SDRL Seadrill Limited

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13A-16 OR 15D-16

OF THE SECURITIES EXCHANGE ACT OF 1934

For the month of May 2019

Commission File Number 333-224459

SEADRILL LIMITED

(Exact name of Registrant as specified in its Charter)

Par-la-Ville Place, 4th Floor

14 Par-la-Ville Road

Hamilton HM 08 Bermuda

(441) 295-6935

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F  ☒            Form 40-F  ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Yes  ☐            No  ☒

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Yes  ☐            No  ☒

Seadrill Limited

Report on Form 6-K for the three months ended March 31, 2019

EXPLANATORY NOTE

This Form 6-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, 2019.

This Form 6-K is hereby incorporated by reference into our Registration Statements on (i) Form F-3 (Registration No. 333-224459), and (ii) Form S-8 (Registration No. 333-227101).

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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 Form 6-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 Form 6-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 Form 6-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 Form 20-F filed with the SEC on March 28, 2019 (SEC File No. 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, and, for periods before emergence from Chapter 11 Proceedings on July 2, 2018, to Old Seadrill Limited, any one or more of its consolidated subsidiaries, or to all such entities.

References to the term “Predecessor” refers to the financial position and results of operations of Seadrill prior to, and including, July 1, 2018. This is also applicable to terms “Seadrill,” “the Group,” “we,” “us,” “our,” “the Company” or “our Business” in context of events before emergence from Chapter 11 Proceedings on July 2, 2018.

References to the term “Successor” refers to the financial position and results of operations of Seadrill after July 2, 2018. This is also applicable to terms “Seadrill,” “the Group.” “we,” “us,” “our,” “the Company” or “our Business” in context of events after emergence from Chapter 11 Proceedings on July 2, 2018.

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 and jack-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 and major integrated oil and gas companies, 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 own and operate 35 drilling rigs and we manage and operate 18 rigs on behalf of Seadrill Partners, SeaMex and Northern Drilling.

Significant Developments

Receipt of overdue receivable

In January 2019, we received $26 million for the final settlement of an overdue receivable which was fully provided in the Predecessor company. This receivable was not recognized as an asset as part of fresh start accounting, and has been recognized as other operating income in our first quarter 2019 results.

Sonadrill joint venture

In February 2019, we entered into an agreement to establish a 50:50 joint venture with Sonangol called Sonadrill. The joint venture will operate four drillships, focusing on opportunities in Angolan waters. Each of the joint venture parties will bareboat two drillships into Sonadrill and we will manage and operate all the units. Seadrill will also manage the delivery and mobilization to Angolan waters of the two Sonangol drillships, from the shipyard in Korea, under a separate commissioning and mobilization agreement with Sonangol.

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Tender offer of New Secured Notes

In March 2019 we launched a consent solicitation process to amend the Senior Secured Notes indenture which included a $341 million subsequent tender offer to purchase $311 million of principal amount outstanding. As a result of this process the $311 million being purchased was reclassified as a current liability at March 31, 2019 and, following completion of the offer in April 2019, we re-purchased $311 million of New Secured Notes at a price of 107.

Dalian Newbuilds

The Newbuild contracts for the remaining two jack-up rigs from the Dalian shipyard, the West Dione and West Mimas, were terminated in February 2019 and April 2019, respectively.

The Seadrill contracting parties have commenced arbitration proceedings in respect of the eight newbuild jack-up rigs previously contracted to be delivered from the Dalian shipyard and are claiming for repayment of yard installments plus interest and damages. Seadrill has filed claims for these amounts as part of the Dalian insolvency proceedings in China. Dalian has maintained it has a damages claim in respect of each of the rigs. The newbuild contracts are all with limited liability subsidiaries of Seadrill and there are no parent company guarantees.

Contract Backlog

We define contract backlog as the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions.

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 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. In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period.

We project our May 23, 2019 contract backlog to unwind over the following periods:

The actual amounts of revenues earned and the actual periods during which revenues are earned will differ from the amounts and periods shown in the tables above due to various factors, including shipyard and maintenance 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, 2019 and for each year ended December 31 over the period 2015 to 2018. The Brent oil price at April 30, 2019 was $73.

We have seen a stabilization in the oil and gas market in 2019 with Brent oil prices remaining above $60 per barrel for most of the period. When combined with efficiencies across the industry, this has led to continued improved economics for our customers, which has in turn led to increased tendering activity and a positive trend in dayrates. We expect these trends to continue as our customers continue to increase their levels of investment.

The below table shows the global number of rigs on contract and marketed utilization at March 31, 2019 and for each of the four preceding years ending December 31.

