Annual and Transition Report (foreign Private Issuer) (20-f)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 20-F

[_] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE
SECURITIES EXCHANGE ACT OF 1934

OR

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

OR

[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the transition period from ____ to ____

OR

[_] SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report:

Commission file number: 333-224459

SEADRILL LIMITED
(Exact name of Registrant as specified in its charter)
 
Bermuda
(Jurisdiction of incorporation or organization)
Par-la-Ville Place, 4th Floor, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda
(Address of principal executive offices)
Colleen Simmons
Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda
Tel: +1 (441) 295-9500, Fax: +1 (441) 295-3494
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person
Securities registered or to be registered pursuant to Section 12(b) of the Act:
 
Common stock, $0.10 par value
 
New York Stock Exchange
 
 
 
 
 
 
 
Title of class
 
Name of exchange on which registered
 

Securities registered or to be registered pursuant to Section 12(g) of the Act:  None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:



As of December 31, 2018 , there were 100,000,000 shares, par value $0.10 per share, of the Registrant’s common stock outstanding.
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
[_] Yes
[X] No
 
 
If this report is an annual report or transition report, indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
[_] Yes
[X] No
 
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
[X] Yes
[_] No
 
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit the files).
[X] Yes
[_] No

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  [_]
Accelerated filer  [X]
Non-accelerated filer   [_]
Emerging growth company  [_]
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  [_]

Indicate by check mark which basis of accounting the Registrant has used to prepare the financial statements included in this filing:
 
[X]  U.S. GAAP
 
[_]  International Financial Reporting Standards as issued by the International Accounting Standards Board
 
[_]  Other
 
If ”Other” has been checked in response to the previous question, indicate by check mark which
financial statement item the Registrant has elected to follow.
 
[_]  Item 17
 
[_]  Item 18

If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
[_]  Yes
[X]  No




TABLE OF CONTENTS
 
 
Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
 
PART 1
 
 
ITEM 1.
ITEM 2.
ITEM 3
ITEM 4.
ITEM 4A
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 8
ITEM 9.
ITEM 10.
ITEM 11.
ITEM 12.
 
 
 
PART II
 
 
ITEM 13.
ITEM 14.
ITEM 15
ITEM 16.
ITEM 16A.
ITEM 16B.
ITEM 16C.
ITEM 16D.
ITEM 16E.
ITEM 16F.
ITEM 16G.
ITEM 16H.
 
 
 
PART III
 
 
ITEM 17.
ITEM 18.
ITEM 19.

Table of Contents

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 annual report 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 annual report, 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;

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•
fluctuations in interest rates or exchange rates and currency devaluations relating to foreign or US monetary policy;
•
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 20-F 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.


Table of Contents

PART 1.
 
ITEM 1.
IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
 
Not applicable.
 
ITEM 2.
OFFER STATISTICS AND EXPECTED TIMETABLE
 
Not applicable.
 
