Report of Foreign Issuer (6-k)

Date : 08/19/2019 @ 9:29PM
Source : Edgar (US Regulatory)
Stock : Seadrill Ltd (SDRL)
Quote : 1.3234  -0.0266 (-1.97%) @ 2:29PM

Report of Foreign Issuer (6-k)




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 August 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 [X]       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 [X]


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 [X]



1









2







Seadrill Limited

Report on Form 6-K for the six months ended June 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 six month period ended June 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).


INDEX

Interim Financial Statements (unaudited)
 


3







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:

our ability to maintain relationships with suppliers, customers, employees and other third parties following our emergence from Chapter 11 proceedings;
our ability to maintain and obtain adequate financing to support our business plans following our emergence from Chapter 11;
factors related to the offshore drilling market, including changes in oil and gas prices and the state of the global economy on market outlook for our various geographical operating sectors and classes of rigs;
supply and demand for drilling units and competitive pressure on utilization rates and dayrates;
customer contracts, including contract backlog, contract commencements, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations;
the repudiation, nullification, modification or renegotiation of drilling contracts;
delays in payments by, or disputes with, our customers under our drilling contracts;
fluctuations in the market value of our drilling units and the amount of debt we can incur under certain covenants in our debt financing agreements;
the liquidity and adequacy of cash flow for our obligations;
our ability to successfully employ our drilling units;
our ability to procure or have access to financing;
our expected debt levels;
our ability to satisfy our obligations, including certain covenants, under our debt financing agreements and if needed, to refinance our existing indebtedness;
credit risks of our key customers;
political and other uncertainties, including political unrest, risks of terrorist acts, war and civil disturbances, public health threats, piracy, corruption, significant governmental influence over many aspects of local economies, or the seizure, nationalization or expropriation of property or equipment;
the concentration of our revenues in certain geographical jurisdictions;
limitations on insurance coverage, such as war risk coverage, in certain regions;
any inability to repatriate income or capital;
the operation and maintenance of our drilling units, including complications associated with repairing and replacing equipment in remote locations and maintenance costs incurred while idle;
newbuildings, upgrades, shipyard and other capital projects, including the completion, delivery and commencement of operation dates;
import-export quotas;
wage and price controls and the imposition of trade barriers;
the recruitment and retention of personnel;
regulatory or financial requirements to comply with foreign bureaucratic actions, including potential limitations on drilling activity, changing taxation policies and other forms of government regulation and economic conditions that are beyond our control;
the level of expected capital expenditures, our expected financing of such capital expenditures, and the timing and cost of completion of capital projects;
fluctuations in interest rates or exchange rates and currency devaluations relating to foreign or US monetary policy;

4







tax matters, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Bermuda, Brazil, Norway, the United Kingdom and the United States;
legal and regulatory matters, including the results and effects of legal proceedings, and the outcome and effects of internal and governmental investigations;
hazards inherent in the drilling industry and marine operations causing personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and the suspension of operations;
customs and environmental matters; and
other important factors described from time to time in the reports filed or furnished by us with the SEC.

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.




5







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
Significant developments
Contract backlog
Market overview and trends
Results of operations
Liquidity and capital resources
Borrowing activities
Contractual obligations
Quantitative and qualitative disclosures about market risk
Critical accounting estimates

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

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.


6







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.

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
On August 15, 2019, we announced the award of drilling contracts by Qatar Petroleum to Gulf Drilling International ("GDI"). We have entered into a 50:50 joint venture, Gulfdrill, which will initially manage and operate five premium jack-ups in Qatar with Qatar Petroleum commencing throughout 2020. The total contract value is expected to be $656 million, including mobilization fees. Each contract has five single well options which could add up to an estimated 14 cumulative years of term and an additional contract value of $700 million.

Gulfdrill will initially bareboat charter the West Telesto and West Castor from Seadrill and has secured bareboat charters for three additional units from a third-party shipyard.

