K not to place undue reliance on these forward-looking statements, which speak to circumstances only as at their dates. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward-looking statement.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our financial condition and results of operations in conjunction with the interim Financial Statements presented in this report, as well as the historical Consolidated Financial Statements and related notes of Seadrill Limited included in our annual report on Form20-F filed with the SEC on April 2, 2020 (SEC FileNo. 333-224459) (the“20-F”). Among other things, those financial statements include more detailed information regarding the basis of presentation for the following information. The unaudited Consolidated Financial Statements of Seadrill Limited included in this report have been prepared in accordance with United States Generally Accepted Accounting Principles (“US GAAP”) and are presented in US Dollars.

Except where the context otherwise requires or where otherwise indicated, the terms “Seadrill,” “the Group,” “we,” “us,” “our,” “the Company” and “our Business” refer to either Seadrill Limited, any one or more of its consolidated subsidiaries, or to all such entities.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is designed to provide a reader of our financial statements with a narrative from the perspective of management. Our MD&A is presented in the following sections:

Overview

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, semi-submersible rigs andjack-up rigs for operations in shallow to ultra-deepwater areas in both benign and harsh environments. We contract our drilling units to drill wells for our customers on a dayrate basis. Typically, our customers are oil super-majors, state-owned national oil companies and independent oil and gas companies.

Through a number of acquisitions of companies, second-hand units and newbuildings, we have developed into one of the world’s largest international offshore drilling contractors. We also provide management services to our related parties Seadrill Partners, SeaMex, Northern Ocean and Sonadrill.

Significant Developments for the period from January 1, 2020 through and including March 31, 2020

Impairment of assets

During the first quarter of 2020 there was a significant decline in the price of oil due to the actions of OPEC and its partners combined with the global impact of theCOVID-19 pandemic, with Brent Oil reaching a low of $22 per barrel on March 30, 2020. The impact of these events on the drilling market is having an impact on our industry with expected decreases in utilization going forward and downward pressure on dayrates. We have considered these as indicators of impairments of our assets during the first quarter and as a result recognised impairments in respect of our drilling units totaling $1,230 million and impairments of our investments of $47 million.

Archer convertible note

On March 13, 2020, Archer announced that it had successfully secured a consensual amendment and extension to its debt facilities. This included a reduction to the principal and interest on the convertible loan due to us from Archer, in exchange for a reduced stock conversion price and removal of certain restrictions regarding the sale or conversion of the loan (see Note 26—“Related party transactions” for details regarding the loan). Following the amendment, the principal due on the loan was reduced to $13 million and the stock conversion price decreased from $2.083 per share to $0.40. The maturity date of the loan was extended to April 1, 2024. The transaction was executed on April 9, 2020.

New York Stock Exchange delisting

On March 26, 2020, we received written notice from the NYSE that we were not in compliance with the continued listing standard with respect to the minimum average share price required of $1.00 per share over a period of thirty consecutive trading days. On April 8, 2020, the Company notified the NYSE of its intention to cure the non-compliance.

However, in light of the significant impact of COVID-19 on the Company and the drilling industry as well as the challenges posed by the continued volatility in the offshore oil and gas industry, and taking into account other factors associated with maintaining a NYSE listing, the Board of Directors determined that it is in the best interests of the Company to voluntarily withdraw our common shares from listing on the NYSE. We intend to file a Form 25 with the SEC on or about June 11, 2020 in order to delist our common shares from the NYSE, which will occur ten days thereafter upon effectiveness of the Form 25. Accordingly, we anticipate that the last day of trading on the NYSE will be on or about June 19, 2020, which is the last trading day prior to effectiveness of the Form 25. The Company anticipates that its common shares will trade in the over the counter (“OTC”) market if one or more brokers chooses to make a market for our common shares; however, there can be no assurances regarding any such trading.

Seadrill Limited will retain its listing on the Oslo Børs under the ticker symbol ‘SDRL’ and expects to continue to make required filings with the SEC.

Contract Backlog

Contract Backlog includes all firm contracts at the maximum 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 excludes revenues for mobilization, demobilization and contract preparation or other incentive provisions and excludes backlog relating toNon-Consolidated Entities.

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The disruptive impacts of the oil price decline andCOVID-19 could have an adverse effect on our ability to realize our backlog. Our customers may seek to terminate or renegotiate our contracts, which could result in lower dayrates or less favorable economic terms.

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

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. For example, an alternative contractual dayrate, such as awaiting-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. In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period.

We project our March 31, 2020 contract backlog to unwind over the following periods:

The actual amounts of revenues earned and the actual periods during which revenues are earned will also differ from the amounts and periods shown in the tables above due to various factors, including shipyard and maintenance 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.

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Market Overview and Trends

The below table shows the average oil price for the three months ended March 31, 2020 and for each year ended December 31 over the period 2016 to 2020. The Brent oil price at March 31, 2020 was $23 and $35 as of May 31, 2020.

Although we saw a stabilization in the oil and gas market in 2019, recent developments have created significant uncertainty on the industry’s trajectory for 2020. The global impacts surrounding theCOVID-19 outbreak are rapidly evolving and increasingly dynamic. In addition, recent actions by certain members of OPEC and its partners have contributed to the substantial decline in the price of Brent oil, with a low of $22 per barrel on March 30, 2020. We expect this volatility to continue and if the price of oil declines further and/or remains at a low price for an extended period there could be a material adverse effect on our business, financial condition, and results of operations.