ITEM 3.
KEY INFORMATION

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 “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. References to the term "the 2018 Successor period" refers to the period from July 2, 2018 to December 31, 2018.
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 "the 2018 Predecessor period" refers to the period from January 1, 2018 to July 1, 2018.
Unless otherwise indicated or the context otherwise requires, references in this report to the terms below have the following meanings:
•
“AOD” means Asia Offshore Drilling Limited, a company incorporated under the Laws of Bermuda with registration number 44712.
•
“Bankruptcy Court” means the United States Bankruptcy Court for the District of South Texas Victoria Division;
•
“Centerbridge” means Centerbridge Credit Partners L.P. and certain of its affiliates;
•
“Chapter 11 Proceedings” means reorganization proceedings under Chapter 11 of Title 11 of the United States Code.
•
“Commitment Parties” means each commitment party to the Investment Agreement;
•
“Companies Act” means the Companies Act 1981 of Bermuda, as amended from time to time;
•
“Debtors” means Seadrill Limited and certain of its subsidiaries which filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court on September 12, 2017;
•
“Effective Date” means the date of the Debtors’ emergence from bankruptcy proceedings in accordance with the terms and conditions of the Plan;
•
“Employee Incentive Plan” means the employee incentive plan that was implemented by Seadrill pursuant to the terms of the Plan which will, among other things, reserve an aggregate of 10 percent of the Common Shares, on a fully diluted, fully distributed basis, for grants made from time to time to employees of Seadrill and its subsidiaries and otherwise contain terms and conditions (including with respect to participants, allocation, structure, and timing of issuance) generally consistent with those prevailing in the market at the discretion of the board of directors of Seadrill;
•
“Exchange Act” means the Securities Exchange Act of 1934, as amended;
•
“Global Settlement” refers to the settlement announced by the Debtors on February 26, 2018 with an ad-hoc group of unsecured bond holders, the official committee of unsecured creditors and other major creditors. This is described under the heading “The Reorganization—Introduction”;
•
“Hemen” means Hemen Holding Limited, a Cyprus holding company with registration number HE87804 and Hemen Investments Limited, a Cyprus holding company with registration number HE371665;
•
“Investment Agreement” means the investment agreement described under the heading “The Reorganization—Introduction”;
•
“New Secured Notes” means the $880.0 million aggregate principal amount of 12.0% Senior Secured Notes due 2025 issued by NSNCo in connection with the Reorganization;
•
“NSNCo” means Seadrill New Finance Limited, a company incorporated under the Laws of Bermuda with registration number 53541, formed in connection with the Reorganization and the issuer of the New Secured Notes;
•
“NYSE” means the New York Stock Exchange;
•
“Old Seadrill Limited” or the “Predecessor Company” means Seadrill Limited, a company incorporated under the Laws of Bermuda with registration number 36832. Old Seadrill Limited was the parent company of Seadrill prior to its emergence from bankruptcy;
•
“OSE” means the Oslo Stock Exchange;

1
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•
“Plan” means the Second Amended Joint Chapter 11 Plan (as modified) of Reorganization, what was filed with the Bankruptcy Court on February 26, 2018 and confirmed by the Bankruptcy Court on April 17, 2018;
•
“Reorganization” means the transactions described under the heading “The Reorganization” and those transactions contemplated by the Plan;
•
“RSA” means the restructuring support and lock-up agreement that the Debtors entered with a group of bank lenders, bondholders, certain other stakeholders and new investors on September 12, 2017. This is described under the heading “The Reorganization—Introduction”;
•
“Sapura Energy” means Sapura Energy Berhad. We previously held an investment in Sapura Energy. Sapura Energy is also our joint venture partner for Seabras Sapura;
•
“Seabras Sapura” refers to our joint venture with Sapura Energy. We refer to our investments in Seabras Sapura Participacoes SA and Seabras Sapura Holding GmbH together as “Seabras Sapura”;
•
“Seadrill Limited” or the “Successor Company” means Seadrill Limited (formerly known as “New SDRL Limited”), a company incorporated under the Laws of Bermuda with registration number 53439. Seadrill Limited has been the parent company of Seadrill since its emergence from bankruptcy;
•
“Seadrill Common Shares” or the "Shares” means common shares, par value $0.10 per share, of Seadrill Limited;
•
“Seadrill Partners” means Seadrill Partners, LLC, a limited liability company formed under the Laws of the Republic of The Marshall Islands with registration number 962166;
•
“SeaMex” means SeaMex Limited, a limited liability company formed under the Laws of Bermuda with registration number 48115.

Throughout the report we refer to customers, suppliers and other key partners by the names they are commonly known by instead of their full legal names.

References in this annual report to “Total,” “Petrobras,” “ExxonMobil,” “LLOG,” “Saudi Aramco,” “ConocoPhillips” and “Equinor” refer to our key customers Total S.A., Petroleo Brasileiro S.A., Exxon Mobil Corporation, LLOG Exploration Company LLC, Saudi Arabian Oil Company, ConocoPhillips and Equinor ASA, respectively.

References in this annual report to “Cosco,” “Samsung,” “DSME,” “Dalian,” “Jurong,” and “HSHI” refer to the shipyards Cosco (Qidong) Offshore Co. Limited, Samsung Heavy Industries, Daewoo Shipbuilding & Marine Engineering, Dalian Shipbuilding Industry Offshore Co., Ltd., Jurong Shipyard Pte Ltd., and Hyundai Samho Heavy Industries Co. Ltd., respectively.