Floater

The net floater supply has continued to decline globally as the number of scrapped rigs continue to outweigh newbuild rigs entering the market. The net attrition has positively impacted the recovery in the floater market as total and marketed supply start to align. There is high demand for high specification harsh environment units relative to their supply, which has led to increased dayrates and higher utilization within this segment. There is still an excess supply of benign environment units which has delayed the recovery in that market.

Whilst we expect further newbuild rigs to enter the market in 2020 and beyond, there remains a number of older units with no follow-on work identified which will be prime scrapping candidates, as 35-year classing expenditures can be costly and will only be completed if the future contract economics satisfy the cost. Instead, many rig owners will choose to retire a unit rather than incur the cost without a visible near-term recovery in demand. Larger drilling companies with diversified fleets will find it easier to make economic decisions and cold stack idle rigs as each individual unit represents a smaller percentage of the overall fleet. Cold stacked units will generally require a sufficient improvement in dayrates to overcome reactivation costs before they are reintroduced into marketed supply.

Jack-up

We have seen an improvement in shallow water markets and this has led to an increase in the number of contracted jack-ups. The increase in demand and dayrates have seen newbuild rigs begin to enter the market. As newer rigs with high specifications enter the jack-up market, this will lead to the accelerated attrition of older units. The shorter-term contract profile in this market lends itself to higher rig turnover. As these contracts start to lengthen, we expect rig turnover to normalize, which will positively aid the jack-up market recoverability.

Results of Operations

The tables included below set out financial information for the three months ended March 31, 2019 (Successor) and March 31, 2018 (Predecessor). The three months ended March 31, 2019 and March 31, 2018 are distinct reporting periods because of the application of fresh start accounting upon emergence from Chapter 11 bankruptcy on July 2, 2018. These periods may not be comparable to each other.

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1) Operating revenues

Operating revenues consist of contract revenues, reimbursable 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.

i. Average number of rigs on contract

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 was the same for the three months ended March 31, 2019 and the three months ended March 31, 2018. We re-activated the West Hercules for a new contract in the North Sea in April 2018 and the Sevan Louisiana started work on a new contract in November 2018. This was offset by the West Eclipse and Sevan Brasil completing contracts in June 2018 and July 2018.

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The average number of jack-ups on contract was the same for the three months ended March 31, 2019 and the three months ended March 31, 2018. The West Telesto and West Tucana started new contracts in April 2018 and October 2018. This was offset by the West Ariel and West Castor completing contracts in March 2018 and May 2018, respectively.

ii. Average contractual dayrates

We calculate the average contractual dayrate by dividing the aggregate contractual dayrates during a reporting period by the aggregate number of 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 $73k per day between the three months ended March 31, 2019 and March 31, 2018 due to the West Carina and West Eclipse completing legacy contracts for Petronas and ExxonMobil in July 2018. The West Carina secured a new contract with Petronas in December 2018 at a lower dayrate.

The average contractual dayrate for jack-ups decreased by $28k per day between the three months ended March 31, 2019 and March 31, 2018 due to the West Linus moving to a lower dayrate as part of securing a long-term contract with ConocoPhillips, the West Ariel and West Castor completing legacy contracts and the West Callisto moving to a lower dayrate.

iii. Economic utilization for rigs on contract

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

As set out in the below table, economic utilization has remained in the range of 90% to 97% for each of the periods presented.

The economic utilization for floaters for the three months ended March 31, 2019 was 91%. This was primarily due to operational downtime on the Sevan Louisiana related to a malfunction of its subsea equipment .

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.

Reimbursable revenues for the three months ended March 31, 2019 included revenue of $17 million for a contract to perform the first mobilization of the West Mira for Northern Drilling.

c) Other revenues

Other revenues include the following:

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i. Related party revenues

Related party revenues represent income from management and technical support services provided to Seadrill Partners, SeaMex and Northern Drilling.

ii. Amortization of unfavorable contracts

We recognize an intangible asset or liability if we acquire a drilling contract in a business combination and the contract had a dayrate that was above or below market rates at the time of the business combination. For the periods before emergence from Chapter 11 we classified the amortization of these intangible assets or liabilities within other revenues. Post-emergence and after the application of fresh start accounting, we have applied a new accounting policy which classifies amortization of these intangible assets and liabilities within operating expenses.

iii. Other

Other revenues for the three months ended March 31, 2018 included early termination fee revenue for the West Pegasus .

2) Operating expenses

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

i. Vessel and rig operating expenses

Vessel and rig operating expenses represent the costs we incur to operate a drilling unit that is either in operation or stacked. This includes the remuneration of offshore crews, rig supplies, expenses for repair and maintenance and onshore support costs.