The below table shows the global number of rigs on contract and marketed utilization at March 31, 2020 and for each of the four preceding years ending December 31.

Floater

During 2019 there was an increase in the number of opportunities for floaters and net floater supply continued to decline which improved utilization. Whilst we saw an overall improvement to marketed utilization, thesub-segments continued to recover at varying rates. The harsh environment trended ahead due to high demand for high specification units relative to their supply. There was still excess supply of benign environment units which slowed the recovery in this market. While utilization remained consistent in Q1 2020, the impact ofCOVID-19 and the oil price decline are expected to decrease utilization across allsub-segments going forward and put downward pressure on dayrates.

Jack-up

There were positive trends in thejack-up market with utilization and dayrates improving throughout 2019. The market preference for premium units continued, resulting in a bifurcation of rates and utilization for these assets. We expect these patterns to change given recent events.

Results of Operations

The tables included below set out financial information for the three months ended March 31, 2020 and the three months ended March 31, 2019.

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1) Operating revenues

Operating revenues consist of contract revenues, reimbursable revenues, management contract revenues and other revenues. We have analyzed operating revenues between these categories in the table below:

a) Contract revenues

Contract revenues represent the revenues that we earn from contracting our drilling units to customers, primarily on a dayrate basis. We have analyzed contract revenues by segment in the table below.

Contract revenues 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. We have set out movements in these key indicators of performance in the sections below.

We calculate the average number of rigs on 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 for the periods covered is set out in the below table:

The average number of floaters on contract for the three month period ended March 31, 2020 decreased by two from the three months ended March 31, 2019 as theWest Jupiter completed its contract with Total in Nigeria in December 2019 and theWest Saturn with Equinor in October 2019.

The average number ofjack-ups on contract for the three months ended March 31, 2020 increased by one compared to March 31, 2019. This was primarily due to theWest Cressidareturning to operations in August 2019 after being warm stacked since December 2018.

We calculate the average contractual dayrate by dividing the aggregate contractual dayrates during a reporting period by the aggregate number of rig operating days for the reporting period. We have set out the average contractual dayrates for the periods presented in the below table:

The average contractual dayrate for floaters decreased by $18k between the three months ended March 31, 2020 and March 31, 2019. TheWest Telluswas on a lower dayrate for the three months ended March 31, 2020 compared to the previous year and theWest Jupiter completed its contract with Total in Nigeria in December 2019.

The average contractual dayrate forjack-ups for the three months ended March 31, 2020 was consistent with the three months ended March 31, 2019.

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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 contractual operating rate, such as planned downtime for maintenance. In such situations, economic utilization reduces below 100%.

Economic utilization for each of the periods presented in this report is set out in the table below:

The economic utilization for floaters andjack-ups for the three months ended March 31, 2020 remained consistent to the three months ended March 31, 2019.

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.

c) Management contract revenue

Management contract revenues for the three months ended March 31, 2020 were $105 million (three months ended March 31, 2019: $37 million) representing revenues related to contracts where we are providing management, operational and technical support services to other parties.

The increase for the three months ended March 31, 2020 was due to higher revenues on our rig management arrangements with Northern Ocean and Sonadrill and higher reimbursable revenues for the first mobilizations of the Northern Ocean rigsWest Mira andWest Bollsta and the Sonangol rigsLibongos andQuenguela.

d) Other revenues

Other revenues include the following:

Other revenues for the three months ended March 31, 2020 included related party charter income earned by theWest Castor andWest Telesto, which have been leased to Gulfdrill.

2) Operating expenses

Total operating expenses include vessel and rig operating expenses, reimbursable expenses, management contract expenses, depreciation of drilling units and equipment, amortization of of favorable and unfavorable contracts, and selling, general and administrative expenses. We have analyzed operating expenses between these categories in the table below:

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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.

We have analyzed vessel and rig operating expenses by segment in the table below.

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 incurone-time costs for activities such as preservation and severance when we cold stack a rig. We also incur significant costs whenre-activating a rig from cold stack, a proportion of which is expensed as incurred.

We have analyzed the average number of rigs by status and segment over the reporting period in the table below:

Vessel and rig expenses for the floater segment decreased by $28 million for the three months ended March 31, 2020compared to the three months ended March 31, 2019. This decrease was primarily due to there being fewer operating rigs and one additional cold stacked unit, as theWest Jupiter andWest Saturn completed contracts in the fourth quarter of 2019 and theWest Eclipse was cold stacked after completing a mooring upgrade in the second quarter of 2019.

Vessel and rig expenses for thejack-up segment decreased by $11 million for the three months ended March 31, 2020compared to the three months ended March 31, 2019. This decrease was primarily due to theWest Castor being chartered to the Gulfdrill joint venture in the fourth quarter of 2019. In the comparative period the rig incurred reactivation costs.

ii.    Management contract expenses

Management contract expenses increased by $71 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019. This was primarily because we have incurred higher reimbursable expenses on mobilization of the Northern Ocean rigs,West BollstaandWest Mira, and the Sonangol rigs,LibongosandQuenguela,as well as higher expenses on our rig management arrangements with Northern Ocean and Sonadrill since the commencement of drilling contracts for theWest Mira andLibongos at the end of 2019.