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:
(In $ millions)
 
 
 
 
Contract backlog
 
June 30, 2019

 
December 31, 2018

Floaters
 
498

 
630

Jack-ups
 
1,411

 
1,457

Total
 
1,909

 
2,087


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 June 30, 2019 contract backlog to unwind over the following periods:
(In $ millions)
 
 
 
Period ended December 31,
Contract backlog
 
Total

 
2019

 
2020

 
2021

 
2022+

Floaters
 
498

 
298

 
191

 
9

 

Jack-ups
 
1,411

 
157

 
171

 
169

 
914

Total
 
1,909

 
455

 
362

 
178

 
914


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.



7







Market Overview and Trends
 
The below table shows the average oil price for the six months ended June 30, 2019 and for each year ended December 31 over the period 2015 to 2018. The Brent oil price at July 31, 2019 was $58.
 
 
Dec-2015

 
Dec-2016

 
Dec-2017

 
Dec-2018

 
Jun-2019

 
Average Brent oil price ($/bbl)
 
54

 
45

 
55

 
71

 
60

 

We have seen a stabilization in the oil and gas market in 2019 with Brent oil prices remaining 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 June 30, 2019 and for each of the four preceding years ending December 31.
 
 
Dec-2015

 
Dec-2016

 
Dec-2017

 
Dec-2018

 
Jun-2019

 
Contracted rigs
 
 
 
 
 
 
 
 
 
 
 
Harsh environment floater
 
45

 
35

 
30

 
31

 
35

 
Benign environment floater
 
196

 
139

 
120

 
116

 
118

 
Jack-up (1)
 
180

 
152

 
154

 
168

 
194

 
Marketed utilization
 
 
 
 
 
 
 
 
 
 
 
Harsh environment floater
 
93
%
 
81
%
 
83
%
 
85
%
 
87
%
 
Benign environment floater
 
83
%
 
71
%
 
71
%
 
73
%
 
76
%
 
Jack-up (1)
 
83
%
 
70
%
 
70
%
 
74
%
 
82
%
 
(1) Jack-up rigs capable of operating in water depth greater than 350 feet.

Floater
During 2019 we have seen an increase in the number of opportunities for floaters. This activity, supported by the continued decline in the net floater supply in 2019, has improved utilization levels. 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 future demand for high specification units which will support continued improvement in utilization.

While 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 economic future profile satisfies this cost. There are also a significant number of cold stacked units with significant reactivation costs that will generally require a sufficient improvement in dayrates to overcome these costs before they are reintroduced into the market, if they are reintroduced at all. This could see total and marketed supply begin to align.

Jack-up
We continue to see an improvement in shallow water market customer demand which has led to an increase in marketed utilization. The increased demand and improved 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 recovery.

Results of Operations

The tables included below set out financial information for the three and six months ended June 30, 2019 (Successor) and June 30, 2018 (Predecessor). The three and six months ended June 30, 2019 and June 30, 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.

8







 
Successor
 
 
Predecessor
 
Successor


Predecessor
(In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Operating revenues
321

 
 
348

 
623

 
 
712

Operating expenses
(397
)
 
 
(476
)
 
(796
)
 
 
(918
)
Other operating items
3

 
 
(411
)
 
29

 
 
(407
)
Operating loss
(73
)
 
 
(539
)
 
(144
)
 
 
(613
)
Interest expense
(122
)
 
 
(19
)
 
(254
)
 
 
(38
)
Reorganization items

 
 
(35
)
 

 
 
(109
)
Other income and expense
(41
)
 
 
165

 
(116
)
 
 
161

Loss before income taxes
(236
)
 
 
(428
)
 
(514
)
 
 
(599
)
Income tax benefit/(expense)
30

 
 
(4
)
 
12

 
 
(36
)
Net loss
(206
)
 
 
(432
)
 
(502
)
 
 
(635
)

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:
 
Successor
 
 
Predecessor
 
Successor


Predecessor
(In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Contract revenues
253

 
 
311

 
508

 
 
619

Reimbursable revenues
44

 
 
9

 
70

 
 
21

Other revenues
24

 
 
28

 
45

 
 
72

Total operating revenues
321

 
 
348

 
623

 
 
712


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.
 