For periods prior to emergence from Chapter 11 we classified certain operational support and information technology related costs incurred by our support functions within general and administrative expenses. As part of fresh start accounting and for periods after emergence we classified these costs within vessel and rig operating expenses. Vessel and rig operating expenses for the 2018 Predecessor and 2019 Successor periods are therefore not comparable.

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

Vessel and rig operating expenses allocated to the “Other” segment represent rig related onshore costs incurred in connection with our contracts to provide technical support services to Seadrill Partners, Seamex and Northern Drilling.

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

The number of cold stacked floaters decreased by one and the warm stacked floaters increased by one between the three months ended March 31, 2019 and March 31, 2018. The decrease in cold stacked floaters was due to the West Hercules and Sevan Louisiana which were reactivated in April 2018 and November 2018 respectively. This was offset by the Sevan Brasil which was cold stacked in January 2019.

The number of cold stacked jack-ups increased by one and the warm stacked jack-ups decreased by one between the three months ended March 31, 2019 and March 31, 2018. We cold stacked the West Freedom and West Ariel in July 2018 and re-activated the West Tucana for a new contract in October 2018.

ii. 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. We reduced the carrying value of drilling unit and equipment balances to their fair values when we applied fresh start accounting on emergence from Chapter 11. The depreciation expense for the three months ended March 31, 2019 is therefore based on lower carrying values of drilling units and equipment and is not comparable to the level of depreciation expense for the three months ended March 31, 2018.

iii. Amortization of intangibles

For periods before emergence from Chapter 11 we recognized intangible assets or liabilities only where we acquired a drilling contract in a business combination. The accounting policy we applied in the Predecessor was to classify amortization for such contracts within other revenues. 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.

iv. General and administrative expenses

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. Legal and professional fees incurred for our Chapter 11 reorganization post-petition were classified under reorganization items. As discussed above, we changed the classification of certain support function costs for periods after emergence. General and administrative expenses are therefore not comparable to between the Successor and Predecessor periods.

General and administrative expenses for the three months ended March 31, 2019 and March 31, 2018 were $31 million and $51 million, respectively. For the three months ended March 31, 2019 this includes $8 million (2018: $13 million) related to rigs we manage for our partners, which is charged out on a cost plus basis.

3) Other operating items

Other operating items 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.

Other operating items for the three months ended March 31, 2018 represents amounts recognized for contingent consideration from the sales of the West Vela and West Polaris to Seadrill Partners in 2014 and 2015. On emergence from Chapter 11 we recognized receivables equal to the fair value of expected future cash flows under these arrangements and have therefore not recognized further income in the Successor periods.

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4) Interest expense

We have analyzed interest expense into the following components:

i. Cash and payment-in-kind interest on debt facilities

We incur cash and payment-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. This margin increased by one percentage point when we emerged from Chapter 11. There has also been an increase in LIBOR rates. Both factors increased the effective interest rate on our senior credit facilities.

During Chapter 11, we recorded contractual interest payments against debt held as subject to compromise (“adequate protection payments”) as a reduction to debt in the Consolidated Balance Sheet and not as an expense to the Consolidated Statement of Operations. We then expensed the adequate protection payments on emergence from Chapter 11 on July 2, 2018.

During the three months ended March 31, 2019, we had $769 million of principal outstanding of the New Secured Notes that we issued on emergence from Chapter 11. We incur 4% cash interest and 8% payment-in-kind interest on these notes.

Our Consolidated Balance Sheet includes approximately $1 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.

ii. 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. Loan fee amortization

We amortize loan issuance costs over the expected term of the associated debt facility.

5) Reorganization items

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For the three months ended March 31, 2018, reorganization items included professional and advisory fees for post-petition Chapter 11 expenses and interest income generated from cash held by filed entities.

6) Other income and expense

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

i. Interest Income

Interest income relates to interest earned on cash deposits and other financial assets. During the period we were in Chapter 11 (September 12, 2017 to July 1, 2018), we classified interest income on cash held by filed entities within reorganization items. This totaled $1 million for the three months ended March 31, 2018.

ii. Share in results from associated companies

Share in results from 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 differences between (i) the book value of rig and contract asset balances recorded in the balance sheets of our equity method investees and (ii) the implied value of these assets in our consolidated balance sheet. We refer to these differences as “basis differences”. We amortize basis differences over the expected lives of the associated assets or liabilities. We classify this amortization within when the “share in results of associated companies” line item in our statement of operations. Therefore, the share in results from associated companies for the three months ended March 31, 2019 is not comparable to the share in results from associated companies for the three months ended March 31, 2018.