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. The decrease for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was primarily due to assets becoming fully depreciated at the end of 2019.

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On emergence from Chapter 11 and application of fresh start accounting, we recognized intangible assets and liabilities for favorable and unfavorable drilling contracts at fair value. We amortize these assets and liabilities over the remaining contract period and classify the amortization under operating expenses. The majority of our favorable and unfavorable contracts completed in prior periods, therefore the amount recognized in the three months ended March 31, 2020 was nil.

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.

3) Other operating items

During the first quarter, the impact ofCOVID-19 on the global economy has had a negative impact on our industry. As global oil demand has fallen, we have also seen an increase in oil supply, leading to a surplus of reserves. Brent crude has fallen from $66 as at December 31, 2019 to $23 as at March 31, 2020.

The oil price decline has led to pressures on our customers to reduce their capital expenditures in the near-term until there is sufficient recovery in the oil price. As a consequence, this has led to reduced forecasted day rates and utilization for 2020 and beyond and therefore we have concluded that an impairment triggering event had occurred for our drilling unit fleet.

On assessment of asset recoverability through an estimated undiscounted future net cash flow we calculated the value to be lower than the carrying value, resulting in an impairment against our long-lived assets of $1,230 million.

Other operating income for the three months ended March 31, 2020 represents the settlement of a loss of hire insurance claim in relation to the subsea equipment incident on theSevan Louisiana.

Other operating income for the three months ended March 31, 2019 represents cash received for the recovery of a receivable balance previously written down to nil on fresh start.

4) Other income and expense

We have analyzed other income and expense into the following components:

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i.    Interest Income

Interest income relates to interest earned on cash deposits and other related party loans.

ii. Interest expense

We have analyzed interest expense into the following components:

Cash andpayment-in-kind interest on debt facilities

We incur cash andpayment-in-kind interest on our debt facilities. This is summarized in the table below.

We are charged interest on our senior credit facilities at LIBOR plus a margin. There has been a decrease in LIBOR rates contributing to the decrease in interest expense on our senior credit facilities.

On emergence from Chapter 11 we issued $880 million of Senior Secured Notes. We incur 4% cash interest and 8%payment-in-kind interest on these notes. On November 14, 2018 and April 10, 2019 there were two redemptions. As at March 31, 2020, there was $495 million principal outstanding on the notes, which includes $37 million of accruedpayment-in-kind interest on our Senior Secured Notes which was compounded on July 15, 2019 and January 15, 2020 with additional notes being issued.

Our Consolidated Balance Sheet includes approximately $0.6 billion of debt facilities held by subsidiaries of Ship Finance that we consolidate as variable interest entities. Our interest expense includes the interest incurred by these entities on those facilities.

Unwind of discount on debt

On emergence from Chapter 11 and application of fresh start accounting, we recorded a discount against our debt to reduce its carrying value to equal its fair value. The debt discount is unwound over the remaining terms of the debt facilities.

iii. Loss on impairment of equity method investments

During the first quarter, the impact ofCOVID-19 on the global economy has had a negative impact on our industry. As global oil demand has fallen, we have also seen an increase in oil supply, leading to a surplus of reserves. Brent crude has fallen from $66 as at December 31, 2019 to $23 as at March 31, 2020.

The oil price decline has led to pressures on our customers to reduce their capital expenditures in the near-term until we see a recovery in the oil price. As a consequence, this has led to reduced forecasted day rates and utilization for 2020 and beyond and therefore we have indicators of impairment against our investments. Following this impairment review, we concluded that our investments in Seadrill Partners were impaired in full and we recorded an impairment charge of $47 million.

iv. Share in results from associated companies

Share of results in associated companies represents our share of earnings or losses in our investments accounted under the equity method. We reduced the carrying value of our equity method investments when we applied fresh start accounting on emergence from Chapter 11. This led to the recognition of basis differences between the book value of the drilling unit or pipe laying service vessel and contract intangible balances recorded in the balance sheets of our equity method investees and the implied value of those assets reflected in the equity method investments recorded in our Consolidated Balance Sheet. We unwind these basis differences over the lives of the associated assets and liabilities when calculating our share of results of the equity method investments.

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We have analyzed our share of results in associated companies by equity method investment below:

The share of results from associated companies for the three months ended March 31, 2020 was an increased loss compared to the three months ended March 31, 2019 due primarily to the losses from our direct investments in Seadrill Partners. The share of Seadrill Partners loss recognized in the three months ended March 31, 2020 was due to impairments recognized against their long-lived assets.

v. Loss on derivative financial instruments

On May 11, 2018, we bought an interest rate cap from Citigroup for $68 million. The interest rate cap mitigates our exposure to future increases in LIBOR over 2.87% from our floating bank debt. We also have a conversion option on a bond issued to us by Archer Limited. We record both of these assets at fair value.

The loss on derivatives for the three months ended March 31, 2020 of $1 million (three months ended March 31, 2019: $27 million) comprised a fair value loss on our interest rate cap derivatives due to a decrease in forward interest rates.

vi. Foreign exchange loss

Foreign exchange gains and losses relate to exchange differences on the settlement or revaluation of monetary balances denominated in currencies other than the US Dollar.