Successor
 
 
Predecessor
 
Successor


Predecessor
(In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Floaters
164

 
 
226

 
338

 
 
436

Jack-ups
89

 
 
85

 
170

 
 
183

Contract revenues
253

 
 
311

 
508

 
 
619


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:

 
Successor
 
 
Predecessor
 
Successor


Predecessor
(Number)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Floaters
7

 
 
9

 
8

 
 
9

Jack-ups
8

 
 
8

 
8

 
 
8

Average number of rigs on contract
15

 
 
17

 
16

 
 
17




9







The average number of floaters on contract decreased by two between the three months ended June 30, 2019 and the three months ended June 30, 2018 primarily due to the West Eclipse and Sevan Brasil completing contracts in June 2018 and July 2018, respectively.

The average number of jack-ups on contract was the same for the three months ended June 30, 2019 and the three months ended June 30, 2018 . The West Tucana started a new contract in October 2018, this was offset by idle time on the West Telesto during April and May 2019.

The average number of floaters on contract decreased by one between the six months ended June 30, 2019 and the six months ended June 30, 2018 primarily due to the West Eclipse and Sevan Brasil completing contracts in June 2018 and July 2018. This was partly offset by idle time on the West Hercules from January to April 2018.

The average number of jack-ups on contract was the same for the six months ended June 30, 2019 and the six months ended June 30, 2018 . The West Tucana started a new contract in October 2018. This was offset by the West Ariel operating from January to March 2018 and by idle time on the West Telesto in April and May 2019.

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:
 
Successor
 
 
Predecessor
 
Successor


Predecessor
(In $ thousands)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Floaters
253

 
 
274

 
237

 
 
285

Jack-ups
113

 
 
113

 
110

 
 
124


The average contractual dayrate for floaters decreased by $21k and $48k per day between the three and six months ended June 30, 2019 and June 30, 2018 due to the West Carina , Sevan Brasil and West Eclipse completing legacy contracts for Petrobras and ExxonMobil in July 2018, respectively. The West Carina secured a new contract with Petronas in December 2018 at a lower dayrate.

The average contractual dayrate for jack-ups was the same between the three months ended June 30, 2019 and June 30, 2018 . The West Elara moved to a higher dayrate on its contract with ConocoPhillips in December 2018 and the West Telesto started a new contract with GDI at a higher dayrate that it previously earned for its work in India. This was offset by the West Callisto moving to a lower dayrate in January 2019.

The average contractual dayrate for jack-ups decreased by $14k per day between the six months ended June 30, 2019 and June 30, 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. This was partly offset by the West Elara and West Telesto moving to higher dayrates.

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 98% for each of the periods presented.
 
Successor
 
 
Predecessor
 
Successor


Predecessor
(Percentage)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Floaters
95
%
 
 
90
%
 
93
%
 
 
90
%
Jack-ups
98
%
 
 
90
%
 
98
%
 
 
94
%

The economic utilization for floaters has increased for the three and six months ended June 30, 2019 to 95% and 93% , respectively. This was primarily due to operational downtime on the West Carina and West Tellus during the three months ended June 30, 2018 .

The economic utilization for jack-ups has increased for the three and six months ended June 30, 2019 to 98% . This was primarily due to operational downtime on the West Linus during the three months ended June 30, 2018 .


10







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 June 30, 2019 included revenue of $21 million (six months ended June 30, 2019 : $38 million) for a contract to perform the first mobilization of the West Mira for Northern Drilling and $12 million (six months ended June 30, 2019 : $12 million) for a contract to perform the first mobilization of the Libongos and Quenguela for Sonangol.

c) Other revenues
Other revenues include the following:
 
Successor
 
 
Predecessor
 
Successor


Predecessor
(In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Related party revenues (i)
22

 
 
21

 
43

 
 
43

Amortization of unfavorable contracts (ii)

 
 
9

 

 
 
21

Other (iii)
2

 
 
(2
)
 
2

 
 
8

Total other revenues
24

 
 
28

 
45

 
 
72


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

Other revenues for the three months ended June 30, 2018 included the reversal of third party management fee revenue that was deemed no longer recoverable. Other revenues for the six months ended June 30, 2018 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 general and administrative expenses. We have analyzed operating expenses between these categories in the table below:
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
  (In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019