Unless otherwise indicated, all references to “US$” and “$” in this annual report are to, and amounts are presented in, US dollars. All references to “€” are to euros, all references to “£” or “GBP” are to pounds sterling, all references to “NOK” are to Norwegian krone and all references to “SEK” are to Swedish krona.

A.
SELECTED FINANCIAL DATA
 
Our selected statement of operations and other financial data with respect to the 2018 Successor period , the 2018 Predecessor period and the fiscal years ended December 31, 2017 and 2016 and our selected balance sheet data as of December 31, 2018 and 2017 have been derived from our Consolidated Financial Statements included in Item 18 of this annual report, or the Consolidated Financial Statements, which have been prepared in accordance U.S. GAAP.
 
Our selected Statement of Operations and other financial data for the fiscal years ended December 31, 2015 and 2014 and our selected balance sheet data as of December 31, 2016 , 2015 and 2014 have been derived from the Consolidated Financial Statements that are not included herein.

We deconsolidated our investments in Seadrill Partners on January 2, 2014, and deconsolidated our investments in SeaMex, on March 10, 2015. Please see “ITEM 4. Information on the Company—A. History and Development of the Company” for further information.
 
The following table should be read in conjunction with “ITEM 5. Operating and Financial Review and Prospects” and our Consolidated Financial Statements and notes thereto, which are included herein. Our Consolidated Financial Statements are maintained in U.S. dollars. We refer you to the notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are prepared, and we draw your attention to the statement regarding the application of Fresh Start accounting as described in Note 1 "General information" of our Consolidated Financial Statements included herein.




2
Table of Contents

 
Successor
 
Predecessor
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

 
Year ended December 31,
2015

 
Year ended December 31,
2014

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions of U.S. dollars except common
share and per share data)
 
 
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
 
Total operating revenues
541

 
712

 
2,088

 
3,169

 
4,335

 
4,997

Net operating (loss)/ income
(175
)
 
(613
)
 
(728
)
 
1,026

 
1,019

 
2,279

Net (loss)/income
(605
)
 
(3,885
)
 
(3,102
)
 
(155
)
 
(635
)
 
4,087

(Loss)/earnings per share, basic
(6.02
)
 
(7.71
)
 
(5.89
)
 
(0.36
)
 
(1.29
)
 
8.32

(Loss)/earnings per share, diluted
(6.02
)
 
(7.71
)
 
(5.89
)
 
(0.36
)
 
(1.29
)
 
8.30




 
Successor
 
Predecessor
 
As of December 31,
 
As of December 31,
 
2018

 
2017

 
2016

 
2015

 
2014

 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions of U.S. dollars except common share and per share data)
 
 
Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
1,542

 
1,255

 
1,368

 
1,044

 
831

Drilling units
6,659

 
13,216

 
14,276

 
14,930

 
15,145

Newbuildings
—

 
248

 
1,531

 
1,479

 
2,030

Investment in associated companies
800

 
1,473

 
2,168

 
2,592

 
2,898

Goodwill
—

 
—

 
—

 
—

 
604

Total assets
10,848

 
17,982

 
21,666

 
23,439

 
26,297

Long-term debt (including current portion)  (1)
6,914

 
8,699

 
9,514

 
10,543

 
12,475

Common share capital
10

 
1,008

 
1,008

 
985

 
985

Total equity
3,035

 
6,959

 
10,063

 
10,068

 
10,390

Common shares outstanding (in millions)
100.0

 
504.5

 
504.4

 
492.8

 
492.8

Weighted average common shares outstanding (in millions)
100.0

 
504.5

 
501.0

 
492.8

 
478.0

 
(1)
Includes $7,705 million of debt classified as liabilities subject to compromise in 2017.

 
Successor
 
Predecessor
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

 
Year ended December 31,
2015

 
Year ended December 31,
2014

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions of U.S. dollars except common
share and per share data)
 
 
Statement of Cash Flows data:
 
 
 
 
 
 
 
 
 
 
 
Operating cash flows
(26
)
 
(213
)
 
399

 
1,184

 
1,788

 
1,574

Investing cash flows
61

 
149

 
358

 
354

 
(165
)
 
197

Financing cash flows
(208
)
 
887

 
(846
)
 
(1,405
)
 
(1,370
)
 
(1,521
)
Capital expenditure   (2)
(98
)
 
(127
)
 
(150
)
 
(231
)
 
(1,041
)
 
(3,168
)

(2) Capital expenditures include additions to drilling units and equipment, additions to newbuildings, as well as payments for long-term maintenance.