In May 2019, we placed a total of 330 million Brazilian Reais of collateral with BTG bank under a letter of credit arrangement. Following a significant weakening of the Brazilian Reais against the US Dollar during the current quarter, this generated an $18 million foreign exchange loss in three months ended March 31, 2020.

vii. Loss on marketable securities

The loss on marketable securities reflect the changes inmark-to-market movements in our investments in Seadrill Partners common units and our Archer shares.

viii. Impairment of convertible bond from related party

On March 13, 2020, Archer announced completion of a refinancing, which included agreed renegotiated terms on the convertible loan. The updated terms amended the loan balance to $13 million that bears interest of 5.5%, matures in April 2024 and an equity conversion option. The renegotiated terms resulted in a $29 million impairment being recognized following a reduction in loan balance and an increase to the discount rate.

4) Income taxes

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.

Liquidity and Capital Resources

1) Introduction

We operate in a capital-intensive industry. We have historically funded acquisitions of drilling units and investments in associated companies through a combination of debt and equity issuances and from cash generated from operations. Although we restructured our debt through the Chapter 11 Reorganization, we remain a highly leveraged company with outstanding borrowings on our external debt facilities totaling $6.8 billion as at March 31, 2020.

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Our liquidity requirements relate to servicing and repaying our debt, making capital investments, funding working capital requirements and maintaining adequate cash reserves to mitigate the effects of fluctuations in operating cash flows. Most of our contract and other revenues are received between 30 and 60 days in arrears, and most of our operating costs are paid monthly. We have historically relied on our cash generated from operations to meet our short-term liquidity needs. We believe our current resources, available cash and cash from operations will be sufficient to meet our working capital requirements and other obligations as they fall due for at least the next twelve months following the date of this report.

Our debt agreements contain cross-default provisions (or, in certain instances, cross-acceleration provisions), meaning that if we are in default under one of our debt agreements, amounts outstanding under our other debt agreements may also be in default, accelerated and become due and payable. In addition, we have provided guarantees over certain debt facilities of our affiliates and related companies, and the lenders under such facilities could look to us to meet such liabilities if such affiliates and related companies are unable to meet their obligations. If any of these events occur, we may not be able to satisfy our obligations and our ability to continue our operations or generate any cash flow in the future could be impaired.

Since the fourth quarter of 2019, we have been engaged in discussions with our secured lenders regarding potential amendments to our credit facilities to provide operational flexibility and additional near-term liquidity by, among other things, converting certain interest payments under our credit facilities topayment-in-kind (“PIK”) interest and deferring certain scheduled amortization payments (or increasing the aggregate amount of such payments that may be converted to loans payable at the final scheduled maturity date of the relevant facility pursuant to the amortization conversion election provisions contained in the facility agreements). Our debt service is anticipated to be primarily comprised of interest through at least Q1 2021 because our facility agreements contain certain provisions that allow us to elect to defer and convert up to $500 million in the aggregate of scheduled amortization payments under certain of our credit facilities. We have already elected to use a portion of this capacity with respect to the scheduled amortization installments under our credit facilities occurring in Q1 and Q2 2020. We intend to continue exercising this option for each subsequent scheduled amortization payment date until such capacity is fully utilized; however, we cannot guarantee that we will be able to satisfy the conditions set forth in the facility agreements in order to be able to do so. We have also forecasted that we will not be able to meet the requirements under our ongoing liquidity financial covenant contained in the facility agreements within a twelve-month period following the date of this report and had requested consent for certain liquidity enhancing measures in order to mitigate this. Failure to comply with such liquidity requirements could result in a default under the terms of our facility agreements if we are unable to obtain a waiver or amendment from our lenders for suchnon-compliance. We had also requested that our lenders consent to an extension of the periods before which we are required to comply with the net leverage and debt service coverage financial covenants in our facility agreements because we currently anticipate that we will not be able to meet these requirements when such covenants begin to be tested at the end of Q1 2021.

Whilst substantial support was indicated by our secured lenders for the consents discussed above, as certain of the amendments impacting economic terms required 100% approval across 43 institutions, recent market uncertainties have prevented a coalescing of views. As a consequence, Seadrill has decided not to proceed with the bank consent and has retained financial and legal advisors to prepare for a comprehensive restructuring of the balance sheet. Whilst we continue to evaluate various alternatives to address the cost of debt service and overall volume of debt, we anticipate that a comprehensive restructuring may require a substantial conversion of our indebtedness to equity. With $1.2 billion cash on hand Seadrill believes that this provides sufficient liquidity to complete a comprehensive restructuring process. However, until such time that an agreement is reached to restructure our borrowing commitments, substantial doubt remains over our ability to continue as a going concern.

The Company’s business operations remain unaffected by these amendment negotiations and related contingency planning efforts, and the Company expects to meet its ongoing customer and business counterparty obligations as they become due.

Our funding and treasury activities are conducted in accordance with our corporate policies, which aim to maximize returns while maintaining appropriate liquidity for our operating requirements. Cash and cash equivalents are held mainly in U.S. dollars, with lesser amounts held in Norwegian Kroner, Brazilian Reais and Great British Pounds.

This section discusses the most important factors affecting our liquidity and capital resources.

2) Liquidity

Our level of liquidity fluctuates depending on a number of factors. These include, among others, our contract backlog, economic utilization achieved, average contract day rates, timing of accounts receivable collection, timing of payments for operating costs and other obligations.

Our liquidity comprises cash and cash equivalents. The below table shows cash and restricted cash balances for each period presented.