 
 
Six months ended June 30, 2018

Vessel and rig operating expenses
(182
)
 
 
(224
)
 
(381
)
 
 
(407
)
Reimbursable expense
(43
)
 
 
(8
)
 
(69
)
 
 
(20
)
Depreciation
(104
)
 
 
(195
)
 
(212
)
 
 
(391
)
Amortization of intangibles
(38
)
 
 

 
(73
)
 
 

General and administrative expenses
(30
)
 
 
(49
)
 
(61
)
 
 
(100
)
Total operating expenses
(397
)
 
 
(476
)
 
(796
)
 
 
(918
)

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.


11







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.
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
(In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019

 
 
Six months ended June 30, 2018

Floaters
(118
)
 
 
(115
)
 
(250
)
 
 
(239
)
Jack-ups
(50
)
 
 
(105
)
 
(106
)
 
 
(158
)
Other
(14
)
 
 
(4
)
 
(25
)
 
 
(10
)
Vessel and rig operating expenses
(182
)
 
 
(224
)
 
(381
)
 
 
(407
)

Vessel and rig expenses for the for jack-ups for the three and six months ended June 30, 2018 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.

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


Predecessor
(Number of rigs)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Floaters
 
 
 
 
 
 
 
 
 
Operating
7

 
 
9

 
8

 
 
9

Warm stacked
3

 
 
1

 
2

 
 
1

Cold stacked
9

 
 
9

 
9

 
 
9

Average number of Floaters
19

 
 
19

 
19

 
 
19

 
 
 
 
 
 
 
 
 
 
Jack-ups
 
 
 
 
 
 
 
 
 
Operating
8

 
 
8

 
8

 
 
8

Warm stacked
2

 
 
3

 
2

 
 
3

Cold stacked
6

 
 
5

 
6

 
 
5

Average number of Jack-ups
16

 
 
16

 
16

 
 
16


For the three and six months ended June 30, 2019 and June 30, 2018 , the number of cold stacked floaters was the same and the number of warm stacked floaters increased by two and one respectively. Between these dates the Sevan Louisiana was reactivated from cold stack but was subsequently warm stacked in March 2019 for BOP repairs, the West Eclipse was warm stacked and the Sevan Brasil was cold stacked.

For the three and six months ended June 30, 2019 and June 30, 2018 , the number of cold stacked jack-ups increased by one and the warm stacked jack-ups decreased by one. Between these dates the West Freedom and West Ariel were taken from warm stacked to cold stacked offset by the West Castor which was warm stacked and the West Tucana which was reactivated from cold stack for a new contract.

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 six months ended June 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 three and six months ended June 30, 2018 .


12







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 from general and administrative expenses to vessel and rig operating expenses. General and administrative expenses are therefore not comparable to between the Successor and Predecessor periods.

General and administrative expenses for the three months ended June 30, 2019 and June 30, 2018 were $30 million and $49 million , respectively. For the three months ended June 30, 2019 this includes $8 million (June 30, 2018: $14 million) related to rigs we manage for our partners, which is charged out on a cost plus basis.

General and administrative expenses for the six months ended June 30, 2019 and June 30, 2018 were $61 million and $100 million , respectively. For the six months ended June 30, 2019 this includes $16 million (June 30, 2018: $27 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 and months ended June 30, 2019 represents the settlement with Jurong Shipyard regarding a long outstanding builders credit issue. The six months ended June 30, 2019 further includes cash received for the recovery of a receivable balance previously written down to nil on fresh start.

Other operating items for the three and six months ended June 30, 2018 represents an impairment charge of $414 million against the W est 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 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.

4) Interest expense
We have analyzed interest expense into the following components:

Successor
 
 
Predecessor
 
Successor


Predecessor
  (In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Cash and payment-in-kind interest on debt facilities
(110
)
 
 
(18
)
 
(230
)


(36
)
Unwind of discount on debt
(12
)
 
 

 
(24
)
 
 

Loan fee amortization

 
 
(1
)
 

 
 
(2
)
Interest expense
(122
)
 
 
(19
)
 
(254
)
 
 
(38
)

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.
 