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

The share in after tax loss of associated companies for the three months ended March 31, 2019 reflected our share of the after-tax losses of our investments in Seadrill Partners and Seamex offset by our share of profits in the Seabras Sapura joint venture. This included a net expense for the amortization of basis differences of $28 million.

The share in after-tax profit for the three months ended March 31, 2018 reflected our share of the after-tax profit of our investments in Seamex and Seabras Sapura Joint venture offset by a share of losses in our investment in Seadrill Partners.

iii. 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%. We currently have exposure to LIBOR from our floating rate debt.

The loss on derivatives for the three months ended March 31, 2019 of $27 million comprised a fair value loss on our interest rate cap. The fair value loss on the interest rate cap was caused by a decrease in forward interest rates. There was an immaterial movement in the Archer share price which resulted in the value of the conversion option on the Archer convertible bond remaining stable.

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The loss on derivatives for the three months ended March 31, 2018 of $3 million comprised a fair value loss on the conversation option on the Archer convertible bond.

iv. Foreign exchange (loss)/gain

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.

v. Loss on marketable securities

The loss on marketable securities for the three months ended March 31, 2019 and March 31, 2018 reflect the changes in mark to market movements in our investments in Seadrill Partners common units and our Archer shares.

vi. Other financial items

Other financial items for the three months ended March 31, 2019 primarily comprised an indenture fee incurred for a tender offer of our New Secured Notes. We did not incur significant other financial items for the three months ended March 31, 2018.

7) 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, the latter generally being a function of gross revenue.

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 $7.1 billion as of March 31, 2019.

Our liquidity requirements relate to servicing 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 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.

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 materially 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, 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, 2019 (Successor) were primarily generated by contingent consideration payments from Seadrill Partners from the sale of the drillship West Vela in 2015. These cash inflows were offset by capital expenditures.

Net cash flows from investing activities for the three months ended March 31, 2018 (Predecessor) were driven by contingent consideration payments from Seadrill Partners from the sale of the drillship West Vela in 2015, and related party loan repayments from Seadrill Partners. These cash inflows were partly offset by capital expenditures.

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c) Cash flows from financing activities

Net cash flows from financing activities for the three months ended March 31, 2019 (Successor) and March 31, 2018 (Predecessor) were related to repayments of debt contained within three consolidated variable interest entities managed and financed by Ship Finance International Limited from whom we lease rigs under sale and leaseback arrangements.

In addition to the above, we have recognized liabilities for uncertain tax positions of $122 million including interest and penalties as at March 31, 2019.

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 from non-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, reduced by the effects of master netting agreements, adjusted for counterparty non-performance credit risk assumptions. It is our policy to enter into master netting agreements with the counterparties to derivative financial instrument contracts, which give us the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes to us.

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 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 contract 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.

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Our foreign exchange exposure primarily relates to foreign denominated cash and working capital balances. We do not expect these exposures to cause a significant amount of fluctuation in net income and therefore do not currently hedge them. Further, the effect of fluctuations in currency exchange rates caused by our international operations generally has not had a material impact on our overall operating results.

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. We have set out our exposure to interest rate risk on our net debt obligations at March 31, 2019 in the table below:

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 the 3-month US LIBOR is 2.87% and covers the period from June 15, 2018 to June 15, 2023.

The LIBOR rate applied on our debt at March 31, 2019 was 2.60%. Therefore, the interest cap would mitigate the impact of 73% of a theoretical 1% point increase in the LIBOR rate. This is set out in the table below:

One of the Ship Finance subsidiaries that we consolidate as a VIE (refer to Note 23– Variable Interest Entities (VIEs)) previously entered into interest rate swaps to mitigate its exposure to variability in cash flows for future interest payments on the loans taken out to finance the acquisition of the West Linus . These interest rate swaps matured on December 31, 2018.

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 Form 20-F.

Critical accounting estimates that have significantly impacted the three months ended March 31, 2019 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, 2019 (Successor) and December 31, 2018 (Successor), the carrying amount of our drilling units was $7 billion, representing 62% and 61% of our total assets, respectively.

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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 and jackup 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. We re-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.

Redeemable non-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 RSA 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 of non-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 the non-controlling interest in AOD at a price subject to the floor price (“Call Option”). The Put Option generates a redemption feature for the non-controlling interest holder that is outside the control of Seadrill Limited.

To calculate the fair value of the non-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 the non-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 11.40%. We derived the fair value of the external debt facilities with a discounted cash flow using a weighted average cost of debt of 6.15%.

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 of pre-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 (such as the 2017 US tax reform), 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 6 – “Taxation” to our Consolidated Financial Statements included herein for further information.

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Seadrill Limited

INDEX TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

F-1

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

F-2

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

F-3

F-5