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 November 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 nine months ended September 30, 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 nine month period ended September 30, 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 20 rigs on behalf of Seadrill Partners, SeaMex, Sonangol and Northern Drilling.

Significant Developments for the period from January 1, 2019 through and including September 30, 2019

Receipt of overdue receivable

In January 2019, we received $26 million for an overdue receivable which was fully provided in the Predecessor company. This was 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 is also managing 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.

In October 2019, Seadrill and Sonangol contributed $50 million equity into the joint venture. On October 1, 2019, the first bareboat and management agreements for the Sonangol drilling unit, Libongos, became effective. The rig commenced its first drilling contract on October 10, 2019.

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Tender offer of Senior Secured Notes

In March 2019 we launched a consent solicitation process to amend the senior secured notes indenture which included a subsequent tender offer to purchase back $311 million of principal amount outstanding. In April 2019, we repurchased $311 million of principal senior secured notes for $342 million. The $31 million additional cash paid represents the 7% purchase premium and settlement of accrued payment-in-kind and cash interest on the notes prior to purchase.

Cancellation of 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 also 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.

Joint venture with Gulf Drilling International

We have entered into an agreement to establish a 50:50 joint venture (“Gulfdrill”) with Gulf Drilling International (“GDI”), which will provide drilling services in Qatar. GDI has been awarded five long-term drilling contracts in Qatar which it will novate to Gulfdrill. We will lease two of our benign environment jack-up rigs, West Castor and West Telesto, to GulfDrill for use under these contracts and have secured bareboat charters for a further three rigs from a third-party shipyard. GDI will manage and operate all rigs on behalf of the joint venture.

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 September 30, 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 nine months ended September 30, 2019 and for each year ended December 31 over the period 2015 to 2018.

We have seen a stabilization in the oil and gas market in 2019 with the Brent oil price consistent at $60 per barrel for most of the period. Combined with efficiency improvements across the industry, this stabilization 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 this trend to continue if the price of oil remains stable and our customers continue to invest in projects.

The below table shows the global number of rigs on contract and marketed utilization at September 30, 2019 and for each of the four preceding years ending December 31.

Floater

During 2019 we have seen an increase in the number of opportunities for floaters and net floater supply has continued to decline which has improved utilization. Marketed utilization continues to improve, particularly in the harsh environment where there is high demand for high specification units relative to their supply. There is still an excess supply of benign environment units which has slowed the recovery in this market. However, we see pockets of strength for high-end ultra deepwater drillships with marketed utilization trending ahead.

While we see improving trends in the forward market we expect economics will not justify reactivations or newbuild rigs entering the market in 2020. There are a number of older units with no follow-on work identified which we expect will be prime scrapping candidates, as classing expenditures can be costly and will only be completed if the economic future profile satisfies this cost.

Jack-up

We continue to see positive trends in the jack-up market with utilization and dayrates improving. The market preference for premium units continues, resulting in a bifurcation in rates and utilization for these assets. The demand and rates for premium assets has seen newbuild units 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.

Results of Operations

The tables included below set out financial information for the three and nine months ended September 30, 2019 and the period from July 2, 2018 through September 30, 2018 (Successor) (“September 2018 successor period”) and the period from January 1, 2018 through July 1, 2018 (Predecessor) (“2018 predecessor period”). The September 2018 successor period and the 2018 predecessor period 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.

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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 for the three month period ended September 30, 2019 was the same as for the period from July 2, 2018 through September 30, 2018 (Successor) (“September 2018 successor period”) as the impact of the Sevan Louisiana returning to operations in August 2019 was offset by the West Gemini completing its contract with ENI during the same month. The average number of jack-ups on contract for the three months ended September 30, 2019 increased by one compared to the September 2018 successor period. This was primarily due to the West Castor returning to operations in March 2019 after being warm stacked since July 2018.

The average number of floaters on contract for the nine month period ended September 30, 2019 was the same as for the September 2018 successor period. The average number of jack-ups on contract for the nine months ended September 30, 2019 was the same as for the September 2018 successor period due to the West Castor returning to operations in March 2019, offset by idle time on the West Cressida during the first half of 2019.

The average number of floaters on contract decreased by three between the period from January 1, 2018 through July 1, 2018 (Predecessor) (“2018 predecessor period”) and the September 2018 successor period. This was primarily due to the West Carina and Sevan Brasil completing contracts with Petrobras in Brazil and the West Eclipse completing its contract with ExxonMobil in Angola. The average number of jack-ups on contract increased by one between the 2018 predecessor period and September 2018 successor period as the West Cressida and West Telesto started work on new contracts in May 2018 and June 2018, offset by the West Castor completing a contract in June 2018.