Successor
 
 
Predecessor
 
Successor


Predecessor
  (In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Senior credit facilities
(82
)
 
 
(63
)
 
(167
)
 
 
(118
)
Less: adequate protection payments

 
 
57

 

 
 
106

Senior secured notes
(16
)
 
 

 
(39
)
 
 

Debt of consolidated variable interest entities
(12
)
 
 
(12
)
 
(24
)
 
 
(24
)
Cash and payment-in-kind interest
(110
)
 
 
(18
)
 
(230
)


(36
)


13







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.

At June 30, 2019 , we had $458 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 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
 
Successor
 
 
Predecessor
 
Successor


Predecessor
  (In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Advisory and professional fees

 
 
(40
)
 

 
 
(115
)
Interest income on surplus cash invested

 
 
5

 

 
 
6

Total reorganization items

 
 
(35
)
 

 
 
(109
)

For the three months ended June 30, 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:
 
Successor
 
 
Predecessor
 
Successor


Predecessor
  (In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Interest income
19

 
 
9

 
39

 
 
19

Share in results from associated companies
(23
)
 
 
141

 
(65
)
 
 
149

Loss on derivative financial instruments
(6
)
 
 
(1
)
 
(33
)
 
 
(4
)
Foreign exchange (loss)/gain
4

 
 
(8
)
 
2

 
 

(Loss)/gain on marketable securities
(14
)
 
 
25

 
(35
)
 
 
(3
)
Other financial items
1

 
 
(1
)
 
(2
)
 
 

Net loss on debt extinguishment
(22
)
 
 

 
(22
)
 
 

Other income and expense
(41
)
 
 
165

 
(116
)
 
 
161


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 $5 million and $6 million for the three and six months ended June 30, 2018 , respectively.


14







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 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 and months ended June 30, 2019 is not comparable to the share in results from associated companies for the three and six months ended June 30, 2018 .

iii. 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.

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


Predecessor
  (In $ millions)
Three Months Ended June 30, 2019

 
 
Three Months Ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Seadrill Partners
(36
)
 
 
114

 
(78
)
 
 
99

Seamex
(5
)
 
 
1

 
(13
)
 
 
4

Seabras Sapura
18

 
 
26

 
26

 
 
46

Share of results from associated companies
(23
)
 
 
141

 
(65
)
 
 
149


The share in after tax loss of associated companies for the three and six months ended June 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 June 30, 2019 of $21 million (six months ended June 30, 2019 : $49 million).
 
The share in after-tax profit for the three and six months ended June 30, 2018 reflected our share of the after-tax profit of our investments in Seadrill Partners, Seamex and Seabras Sapura Joint venture.

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. We also have a conversion option on a bond issued to us by Archer Ltd. We record both of these assets at fair value.

The loss on derivatives for the three and six months ended June 30, 2019 of $ 6 million and $33 million respectively 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.

The loss on derivatives for the three months ended June 30, 2018 of $ 1 million comprised of a fair value gain on the conversation option on the Archer convertible bond offset by a fair value loss on our interest rate cap. The loss on derivatives for the six months ended June 30, 2018 of $4 million comprised of a fair value loss on our interest rate cap. There was an immaterial movement in the Archer share price.

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)/gain on marketable securities
The (loss)/gain on marketable securities for the three and six months ended June 30, 2019 and June 30, 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 six months ended June 30, 2019 primarily comprised an indenture fee incurred for a tender offer of our senior secured notes. We did not incur significant other financial items for the three and six months ended June 30, 2018 .


15







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 June 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.