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B.
CAPITALIZATION AND INDEBTEDNESS
 
Not applicable.

C.
REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.
D. RISK FACTORS

Our assets are primarily engaged in offshore contract drilling for the oil and gas industry in benign and harsh environments worldwide, including ultra-deepwater environments. The following risks principally relate to our emergence from bankruptcy, the industry in which we operate and our business in general. Other risks relate principally to the market for and ownership of our securities. The occurrence of any of the events described in this section could materially and negatively affect our business, financial condition, operating results, cash available for the payment of dividends or the trading price of our common shares. Unless otherwise indicated, all information concerning our business and our assets is as of December 31, 2018 . The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations.

Risks Relating to Our Emergence from Bankruptcy
Our actual financial results may vary significantly from the projections filed with the Bankruptcy Court.
In connection with the Plan process, the Debtors were required to prepare projected financial information to demonstrate to the Bankruptcy Court the feasibility of the restructuring plan and the ability of the Debtors to continue operations upon emergence from bankruptcy. At the time they were last filed with the Bankruptcy Court on February 26, 2018, the projections reflected numerous assumptions concerning anticipated future performance and prevailing and anticipated market and economic conditions that were and continue to be beyond our control and that may not materialize. Further, to the extent we issue new guidance in 2019 and beyond, such projections will supersede any prior guidance. Projections, in any event, are inherently subject to uncertainties and to a wide variety of significant business, economic and competitive risks. Our actual results will vary from those contemplated by our projections and the variations may be material.
Because our Consolidated Financial Statements will reflect fresh start accounting adjustments made upon emergence from bankruptcy, financial information in our future financial statements will not be comparable to Seadrill’s financial information from prior periods.
Upon emergence from Chapter 11 Proceedings, on July 2, 2018, we adopted fresh start accounting in accordance with the provisions set forth in ASC 852, Reorganizations. Adopting fresh start accounting results in a new financial reporting entity with no retained earnings or deficits brought forward. Upon the adoption of fresh start accounting, our assets and liabilities were recorded at their fair values which differ materially from the recorded values of our assets and liabilities as reflected in the Predecessor historical Consolidated Balance Sheets. Thus, our future Consolidated Balance Sheets and Statements of Operations will not be comparable in many respects to Consolidated Balance Sheets and Statements of Operations data for periods prior to adoption of fresh start accounting. You will not be able to compare information reflecting our post-emergence Consolidated Financial Statements to information for periods prior to emergence from bankruptcy, without adjusting for fresh start accounting. The lack of comparable historical information may discourage investors from purchasing our common shares. Additionally, the financial information contained in this annual report on Form 20-F may not be indicative of future financial information.
We cannot be certain that the bankruptcy proceeding will not adversely affect our operations going forward.
We operated in bankruptcy from September 12, 2017 to July 1, 2018. Whilst we have now emerged from Chapter 11, we cannot assure you that our previous use of Chapter 11 Proceedings will not adversely impact our ongoing operations.
We may be subject to claims that were not discharged in the bankruptcy proceedings, which could have a material adverse effect on our results of operations and profitability.
Substantially all the material claims against the Debtors that arose prior to the date of the bankruptcy filing were addressed during the Chapter 11 Proceedings or were resolved in connection with the Plan and the order of the Bankruptcy Court confirming the Plan. However, we may be subject to claims that were not discharged in the Chapter 11 Proceedings. Circumstances in which claims and other obligations that arose prior to the bankruptcy filing that were not discharged primarily relate to certain actions by governmental units under police power authority, where we have agreed to preserve a claimant’s claims, as well as, potentially, instances where a claimant had inadequate notice of the bankruptcy filing. In addition, except in limited circumstances, claims against non-debtor subsidiaries, are generally not subject to discharge under the Bankruptcy Code. To the extent any pre-filing liability remains, the ultimate resolution of such claims and other obligations may have a material adverse effect on our results of operations, profitability and financial condition.
Risks Relating to Our Company and Industry