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We have shown our sources and uses of cash by category of cash flow in the below table.

This reconciles to the total cash and cash equivalents, including restricted, which is as follows:

a) Cash flows from operating activities

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

We calculate cash flows from operating activities using the indirect method as summarized in the below table.

Market conditions in the offshore drilling industry in recent years have led to lower levels of spending for offshore exploration and development. This has negatively affected our revenues, profitability and operating cash flows. During the three months ended March 31, 2020 and three months ended March 31, 2019 our cash flows from operating activities were negative, as cash receipts from customers were insufficient to cover operating costs, payments for long-term maintenance of our rigs, interest payments and tax payments.

b) Cash flows from investing activities

Net cash flows from investing activities for the three months ended March 31, 2020 were primarily from capital expenditures and purchase of call option fornon-controlling interest shares offset by contingent consideration payments from Seadrill Partners from the sale of the drillshipWest Vela in 2015.

Net cash flows from investing activities for the three months ended March 31, 2019 were primarily generated by contingent consideration payments from Seadrill Partners from the sale of the drillshipWest Velain 2015. These cash inflows were offset by capital expenditures.

c) Cash flows from financing activities

Net cash flows from financing activities for the three months ended March 31, 2020 were driven by debt repayments and prepayment of future debt obligations for our three consolidated variable interest entities managed and financed by SFL Corporation Ltd from whom we lease rigs under sale and leaseback arrangements.

Net cash flows from financing activities for the three months ended March 31, 2019 were related to repayments of debt for our three consolidated variable interest entities managed and financed by SFL Corporation Ltd.

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Contractual Obligations

At March 31, 2020, we had the following contractual obligations and commitments:

breached, this would cause our debt obligations to become due prior to their contractual maturities.

In addition to the above, as of March 31, 2020 we have $80 million of unrecognized tax benefits, including interest and penalties, which if recognized, would have a favorable impact on the Company’s effective tax rate.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to several market risks, including credit risk, foreign currency risk and interest rate risk. Our policy is to reduce our exposure to these risks, where possible, within boundaries deemed appropriate by our management team. This may include the use of derivative instruments.

Credit risk

We have financial assets, including cash and cash equivalents, marketable securities, other receivables and certain amounts receivable on derivative instruments. These assets expose us to credit risk arising from possible default by the counterparty. Most of the counterparties are creditworthy financial institutions or large oil and gas companies. We do not expect any significant loss to result fromnon-performance by such counterparties.

We do not demand collateral in the normal course of business. The credit exposure of derivative financial instruments is represented by the fair value of contracts with a positive fair value at the end of each period, adjusted for ournon-performance credit risk assumption.

Concentration of risk

There is a concentration of credit risk with respect to cash and cash equivalents to the extent that most of the amounts are carried with Citibank, Nordea Bank Finland Plc, Danske Bank A/S, BNP Paribas, BTG Bank and ING Bank N.V. We consider these risks to be remote. We also have a concentration of risk with respect to customers. For details on the customers with greater than 10% of total revenues, refer to Note 4—Segment information.

Foreign exchange risk

As is customary in the oil and gas industry, most of our revenues and expenses are denominated in U.S. dollars, which is the functional currency of most of our subsidiaries and equity method investees. However, a portion of the revenues and expenses of certain of our subsidiaries and equity method investees are denominated in other currencies. We are therefore exposed to foreign exchange gains and losses that may arise on the revaluation or settlement of monetary balances denominated in foreign currencies.

Our foreign exchange exposure primarily relates to foreign denominated cash and working capital balances. Historically, these exposures have not caused a significant amount of fluctuation in net income or cash flows and therefore we have not hedged them. However, there was an $18 million foreign exchange loss recognized in the current period which primarily related to a restricted cash balance denominated in Brazilian Reais (which depreciated by c. 20% against the US Dollar during the quarter as a consequence of the current uncertainties in the global economy following theCOVID-19 outbreak).

Interest rate risk

Our exposure to interest rate risk relates mainly to our floating rate debt and balances of surplus funds placed with financial institutions. We manage this risk through the use of derivative arrangements.

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On May 11, 2018, we purchased an interest rate cap for $68 million to mitigate our exposure to future increases in LIBOR on our Senior Credit Facility debt. The interest rate cap is not designated as a hedge and we do not apply hedge accounting. The capped rate against the3-month US LIBOR is 2.87% and covers the period from June 15, 2018 to June 15, 2023.

We have set out our exposure to interest rate risk on our net debt obligations at March 31, 2020 in the table below:

Critical Accounting Estimates

The preparation of the Consolidated Financial Statements 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. The basis of preparation and significant accounting policies are disclosed in our annual report on Form20-F.

Critical accounting estimates that have significantly impacted the three months ended March 31, 2020 are as follows:

Drilling Units

Generally, the carrying amount of our drilling units including rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. However, drilling units acquired through a business combination or remeasured through the application of fresh start accounting are measured at fair value as of the date of acquisition or the date of emergence, respectively. Our drilling units are subject to various estimates, assumptions, and judgments related to capitalized costs, useful lives and residual values, and impairments.

Our estimates, assumptions, and judgments reflect both historical experience and expectations regarding future operations, utilization and performance. At March 31, 2020, the carrying amount of our drilling units was close to $5 billion, representing 68% of our total assets.