 
 
Successor
 
 
Successor
(In $ millions)
 
As at June 30, 2019

 
 
As at December 31, 2018

Cash and cash equivalents
 
1,251

 
 
1,542

Restricted cash
 
218

 
 
461

Cash and cash equivalents, including restricted cash
 
1,469

 
 
2,003


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

 
 
Successor
 
 
Predecessor
(In $ millions)
 
Six months ended June 30, 2019

 
 
Six months ended June 30, 2018

Cash flows from operating activities
 
(184
)
 
 
(132
)
Cash flows from investing activities
 
(11
)
 
 
149

Cash flows from financing activities
 
(343
)
 
 
(153
)
Effect of exchange rate changes in cash and cash equivalents
 
4

 
 
(5
)
Change in period
 
(534
)
 
 
(141
)

This reconciles to the total cash and cash equivalents, including restricted, which is as follows:
 
 
Successor
 
 
Predecessor
(In $ millions)
 
Six months ended June 30, 2019

 
 
Six months ended June 30, 2018

Opening cash and cash equivalents, included restricted
 
2,003

 
 
1,359

Change in period
 
(534
)
 
 
(141
)
Closing cash and cash equivalents, included restricted
 
1,469

 
 
1,218



16







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.
 
 
Successor
 
 
Predecessor
(In $ millions)
 
Six months ended June 30, 2019

 
 
Six months ended June 30, 2018

Net loss
 
(502
)
 
 
(635
)
Adjustments to reconcile net loss to net cash provided by operating activities (1)

 
434

 
 
629

Net loss after adjustments
 
(68
)
 
 
(6
)
Distributions received from associated company
 
2

 
 
17

Payments for long-term maintenance
 
(37
)
 
 
(78
)
Settlement of payment-in-kind interest on senior secured notes
 
(39
)
 
 

Changes in operating assets and liabilities
 
(42
)
 
 
(65
)
Net cash flows from operating activities
 
(184
)
 
 
(132
)

(1)  
Includes depreciation, amortization, share of results of joint ventures and associates, unrealized gains and losses on derivatives, unrealized gains and losses on marketable securities, deferred tax expense and other non-cash items shown under the sub-heading "adjustments to reconcile net loss to net cash provided by operating activities" in the Consolidated Statements of Cash Flows presented in the Consolidated Financial Statements included in this report.

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 six months ended June 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 six months ended June 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.

Net cash flows from investing activities for the six months ended June 30, 2018 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 six months ended June 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 six months ended June 30, 2018 were related to repayments of debt.

Contractual Obligations
At June 30, 2019 (Successor), we had the following contractual obligations and commitments:
 
Payment due by period
 
Period ended June 30
(In $ millions)
2020

 
2021 - 2022

 
2023 - 2024

 
Thereafter

 
Total

Interest bearing debt (1) (2)
185

 
1,297

 
3,007

 
2,276

 
6,765

Related party interest bearing debt

 

 
193

 
121

 
314

Total debt repayments
185

 
1,297

 
3,200

 
2,397

 
7,079

Pension obligations (3)
2

 
5

 
5

 
12

 
24

Operating lease obligations
8

 
15

 
5

 

 
28

Total contractual obligations
195

 
1,317

 
3,210

 
2,409

 
7,131


(1)
Debt principal repayments, excluding cash and payment-in-kind interest.

17







(2)
The above table assumes that we will make amortization payments on our secured credit facilities from 2020. Under the terms of the bank financing agreements we have the ability to defer up to $500 million of amortization payments (Amortization Conversion Election facility or "ACE") up to 120 days before such payment becomes due. The deferred amortization then becomes part of the balloon payment for each relevant facility. Based on the amortization schedule, the ACE has capacity to defer the first five quarters of amortization.
(3)
Pension obligations are the forecasted employer’s contributions to our defined benefit plans, expected to be made over the next ten years.

In addition to the above, we have recognized liabilities for uncertain tax positions of $87 million including interest and penalties as at June 30, 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, 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. We have set out our exposure to interest rate risk on our net debt obligations at June 30, 2019 in the table below:

(In $ millions)
 
Principal outstanding

 
Hedging instruments - see below

 
Net exposure

 
Impact of 1% increase in rates - see below

Senior Credit Facilities
 
5,662

 
4,500

 
1,162

 
36

Debt contained within VIEs
 
645

 

 
645

 
6

Total floating rate debt obligations
 
6,307

 
4,500

 
1,807

 
42

Senior secured notes (1)
 