The success and growth of our business depend on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition.
Our business depends on the level of oil and gas exploration, development and production in offshore areas worldwide that is influenced by oil and gas prices and market expectations of potential changes in these prices.
Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including, but not limited to, the following:

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•
worldwide production of, and demand for, oil and gas and geographical dislocations in supply and demand;
•
the cost of exploring for, developing, producing and delivering oil and gas;
•
expectations regarding future energy prices and production;
•
advances in exploration, development and production technology;
•
the ability of the Organization of the Petroleum Exporting Countries or OPEC, to set and maintain levels of production and pricing;
•
the level of production in non-OPEC countries;
•
international sanctions on oil-producing countries, or the lifting of such sanctions;
•
government regulations, including restrictions on offshore transportation of oil and natural gas;
•
local and international political, economic and weather conditions;
•
domestic and foreign tax policies;
•
the development and exploitation of alternative fuels and unconventional hydrocarbon production, including shale;
•
worldwide economic and financial problems and the corresponding decline in the demand for oil and gas and, consequently, our services;
•
the policies of various governments regarding exploration and development of their oil and gas reserves, accidents, severe weather, natural disasters and other similar incidents relating to the oil and gas industry; and
•
the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, Eastern Europe or other geographic areas or further acts of terrorism in the United States, Europe or elsewhere.
Decreases in oil and gas prices for an extended period of time, or market expectations of potential decreases in these prices, have negatively affected and could continue to negatively affect our future performance.
Continued periods of low demand can cause excess rig supply and intensify competition in our industry, which often results in drilling rigs, particularly older and less technologically-advanced drilling rigs, being idle for long periods of time. We cannot predict the future level of demand for drilling rigs or future condition of the oil and gas industry with any degree of certainty. In response to the decrease in the prices of oil and gas, a number of our oil and gas company customers have announced significant decreases in budgeted expenditures for offshore drilling. Any future decrease in exploration, development or production expenditures by oil and gas companies could further reduce our revenues and materially harm our business.
In addition to oil and gas prices, the offshore drilling industry is influenced by additional factors, which could reduce demand for our services and adversely affect our business, including:
•
the availability and quality of competing offshore drilling units;
•
the availability of debt financing on reasonable terms;
•
the level of costs for associated offshore oilfield and construction services;
•
oil and gas transportation costs;
•
the level of rig operating costs, including crew and maintenance;
•
the discovery of new oil and gas reserves;
•
the political and military environment of oil and gas reserve jurisdictions; and
•
regulatory restrictions on offshore drilling.

The offshore drilling industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, rig location, the condition and integrity of equipment, the rig's and/or the drilling contractor's record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations. Our operations may be adversely affected if our current competitors or new market entrants introduce new drilling rigs with better features, performance, prices or other characteristics compared to our drilling rigs, or expand into service areas where we operate.
Competitive pressures and other factors may result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our results of operations and financial condition.
The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.
The oil and gas drilling industry is cyclical and is currently in a prolonged downcycle. The price of Brent crude has fallen from $115 per barrel in June 2014 to a low of $30 per barrel in January 2016. As at December 31, 2018 , the price of Brent crude was approximately $55 per barrel. During the downturn our customers have reduced their expenditures on offshore drilling which, coupled with additional newbuild supply, has led to increased price competition and has put significant pressure on dayrates and utilization of our rigs.
If we are unable to secure contracts for our drilling units upon the expiration of our existing contracts, we may stack our units. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. As of December 31, 2018 , we had 16 idle units, either “warm stacked,” which means the rig is kept operational and ready for redeployment, and maintains most of its crew, or “cold stacked,” which means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is reassigned to an active rig or dismissed. Without new drilling contracts or additional financing being available when needed or available only on unfavorable terms, we will be unable to meet our obligations as they come due or we may be unable to enhance our existing business, complete additional drilling unit acquisitions or otherwise take advantage of business opportunities as they arise.