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 increased by $23k between the three months ended September 30, 2019 and the September 2018 successor period. The West Gemini, West Hercules and West Phoenix were all on higher dayrates for the three months ended September 30, 2019 compared to the previous year. The average contractual dayrate for jack-ups increased by $4k between the three months ended September 30, 2019 and the September 2018 successor period. This was primarily due to the West Elara moving to a higher dayrate on its contract with ConocoPhillips from October 2018, offset by a lower dayrate for the AOD I after its contract with Saudi Aramco was extended in July 2019.

The average contractual dayrate for floaters for the nine month period ended September 30, 2019 was $4k higher than the September 2018 successor period. The average contractual dayrate for jack-ups for the nine month period ended September 30, 2019 was $9k higher than the September 2018 successor period. This was primarily due to the West Elara moving to a higher dayrate on its contract with ConocoPhillips from October 2018.

The average contractual dayrate for floaters decreased by $38k between the 2018 predecessor period and September 2018 successor period due to the West Carina and West Eclipse completing legacy contracts for Petrobras and ExxonMobil, respectively in July 2018. The average contractual dayrate for jack-ups decreased by $32k between the 2018 predecessor period and September 2018 successor period due to the West Elara and West Linus moving to lower dayrates as part of securing long-term contracts with ConocoPhillips and the West Castor completing a legacy contract.

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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 93% to 98% for each of the periods presented.

The economic utilization for floaters has decreased for the three and nine months ended September 30, 2019 to 93%. This was primarily due to operational downtime on the Sevan Louisiana in early 2019 and downtime on West Saturn and West Phoenix in the three months ended September 30, 2019.

The economic utilization for jack-ups has decreased for the three and nine months ended September 30, 2019 to 93% and 96%, respectively. This was primarily due to the West Linus completing its 5-year class survey during the three months ended September 30, 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.

Reimbursable revenues for the three months ended September 30, 2019 included revenue of $41 million (nine months ended September 30, 2019: $79 million) for a contract to perform the first mobilization of the West Mira and the West Bollsta for Northern Drilling and $22 million (nine months ended September 30, 2019: $34 million) for a contract to perform the first mobilization of the Libongos and Quenguela for Sonangol.

c) Other revenues

Other revenues include the following:

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 and nine months ended September 30, 2019 consisted of management fees for the contract to perform the first mobilization of the Sonangol rigs Libongos and Quenguela.

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Other revenues for the 2018 predecessor period included early termination fee revenue for the West Pegasus offset by the reversal of third party management fee revenue referred above.

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 selling, 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 selling, 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 September 2018 successor period, 2018 predecessor period 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 expenses for the for jack-ups for the 2018 predecessor period included a bad debt expense of $48 million relating to an overdue receivable, subsequently received after emergence within “Other operating income.”

Excluding the effect of this one-time item, 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, Sonangol 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:

For the three and nine months ended September 30, 2019 and the September 2018 successor period the number of cold stacked floaters increased by one and warm stacked floaters decreased by one. Between these dates the Sevan Brasil and West Eclipse were cold stacked having been warm stacked in 2018. This is offset by the Sevan Louisiana which was reactivated from cold stack and the West Gemini went from operating to warm stack in 2019.

For the September 2018 successor period and the 2018 predecessor period the number of cold stacked floaters was the same and the number of warm stacked rigs increased by two. Between these dates the West Eclipse and West Carina came off contract and were warm stacked.

For the three months ended September 30, 2019 and the September 2018 successor period the number of cold stacked jack-ups was the same and the number of warm stacked floaters decreased by one. Between these dates the West Castor started a new contract with Staatsolie having been warm stacked in the September 2018 successor period.

For the nine months ended September 30, 2019 and the September 2018 successor period the number of cold stacked jack-ups was the same and the number of warm stacked floaters was the same. Between these dates the West Castor started a new contract with Staatsolie having been warm stacked in the September 2018 successor period offset by the West Cressida being warm stacked for seven months of the nine months ended September 30, 2019 whilst it was on contract in the September 2018 successor period.

For the September 2018 successor period and the 2018 predecessor period the number of cold stacked jack-ups increased by one and the number of warm stacked rigs decreased by two. Between these dates the West Ariel went from warm stacked to cold stacked and the West Cressida started a new contract with Ophir having been warm stacked.

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 and nine months ended September 30, 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 September 2018 successor period and the 2018 predecessor period.

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 period 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.

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iv. Selling, general and administrative expenses

Selling, general and administrative expenses include the cost of our corporate and regional offices, certain legal and professional fees as well as the remuneration and other compensation of our officers, directors and employees engaged in central management and administration activities. 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 from selling, general and administrative expenses to vessel and rig operating expenses. Selling, general and administrative expenses are therefore not comparable to between the Successor and Predecessor periods.