Useful lives and residual value

The cost of our drilling units less estimated residual value is depreciated on a straight-line basis over their estimated remaining useful lives. The estimated useful life of our semi-submersible drilling rigs, drillships andjack-up rigs, when new, is 30 years.

The useful lives of rigs and related equipment are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. Were-evaluate the remaining useful lives of our drilling units as and when events occur which may directly impact our assessment of their remaining useful lives. This includes changes in the operating condition or functional capability of our rigs as well as market and economic factors. The use of different estimates, assumptions and judgments in establishing estimated useful lives and residual values could result in significantly different carrying values for our drilling units which could materially affect our results of operations.

Impairment considerations

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.

With regard to our older drilling units, which have relatively short remaining estimated useful lives, the results of impairment tests are particularly sensitive to management’s assumptions. These assumptions include the likelihood of the unit obtaining a contract upon the expiration of any current contract, and our intention for the drilling unit should no contract be obtained, including warm/cold stacking or scrapping. The use of different assumptions in the future could potentially result in an impairment of older drilling units, which could materially affect our results of operations.

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Impairment recognized and methodology

During the first quarter, the impact ofCOVID-19 on the global economy had a negative impact on our industry. As global oil demand has fallen, we have also seen an increase in oil supply, leading to a surplus of reserves and a decline in the oil price. As a consequence, this has led to reduced forecasted day rates and utilization for 2020, and an extended time for these to recover in future years as the market supply and demandre-balance. We have therefore concluded that an impairment triggering event had occurred for our drilling unit fleet in the three months ended March 31, 2020.

Given a material change in the macro environment we have also had to assess whether the continued cold stacking of assets and the associated reactivation costs produces the investment return stakeholders deserve. These evaluations have led us to believe that there is an increased probability that certain drilling units may not return to the market and would need to be scrapped.

We assess recoverability of our drilling units by first evaluating the estimated undiscounted future net cash flows based on a number of assumptions, including projected dayrates, utilizations of the units, operating costs, maintenance costs, reactivation costs, likelihoods of any required scrapping activity, and applicable tax rates. These assumptions are necessarily subjective and the use of different assumptions could produce results that differ from those reported. These include uncertainties over future demand for services, dayrates, expenses and other market-based future events, and expectations may not be indicative of future outcomes. Our estimate of fair value generally requires us to use significant unobservable inputs, therefore making it a Level 3 fair value measurement.

There is significant uncertainty in the industry trajectory for 2020 and the recovery of the market in our forecasts beyond. Altering the timing or the rates used in our net cash flows could lead to significantly different estimated fair values. As a result, the assessment as to whether an asset should be impaired or otherwise is dependent on the timing of assessment and current market expectations. As the long-range outcomes are unpredictable due to the current industry volatility, it is not possible to reasonably quantify the impact of changes in the assumptions used in our projected cash flows.

As at March 31, 2020, the undiscounted future net cash flows were not greater than the carrying value for seven of our drilling units; this led to an impairment of the rig carrying value. Following an assessment of recoverability, utilizing a discounted cash flow model incorporating assumptions as noted above and a weighted average cost of capital of 12.8%, we recorded an impairment charge of $1,230 million. We have recognized the impairment within “Impairment of long-lived assets” in our Consolidated Statement of Operations for the three months ended March 31, 2020.

Impairment of Equity Method Investment in Seadrill Partners

Overview

Seadrill Partners is an international offshore drilling contractor formed in 2012. It has a fleet of 11 drilling units. This comprises 4 drillships, 4 semi-submersible rigs and 3 tender rigs. All the rigs were acquired from Seadrill between 2012 to 2015. Seadrill is responsible for managing, marketing and operating the rigs and charges SDLP a management fee for these services.

Seadrill Partners has issued 3 categories of equity instrument. This includes two classes of stock (“common units” and “subordinated units”) and incentive distribution rights (“IDRs”). We have several investments in Seadrill Partners. These include (i) 35% of the common units (2.5 million out of 7.5 million total units); (ii) 100% of the subordinated units (1.6 million units); and (iii) 100% of the IDRs.

i. Common Units

The common units do not meet the definition of common stock under US GAAP as they are not the lowest class of stock (because they have an additional right to dividends compared to the subordinated units). The common units have a readily ascertainable fair value and are therefore recorded at fair value with gains or losses taken to the Consolidated Statement of Operations. Refer to Note 11 in the accompanying financial statements for further information.

ii. Subordinated Units and iii. IDRs

In September 2019, we recognized impairments against the subordinated units and IDRs to take their carrying value down to nil.

Direct investments in Seadrill Partners

In addition to the above holdings, we have investments in the common stock of 4 operating companies (“OPCOs”) controlled by Seadrill Partners. This includes (i) 42% interest in Seadrill Operating LLP which wholly owns 4 rigs and has a 56% interest in 1 rig; (ii) 49% interest in Seadrill Capricorn LLC which wholly owns 4 rigs and (iii) 39% interest in Seadrill Deepwater Drillship Ltd and 49% interest in Seadrill Mobile Units Ltd which, together, own a 44% interest in 1 rig.

We account for these investments under the equity method. These investments were recorded at fair value when we applied fresh start accounting on July 2, 2018. At the end of each reporting period, we (i) increase (or decrease) the value of these investments for our share of theafter-tax profits (or losses) of the entities and (ii) amortize basis differences recorded against the investments on fresh start.