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In the current environment, our customers may also seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, resulting in lower dayrates. Our inability, or the inability of our customers to perform, under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.
From time to time, we are approached by potential buyers for the outright purchase of some of our drilling units, businesses, or other fixed assets. We may determine that such a sale would be in our best interests and agree to sell certain drilling units or other assets. Such a sale could have an impact on short-term liquidity and net income. We may recognize a gain or loss on disposal depending on whether the fair value of the consideration received is higher or lower than the carrying value of the asset.
We do not know when the market for offshore drilling units may recover, or the nature or extent of any future recovery. There can be no assurance that the current demand for drilling rigs will not further decline in future periods. The continued or future decline in demand for drilling rigs would adversely affect our financial position, operating results and cash flows.
We may not have sufficient liquidity to meet our obligations as they fall due or have the ability to raise new capital or refinance existing facilities on acceptable terms.
As at December 31, 2018 , we had $ 7,086 million in principal amount of interest-bearing debt (excluding related party debt of $ 314 million ). This includes our 12% (4% payable in cash and 8% payment-in-kind ("PIK") secured notes due 2025 (the “NSNs”) issued in connection with our Chapter 11 Proceedings, of which $ 769 million in principal amount remains outstanding. Our debt is secured by, among other things, liens on our drilling units, investments in affiliates and available cash.
Our outstanding indebtedness and potential future indebtedness could affect our future operations, since a portion of our cash flow from operations will be dedicated to the payment of interest and principal and will not be available for other purposes (noting that the debt service will primarily comprise of interest for the three years from the Effective Date as the majority of our current lenders have agreed to an amortization holiday during this period). Similarly, the fact that our debt is secured by our assets means that these assets or their proceeds cannot be used for debt service or other corporate purposes.
We have however successfully completed a consent solicitation process to amend certain terms of the indenture and escrow agreement related to the NSNs to enable us to, among other things, make a tender offer for the NSNs using various proceeds, including the approximately $230 million held in a secured escrow account for the NSNs and certain unused net realization proceeds arising from the NSN collateral. An indirect subsidiary of the Company commenced a cash tender offer for up to $311 million in aggregate principal amount of the NSNs pursuant to an offer to purchase dated March 12, 2019. The tender offer will expire on April 8, 2019.

We have a 35% interest in the common units of Seadrill Partners LLC. The distribution on those units in respect of the quarter ended December 31, 2018 was reduced by 90% to one cent per unit. In the event, distributions continue at a minimal level, this may adversely affect our liquidity position.

Covenants contained in our debt agreements require us to meet certain financial and non-financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business or economic conditions, which may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns, and compete with others in our industry for strategic opportunities, and may limit our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes.
Our ability to meet our debt service obligations and to fund planned expenditures will be dependent upon our future performance, which will be subject to prevailing economic conditions, industry cycles and financial, business, regulatory and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all our debt obligations and contractual commitments, and any insufficiency could negatively impact our business. To the extent that we are unable to repay our indebtedness as it becomes due or at maturity, we may need to refinance or restructure our debt, raise new debt, sell assets or repay the debt with the proceeds from equity offerings.
The covenants in our credit facilities impose operating and financial restrictions on us, of which a breach could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed.
Our credit facility agreements impose operating and financial restrictions on us. These restrictions may prohibit or otherwise limit our ability to undertake certain business activities without consent of the lending banks. These restrictions include:
•
executing other financing arrangements;
•
incurring additional indebtedness;
•
creating or permitting liens on our assets;
•
selling our drilling units or the shares of our subsidiaries;
•
making investments;
•
changing the general nature of our business;
•
paying dividends to our shareholders;
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changing the management and/or ownership of the drilling units; and
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making capital expenditures.
These restrictions may affect our ability to compete effectively to the extent of our competitors, whom are subject to less onerous restrictions.

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Our lenders’ interests may be different from ours and we may not be able to obtain our lenders’ consent when beneficial for our business, which may impact our performance or our ability to obtain replacement or additional finance. In addition, the profile of our lenders has changed since emergence from the Chapter 11 Proceedings, with the replacement of certain relationship banks by lenders whose focus may be shorter-term in nature or different. The new profile of our lenders may make it more difficult for us to obtain lender consents when beneficial to our business or to obtain replacement or additional finance.
The different rankings in our capital structure of our lenders and the collateral arrangements which they benefit from in relation to different assets and the consequential complex intercreditor arrangements that exist means that the interests of our lenders will not always be aligned, which may make it more difficult for us to obtain lender consents when beneficial to our business or to obtain replacement or additional finance.