458

 

 
N/A

 

Less: Cash and Restricted Cash
 
(1,469
)
 

 
(1,469
)
 
(15
)
Net debt
 
5,296

 
4,500

 
338

 
27

(1) The interest on the senior secured notes is fixed and therefore does not have exposure to interest rate fluctuations


18







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 June 30, 2019 was 2.33%. Therefore, the interest cap would mitigate the impact of 46% of a theoretical 1% point increase in the LIBOR rate. This is set out in the below table.
(In $ millions)
 
Amount

 
Impact of 1% point increase in rates (before impact of interest rate cap)

 
Less: impact of LIBOR CAP

 
Impact of 1% point increase in rates (after impact of interest rate cap)

 
 
 
 
 
 
 
 
 
Senior Credit Facility debt - hedged
 
4,500

 
45

 
(21
)
 
24

Senior Credit Facility debt - not hedged
 
1,162

 
12

 

 
12

Total Senior Credit Facility Debt
 
5,662

 
57

 
(21
)
 
36


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 six months ended June 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 June 30, 2019 (Successor) and December 31, 2018 (Successor), the carrying amount of our drilling units was close to $7 billion, representing 65% 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 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 TSA and participate in the Predecessor ’s broader debt restructuring under its Chapter 11 reorganization. The TSA executed between the parties provides an option to the holders 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.

19








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%. We derived the fair value of the external debt facilities with a discounted cash flow using a weighted average cost of debt of 6%.

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.

20







Responsibility Statement

We confirm, to the best of our knowledge, that the Consolidated Financial Statements for the period ended June 30, 2019, have been prepared in accordance with accounting principles generally accepted in the United States of America, and give a true and fair view of the assets, liabilities, financial position and results of the Group taken as a whole.

We also confirm that, to the best of our knowledge, these financial statements include a true and fair review of the development and performance of the business and the position of the Group, together with a description of the principal risks and uncertainties facing the Group.





Date: August 20, 2019
The Board of Directors
Seadrill Limited
Hamilton, Bermuda



/s/ Birgitte Ringstad Vartdal
Director
 
 
/s/ Eugene I. Davis
Director
 
 
/s/ Harald Thorstein
Director
 
 
/s/ John Fredriksen
Director and Chairman of the Board
 
 
/s/ Kjell-Erik Østdahl
Director
 
 
/s/ Peter J. Sharpe
Director
 
 
/s/ Scott D. Vogel
Director


21







Seadrill Limited
INDEX TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Consolidated Statements of Operations for the three and six months ended June 30, 2019 (Successor) and for the three and six months ended June 30, 2018 (Predecessor)
 
Unaudited Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2019 (Successor) and for the three and six months ended June 30, 2018 (Predecessor)
 
Unaudited Consolidated Balance Sheets as at June 30, 2019 (Successor) and December 31, 2018 (Successor)
 
Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2019 (Successor) and the six months ended June 30, 2018 (Predecessor)
 
Unaudited Consolidated Statements of Changes in Shareholders' Equity for the six months ended June 30, 2019 (Successor) and the six months ended June 30, 2018 (Predecessor)
 
Notes to Unaudited Consolidated Financial Statements
 


F-1





Seadrill Limited
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
for the three and six months ended June 30, 2019 (Successor) and 2018 (Predecessor)
 
 
Successor
 
 
Predecessor
 
Successor


Predecessor
  (In $ millions)
Notes
Three months ended June 30, 2019

 
 
Three months ended June 30, 2018

 
Six months ended June 30, 2019



Six months ended June 30, 2018

Operating revenues
 
 
 
 
 
 
 
 
 
 
Contract revenues
 
253

 
 
311

 
508

 
 
619

Reimbursable revenues
*
44

 
 
9

 
70

 
 
21

Other revenues
*
24

 
 
28

 
45

 
 
72

Total operating revenues
 
321

 
 
348

 
623

 
 
712

 
 
 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
 
 
Vessel and rig operating expenses
*
(182
)
 
 
(224
)
 
(381
)
 
 
(407
)
Reimbursable expense
 
(43
)
 
 
(8
)
 