Impairment review

Each reporting period, we are required to consider whether there have been any indicators of ‘other than temporary impairment’ (“OTTI”) of our direct method equity method investments. We record an impairment charge for other-than-temporary declines in fair value when the fair value is not anticipated to recover above the carrying value within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required.

During the first quarter, the impact ofCOVID-19 on the global economy has had a negative impact on our industry. As global oil demand has fallen, we have also seen an increase in oil supply, leading to a surplus of reserves and a decline in the oil price. This has led to reduced forecasted dayrates and utilization for 2020, and an extended time for these to recover in future years as market supply and demand re-balance. We have therefore concluded that an indicator of impairment against our investments arose in the quarter.

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Impairment

Having identified an indicator of OTTI, we were required to value our direct investments in Seadrill Partners to calculate the impairment at March 31, 2020.

We valued our investments in the direct interests using an income approach which discounted future free cashflows (“DCF model”). The cash flows were estimated over the remaining useful economic lives of the underlying assets and discounted using an estimated market participant weighted average cost of capital of 12.8%.

The DCF model derived an enterprise value of the OPCOs, after which associated debt was subtracted to provide equity values. Our DCF model considered a range of scenarios to reflect different potential refinancing outcomes for Seadrill Partners. The key assumptions used in the DCF were derived from significant unobservable inputs based on our best judgments and assumptions available at the time of performing the impairment test.

The underlying assumptions used to model future rig cash flows used a methodology that examined historical data for each rig, considering the rig’s age, rated water depth and other attributes and then assessed its future marketability considering the current and projected market environment at the time of assessment.

Other assumptions, such as operating, maintenance and inspection costs, were estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment. The probability applied to each scenario was set with reference to its Term Loan B (“TLB”) traded price as at March 31, 2020.

These assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our assumptions involve uncertainties about future demand for our services, dayrates, expenses and other market based future events, and expectations may not be indicative of future outcomes. If actual events differ from these estimates, or to the extent that these estimates are adjusted in the future, our financial condition and results of operations could be affected in the period of any such change of estimate.

We valued our investments in the direct interests using an option pricing model. The assumptions used in the model were derived from both observable and unobservable inputs and are based on management’s judgments and assumptions available at the time of performing the impairment test. The method values different tranches in the capital structure in sequence of seniority. We employ significant judgment in developing these estimates and assumptions.

We calculated the fair value of our investments in Seadrill Partners direct interests to be nil. The value of our investments prior to impairment was $47 million, after recognizing a $75 million share of loss in the three months ended March 31, 2020.

As a result, we recorded an impairment charge of $47 million. We have recognized the impairment of these investments within “Loss on impairment of equity method investments” in our Consolidated Statement of Operations for the three months ended March 31, 2020.

We have summarized the carrying value of our investments before and after this impairment review in the below table.

Current expected credit losses

As set out in Notes 2 and 3 to the Consolidated financial statements included in this report, we adopted accounting standard update2016-13 effective January 1, 2020. Under this guidance we are required to record allowances for the expected future credit losses to be incurred on trade and loan receivable balances.

We have used aprobability-of-default model to estimate these expected credit losses. Under this methodology we use data such as customer credit ratings, maturity of loan, security of loan, and incorporate historical data published by credit rating agencies, to estimate the chance of default and loss given default. We then multiply the balance outstanding by the estimated chance of default and loss given default to calculate the allowance required for the expected credit loss.

To estimateprobability-of-default we have cross referenced the customer credit ratings and loan maturities for our receivable balances against historical default rates published by credit rating agencies. The counterparties to our related party receivable balances do not typically have published credit ratings, in which case we have estimated a shadow credit rating. We estimated loss-given-default based on historical recovery rates published by credit rating agencies for claims with similar security and priority as the receivable being assessed.

Fair Value of Archer Convertible Bond

At each reporting period, we record the Archer bond at fair value in Seadrill’s balance sheet, with any gains or losses being recorded in other comprehensive income, unless the convertible bond is impaired, under the impairment guidance of ASC326-30, in which case the impairment loss is recorded in net income.

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The Archer convertible debt instrument is bifurcated into two elements (i) the debt component and (ii) embedded conversion option.

i. Debt component

The fair value of the debt component is derived using the discounted cash flow model including assumptions relating to cost of debt and credit risk associated to the instrument. The principal andpayment-in-kind coupon is discounted at a rate of 27.6%. The additional key inputs used in the model is the principal initial value of $13 million,payment-in-kind interest of 5.5% and maturity date of April 1, 2024.

ii. Embedded conversion option

The fair value of the embedded derivative option is calculated using a modified version of the Black-Scholes formula for a currency translated option. The bond can be converted into equity at any stage between now and April 1, 2024. When calculating the fair value we have used themid-point in this range.

The key model input assumptions include Archer’s share price in NOK, NOK/ USD FX volatility and historical and forecasted equity volatility. As the conversion price is significantly below the current trading price the fair value of the conversion option is immaterial. Our estimate of fair value generally requires us to use significant unobservable inputs, therefore making it a Level 3 fair value measurement.