Following emergence from Chapter 11 Proceedings on the Effective Date, with exception of minimum liquidity requirements, we are exempt from financial covenants until Q1 2021. Thereafter, in addition to minimum liquidity requirements we are required to maintain and satisfy certain financial ratios and covenants, relating to net leverage and debt service coverage.
The time that we spent subject to Chapter 11 Proceedings has utilized some of the period for which we were able to negotiate financial covenant flexibility and reduced the period available for the Group to operate outside of Chapter 11 Proceedings to reach a position of compliance with the financial covenants when they do apply.

If we are unable to comply with the net leverage and debt service coverage covenants in our debt agreements between Q1 2021 and Q4 2021, this will lead to a margin increase of up to 100 bps PIK interest, however it does not constitute an event of default. Thereafter, if we are unable to comply with any of these restrictions and covenants, and we are unable to obtain a waiver or amendment from our lenders for such non-compliance, a default could occur under the terms of those agreements. If a default occurs under these agreements, lenders could terminate their commitments to lend or accelerate the outstanding loans and declare all amounts borrowed due and payable or exercise other enforcement rights.

Our debt agreements contain cross-default provisions, meaning that if we are in default under one of our loan agreements, amounts outstanding under our other loan agreements may also be in default, accelerated and become due and payable. Our drilling units also serve as security under certain of our debt agreements. If our lenders were to foreclose their liens on our drilling units in the event of a default, this may impair our ability to continue our operations. As at December 31, 2018 , we had $7,086 million of interest-bearing debt secured by, among other things, liens on our drilling units.
If any of the aforementioned events occurs, our assets may be insufficient to repay all our outstanding indebtedness in full, and we may be unable to find alternative financing. Even if we could obtain alternative financing, that financing might not be on terms that we consider favorable or acceptable. Moreover, in connection with any further waivers of or amendments to our credit facilities that we may obtain, our lenders may impose additional operating and financial restrictions on us or modify the terms of our existing credit facilities. Any of these events may further restrict our ability to pay dividends, repurchase our common shares, make capital expenditures or incur additional indebtedness.
Certain of our affiliated or related companies may be unable to service their debt requirements and comply with the provisions contained in their loan agreements.
The failure of certain of the Company's affiliated or related companies to service their debt requirements and comply with the provisions contained in their debt agreements may lead to an event of default under such agreements, which may have a material adverse effect on the Group. Such affiliated and related companies include (i) Asia Offshore Drilling ("AOD"), (ii) certain subsidiaries of Ship Finance International Limited ("Ship Finance"), and (iii) certain subsidiaries of Seabras Sapura.
If a default occurs under the debt agreements of our affiliated or related companies, the lenders could accelerate the outstanding borrowings and declare all amounts outstanding due and payable. In this case, if such entities are unable to obtain a waiver or an amendment to the applicable provisions of the debt agreements, or do not have enough cash on hand to repay the outstanding borrowings, the lenders may, among other things, foreclose their liens on the drilling units and other assets securing the loans, if applicable, or seek repayment of the loan from such entities. 
We have provided guarantees over certain debt facilities of our affiliates and related companies. If our affiliates or related companies are unable to meet their obligations outlined above, the lenders could look to us to meet such liabilities. Some examples are outlined in the following paragraphs.
We have provided guarantees over AOD's senior secured debt as we have in respect of the bank facilities of other members of the Group and may not have sufficient funds to repay lenders in full if they seek to enforce the guarantees.
We have an outstanding financial guarantee over one of Seabras Sapura's senior secured credit facility agreements that was used to partially fund the acquisition of the pipe-laying support vessel Sapura Esmeralda . As a condition to the lenders making the loan available to Seabras Sapura, we provided a sponsor guarantee, on a joint and several basis with our joint venture partner, Sapura Energy. The total amount guaranteed by the joint venture partners as at December 31, 2018 was $ 165 million .
We also consolidate certain subsidiaries of Ship Finance into our Consolidated Financial Statements as variable interest entities or VIEs. To the extent that the VIEs default under their indebtedness and their debt becomes classified as current in their financial statements, we would in turn mark such indebtedness as current in our Consolidated Financial Statements. The characterization of the indebtedness in our Consolidated Financial Statements as current may adversely impact our compliance with the covenants contained in our existing and future debt agreements.
Our debt agreements also contain cross-default provisions that may be triggered if we fail to comply with our obligations under the guarantees or support agreements described above. Such cross-defaults could result in the acceleration of the maturity of the debt under our agreements