Selling, general and administrative expenses for the three months ended September 30, 2019, the September 2018 successor period and the 2018 predecessor period were $33 million, $31 million and $100 million, respectively. For the three months ended September 30, 2019 this includes $12 million (September 2018 successor period: $14 million) related to rigs we manage for our partners, which is charged out on a cost plus basis.

Selling, general and administrative expenses for the nine months ended September 30, 2019 were $94 million. For the nine months ended September 30, 2019 this includes $28 million (2018 predecessor period: $27 million and September 2018 successor period: $14 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 September 30, 2019 represents the settlement of an insurance claim in relation to the subsea equipment incident on the Sevan Louisiana. The nine months ended September 30, 2019 further includes cash received for the recovery of a receivable balance previously written down to nil on fresh start and the settlement with Jurong Shipyard regarding a long outstanding builders credit issue.

Other operating items for the September 2018 successor period and the 2018 predecessor period represents an impairment charge of $414 million against the West Alpha, West Navigator and West Epsilon, following an assessment of recoverability, as we determined that the continuing downturn in the offshore drilling market was an indicator of impairment on certain assets. This was slightly offset by amounts recognized for contingent consideration from the sales of the West Vela to Seadrill Partners in 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.

4) 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 $6 million in the 2018 Predecessor period.

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ii. Interest expense

We have analyzed interest expense into the following components:

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 the period we were in 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.

On July 15, 2019, $18 million of accrued payment-in-kind interest on our senior secured notes were compounded and additional notes were issued. At September 30, 2019, we had $476 million of principal outstanding of the $880 million senior secured notes that we issued on emergence from Chapter 11. We incurred 4% cash interest and 8% payment-in-kind interest on these notes.

Our Consolidated Balance Sheet includes $633 million 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.

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.

Loan fee amortization

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

iii. Impairment of Seadrill’s investments in Seadrill Partners

On September 6, 2019, Seadrill Partners announced its suspension from trading on the NYSE. This was considered an other than temporary impairment indicator which led to an impairment review being performed in respect of the Seadrill investment in Seadrill Partners. The result of this exercise was a total impairment charge of $302 million across the investments we hold in Seadrill Partners.

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iv. 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 the “share in results of associated companies” line item in our Consolidated Statement of Operations. Therefore, the share in results from associated companies for the three and nine months ended September 30, 2019 is not comparable to the share in results from associated companies for the September 2018 successor period and the 2018 predecessor period.

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 and nine months ended September 30, 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 for the three months ended September 30, 2019 of $13 million (nine months ended September 30, 2019: $63 million).

The share in after-tax profit for the September 2018 successor period and the 2018 predecessor period reflected our share of the after-tax loss of our investments in Seadrill Partners, Seamex and Seabras Sapura Joint venture.

v. (Loss)/gain 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 and nine months ended September 30, 2019 of $4 million and $37 million respectively is due to a fair value loss on our interest rate cap following a decrease in forward interest rates. The Archer conversion option remains immaterial as the current Archer stock price is below our conversion option price.

The gain on derivatives in the September 2018 successor period of $3 million respectively comprised a $11 million fair value gain on our interest rate cap caused by an increase in forward interest rates offset by a $8 million fair value loss on the Archer conversion option caused by a decrease in the Archer share price.

The loss on derivatives in the 2018 predecessor period of $4 million comprised a $6 million fair value loss on our interest rate cap driven by a decrease in forward interest rates offset by a $2 million fair value gain on the conversion option of the Archer convertible bond caused by an increase in the Archer share price.

vi. Net loss on debt extinguishment

On April 10, 2019, we purchased back $311 million of the senior secured notes issued on emergence at a 7% premium. The premium paid was recognized as a loss on debt extinguishment.

vii. Foreign exchange loss

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

viii. Loss on marketable securities

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

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ix. Reorganization items

Prior to emergence from Chapter 11, reorganization items included professional and advisory fees for post-petition Chapter 11 expenses, adjustments to the carrying value of liabilities subject to their estimated allowed claims amount, gains on liabilities subject to compromise, fresh start adjustments and interest income generated from surplus cash invested. We have also classified professional and advisory fees that we incurred post-emergence, but relate to our Chapter 11 filing, within reorganization items.

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 $6.8 billion as of September 30, 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 from the date of this report.

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 nine months ended September 30, 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 nine months ended September 30, 2019 were primarily from capital expenditures offset by contingent consideration payments from Seadrill Partners from the sale of the drillship West Vela in 2015 and cash receipt of loans granted to Seabras Sapura.