Redeemablenon-controlling interests

Subsequent to filing bankruptcy petitions, the Predecessor executed a Transaction Support Agreement (“TSA”) on April 4, 2018 with a minority shareholder of one of our subsidiaries, Asia Offshore Drilling Limited (“AOD”). The purpose of the TSA was to provide a framework for a monetization event for the minority shareholder of AOD as well as obtain unanimous approval of the AOD board of directors (which included the minority shareholder) in order for AOD to become a party to the TSA and participate in the Predecessor’s broader debt restructuring under its Chapter 11 reorganization. The TSA executed between the parties provides an option to the holders ofnon-controlling interest shares to sell the shares it owns to Seadrill Limited subject to a price ceiling (“Put Option”). After the end of the effective period of the Put Option, if the right remains unexercised, Seadrill Limited has the option to purchase thenon-controlling interest in AOD at a price subject to the floor price (“Call Option”). The Put Option generates a redemption feature for thenon-controlling interest holder that is outside the control of Seadrill Limited.

To calculate the fair value of thenon-controlling interest shares, we estimated the fair value of AOD in total and then allocated this between the shares held by us and by those held by thenon-controlling interest. We estimated the fair values of AOD in total by adjusting the Consolidated Balance Sheet position of AOD as at each reporting period for an updated fair value of the three drilling units:AOD I, AOD II and AOD III. We derived the fair value of the three drilling units using a market approach discounted using a weighted average cost of capital of 12.8%. We derived the fair value of the external debt facilities with a discounted cash flow using a weighted average cost of debt of 4%.

Income taxes

Seadrill is a Bermuda company that has a number of subsidiaries and affiliates in various jurisdictions. We are not currently required to pay income taxes in Bermuda on ordinary income or capital gains because we qualify as an exempt company. We have received written assurance from the Minister of Finance in Bermuda that we will be exempt from taxation until March 2035. Certain of our subsidiaries operate in other jurisdictions where income taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income tax rates and methods of computing taxable income vary substantially between jurisdictions. Our income tax expense is expected to fluctuate from year to year because our operations are conducted in different tax jurisdictions and the amount ofpre-tax income fluctuations.

The determination and evaluation of our annual group income tax provision involves the interpretation of tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events, such as amounts, timing and the character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are more likely than not sustainable, based solely on the technical merits and considerations of the relevant taxing authorities widely understood administrative practices and precedence. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year.

While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. 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. 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 at 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. In addition, our uncertain tax positions are estimated and presented within other current liabilities, other liabilities, and as reductions to our deferred tax assets within our Consolidated Balance Sheets. Refer to Note 8– “Taxation” to our Consolidated Financial Statements included herein for further information.

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Risk Factors

Please see “Item 3D - Risk Factors” in our Annual Report on Form 20-F for the year ended December 31, 2019 for a discussion of the risk material to our business. Additionally, the risk factor below has been updated as a result of recent developments.

We intend to voluntarily delist our common stock from the NYSE.

On June 1, 2020, our Board of Directors approved the voluntarily withdraw our common shares from listing on the NYSE. We intend to file a Form 25 with the SEC on or about June 11, 2020 in order to delist our common shares from the NYSE, which will occur ten days thereafter upon effectiveness of the Form 25. Accordingly, we anticipate that the last day of trading on the NYSE will be on or about June 19, 2020, the last trading day prior to the effectiveness of the Form 25, at which point our OSE listing will become our primary listing, subject to our compliance with the OSE’s continued listing standards. The Company anticipates that its common shares will trade in the over the counter (“OTC”) market if one or more brokers chooses to make a market for our common shares and; however, there can be no assurances regarding any such trading.

A delisting of our common shares from the NYSE, even if a trading market subsequently develops on an over-the-counter market, could negatively impact us because it could: (i) reduce the liquidity and market price of our common shares, (ii) reduce the number of investors willing to hold or acquire our common shares, which could negatively impact our ability to raise equity financing, (iii) limit our ability offer and sell freely tradable securities, including under U.S. state securities laws, thereby preventing us from accessing the public capital markets, (iv) impair our ability to provide equity incentives to our employees and (v) lead to a default under one or more of our credit facilities under certain circumstances.

Certain of our credit facilities include a covenant requiring our common shares to be listed on the NYSE or the OSE or, in certain cases another internationally recognized stock exchange. While the voluntary delisting of our common shares from the NYSE will not breach this reporting covenant, if our common shares then were to be delisted from the OSE and not listed on another internationally recognized exchange permitted under such credit facilities, we could be in default under such facilities. Given the cross-default and cross-acceleration provisions in our other debt agreements, we could be in default under those other debt agreements as well, with the result that some or all of our indebtedness could be declared immediately due and payable (or accelerated after the expiration of any applicable grace period), and we may not have sufficient assets available to satisfy our obligations.

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Seadrill Limited

INDEX TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

F-1

Seadrill Limited

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

for the three months ended March 31, 2020 and three months ended March 31, 2019

See accompanying notes that are an integral part of these unaudited Consolidated Financial Statements.

F-1

Seadrill Limited

UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

for the three months ended March 31, 2020 and three months ended March 31, 2019

See accompanying notes that are an integral part of these unaudited Consolidated Financial Statements.

F-2

Seadrill Limited

UNAUDITED CONSOLIDATED BALANCE SHEETS

as at March 31, 2020 and December 31, 2019

See accompanying notes that are an integral part of these unaudited Consolidated Financial Statements.

F-3

Seadrill Limited

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

for the three months ended March 31, 2020 and three months ended March 31, 2019