(69
)
 
 
(20
)
Depreciation
 
(104
)
 
 
(195
)
 
(212
)
 
 
(391
)
Amortization of intangibles
 
(38
)
 
 

 
(73
)
 
 

General and administrative expenses
 
(30
)
 
 
(49
)
 
(61
)
 
 
(100
)
Total operating expenses
 
(397
)
 
 
(476
)
 
(796
)
 
 
(918
)
 
 
 
 
 
 
 
 
 
 
 
Other operating items
 
 
 
 
 
 
 
 
 
 
Impairment of long-lived assets
 

 
 
(414
)
 

 
 
(414
)
Other operating income
*
3

 
 
3

 
29

 
 
7

Total other operating items
 
3

 
 
(411
)
 
29

 
 
(407
)
 
 
 
 
 
 
 
 
 
 
 
Operating loss
 
(73
)
 
 
(539
)
 
(144
)
 
 
(613
)
 
 
 
 
 
 
 
 
 
 
 
Financial items and other income
 
 
 
 
 

 
 
 
 
 
Interest income
*
19

 
 
9

 
39

 
 
19

Interest expenses
*
(122
)
 
 
(19
)
 
(254
)
 
 
(38
)
Share in results from associated companies
12
(23
)
 
 
141

 
(65
)
 
 
149

Loss on derivative financial instruments
 
(6
)
 
 
(1
)
 
(33
)
 
 
(4
)
Net loss on debt extinguishment
 
(22
)
 
 

 
(22
)
 
 

Foreign exchange gain/(loss)
 
4

 
 
(8
)
 
2

 
 

(Loss)/gain on marketable securities
9
(14
)
 
 
25

 
(35
)
 
 
(3
)
Other financial items
*
1

 
 
(1
)
 
(2
)
 
 

Reorganization items
 

 
 
(35
)
 

 
 
(109
)
Total financial items and other non-operating items
 
(163
)
 
 
111

 
(370
)


14

 
 
 
 
 
 
 
 
 
 
 
Loss before income taxes
 
(236
)
 
 
(428
)
 
(514
)
 
 
(599
)
 
 
 
 
 
 
 


 
 


Income tax benefit / (expense)
 
30

 
 
(4
)
 
12



(36
)
Net loss
 
(206
)
 
 
(432
)
 
(502
)


(635
)
 
 
 
 
 
 
 
 
 
 
 
Net loss attributable to shareholder
 
(203
)
 
 
(296
)
 
(498
)
 
 
(477
)
Net loss attributable to non-controlling interest
 
(2
)
 
 
(138
)
 
(2
)
 
 
(160
)
Net (loss)/income attributable to redeemable non-controlling interest
 
(1
)
 
 
2

 
(2
)
 
 
2

 
 
 
 
 
 
 
 
 
 
 
Basic loss per share (US dollar)
 
(2.03
)
 
 
(0.59
)
 
(4.98
)
 
 
(0.95
)
Diluted loss per share (US dollar)
 
(2.03
)
 
 
(0.59
)
 
(4.98
)
 
 
(0.95
)
* Includes transactions with related parties. Refer to Note 24 – Related party transactions.
See accompanying notes that are an integral part of these unaudited Consolidated Financial Statements.





F-2





Seadrill Limited
UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
for the three and six months ended June 30, 2019 (Successor) and 2018 (Predecessor)
 
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
(In $ millions)
 
Three months ended June 30, 2019

 
 
Three months ended June 30, 2018

 
Six months ended June 30, 2019

 
 
Six months ended June 30, 2018

 
 
 
 
 
 
 
 
 
 
 
Net loss
 
(206
)
 
 
(432
)
 
(502
)
 
 
(635
)
Other comprehensive (loss)/income, net of tax:
 
 

 
 
 
 
 
 
 
 
Change in fair value of debt component of Archer convertible bond
 
1

 
 
2

 
6

 
 
2

Actuarial gain relating to pension
 

 
 
1

 

 
 
1

Share of other comprehensive (loss)/income from associated companies
 
(5
)
 
 
2

 
(9
)
 
 
11