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Net cash flows from investing activities for the period from July 2, 2018 through September 30, 2018 (Successor) and the period from January 1, 2018 through July 1, 2018 (Predecessor) were driven by our share of proceeds from the sale of the West Rigel, 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.

c) Cash flows from financing activities

Net cash flows from financing activities for the nine months ended September 30, 2019 were primarily driven by the purchase of the senior secured notes in April 2019 and repayments of debt.

Net cash flows from financing activities for the period from July 2, 2018 through September 30, 2018 (Successor) and the period from January 1, 2018 through July 1, 2018 (Predecessor) were related to proceeds from our secured note and equity issuances on emergence from Chapter 11, offset by debt repayments.

In addition to the above, we have recognized liabilities for uncertain tax positions of $97 million including interest and penalties as at September 30, 2019.

In relation to our Gulfdrill joint venture, we have entered into charter agreements to lease three jack-up rigs from a third-party shipyard. These agreements will be novated to Gulfdrill prior to the commencement of its operations. We have not recognized a lease liability for these agreements as none of the rigs had been delivered as of September 30, 2019. The maximum potential unrecognized obligation for these agreements is $15 million, which is excluded from the above table.

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, adjusted for our non-performance credit risk assumption.

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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 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.

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.

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 September 30, 2019 was 2.11%. At this date, the interest cap would mitigate 24% of the impact of a theoretical 1% point increase in LIBOR. This is set out in the below table.

We have set out our exposure to interest rate risk on our net debt obligations at September 30, 2019 in the table below:

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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 nine months ended September 30, 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 September 30, 2019 (Successor) and December 31, 2018 (Successor), the carrying amount of our drilling units was close to $6 billion and $7 billion respectively, representing 68% and 61% of our total assets, respectively.

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 jack-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. 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.

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”). The holders of these equity instruments have varying rights to receive distributions from Seadrill Partners. The common units and subordinated units have equal rights to distributed profits, subject to the common units being entitled to a minimum quarterly distribution before the subordinated units may receive a dividend. The holders of the IDRs do not receive a share of the Seadrill Partners distributions until a target distribution level has been achieved. The IDRs receive an increasing share of the distribution once this has been met.

As set out in Note 13 to the accompanying financial statements, we have several investments in Seadrill Partners. These include (i) 100% of the subordinated units (1.6 million units); (ii) 35% of the common units (2.5 million out of 7.5 million total units) and (iii) 100% of the incentive distribution rights. In addition, 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 our investment in (i) the subordinated units and (ii) direct investments in Seadrill Partners OPCOs under the equity method. These investments were recorded at fair value when we applied fresh start accounting on July 2, 2018. Each reporting period, we (i) increase (or decrease) the value of these investments for our share of the after-tax profits (or losses) of the entities and (ii) amortize basis differences recorded against the investments on fresh start.

Seadrill Partners 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 incentive distribution rights do not meet the definition of stock. Therefore, neither category of investment is accounted for under the equity method. 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. The IDRs do not have a readily ascertainable fair value and are recorded at cost less impairment. The cost of the IDRs represented the fair value of the instruments when we applied fresh start accounting on July 2, 2018.

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In addition, as set out in Note 25 to the accompanying financial statements, we had $128 million of receivables due to us from Seadrill Partners as of September 30, 2019. These receivables primarily related to management services and deferred consideration arrangements between us and Seadrill Partners.

Impairment review

Each reporting period, we are required to consider (i) whether there have been any indicators of ’other than temporary impairment’ (“OTTI”) of our equity method investments (subordinated units and direct interests) and (ii) whether there has been an impairment of the IDRs. 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.

Seadrill Partners primary debt finance comes from a $2.6 billion Term Loan B (“TLB”) which comes due for repayment in February 2021 and will need to be refinanced. There has been a decrease in the share price of Seadrill Partners common units since November 2018 which culminated in the common units being suspended from trading on NYSE in August 2019 as the market capitalization decreased below $15 million for a period of 30 consecutive days. We have interpreted this decrease in share price as both (i) an indicator of OTTI for the subordinated units and direct interests and (ii) an impairment indicator for the IDRs. The evaluation of whether a decline in fair value is “other than temporary” requires a high degree of judgment and the use of different assumptions that could materially affect our earnings.

Impairment

Having identified an indicator of OTTI, we were required to value our investments in Seadrill Partners to calculate the impairment at September 30, 2019. We calculated the fair value of our investments in Seadrill Partners direct interests and IDRs to be $134 million and nil, compared to pre-impairment book values of $382 million and $54 million respectively. As a result, we recorded an impairment charge of $302 million. We have recognized the impairment of these investments within “Loss on impairment of investments” in our Consolidated Statement of Operations for the three and nine months ended September 30, 2019.

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