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and our lenders may foreclose upon any collateral securing that debt, including our drilling units and other assets, even if such default was subsequently cured. In the event of such acceleration and foreclosure, we will not have sufficient funds or other assets to satisfy all our obligations.
A number of our affiliates or related companies are joint ventures, to which we may have funding obligations. Our partners in these joint ventures may have different objectives or strategies or different financial positions from us and this may affect how these joint ventures perform, how they are supported, their compliance with the financing and contractual arrangements to which they are subject and our interests in and cash flows from them. In addition, affiliates or related companies that we do not control may take actions that we would not have taken or fail to take action which we would have taken.

The occurrence of any of the events described above would have a material adverse effect on our business and may impair our ability to continue as a going concern.
Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted.
In the current market conditions, some of our customers may seek to terminate their agreements with us.
Some of our customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee. The general principle is that such early termination fee shall compensate us for lost revenues less operating expenses for the remaining contract period; however, in some cases, such payments may not fully compensate us for the loss of the drilling contract.
Under certain circumstances our contracts may permit customers to terminate contracts early without the payment of any termination fees, as a result of non-performance, periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events beyond our control. In addition, national oil company customers may have special termination rights by law. During periods of challenging market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts, including through claims of non-performance.
Our customers may seek to renegotiate their contracts with us using various techniques, including threatening breaches of contract and applying commercial pressure, resulting in lower dayrates or the cancellation of contracts with or without any applicable early termination payments.
Reduced dayrates in our customer contracts and cancellation of drilling contracts (with or without early termination payments) may adversely affect our performance and lead to reduced revenues from operations.
Our contract backlog for our fleet of drilling units may not be realized.
As of February 28, 2019 , our contract backlog was approximately $ 2 billion . The contract backlog presented in this annual report on Form 20-F and our other public disclosures is only an estimate. The actual amount of revenues earned and the actual periods during which revenues are earned will be different from the contract backlog projections due to various factors, including shipyard and maintenance projects, downtime and other events within or beyond our control. In addition, we or our customers may seek to cancel or renegotiate our contracts for various reasons, including adverse conditions, such as the current environment, resulting in lower dayrates. In some instances, there is an option for a customer to terminate a drilling contract prematurely for convenience on payment of an early termination fee. However, this fee may not adequately compensate us for the loss of this drilling contract. Our inability, or the inability of our customers, to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.
We may not be able to renew or obtain new and favorable contracts for our drilling units whose contracts have expired or have been terminated.
During the period of high utilization and high dayrates, which we now believe ended in early 2014, industry participants ordered the construction of new drilling units, which resulted in an over-supply and caused, in conjunction with deteriorating industry conditions, a subsequent decline in utilization and dayrates when the new drilling units entered the market. A relatively large number of the drilling units currently under construction have not been contracted for future work, and a number of units in the existing worldwide fleet are currently off-contract.
As at February 28, 2019 , we had 19 current or future contracted units and 16 idle units. Of the contracted units we expect 14 to become available in 2019 , two in 2020 , and three thereafter. We expect the three contracts that expire after 2020 to expire in 2021, 2027 and 2028. Our ability to renew contracts or obtain new contracts will depend on our customers and prevailing market conditions, which may vary among different geographic regions and types of drilling units.
The over-supply of drilling units will be exacerbated by the entry of newbuild rigs into the market, many of which are without firm drilling contracts. The supply of available uncontracted units has intensified price competition as scheduled delivery dates occur and contracts terminate without renewal, reducing dayrates as the active fleet grows. Customers may opt to contract older rigs in order to reduce costs which could adversely affect our ability to obtain new drilling contracts due to our newer fleet.
In addition, as our fleet of drilling units becomes older, any competitive advantage of having a modern fleet may be reduced to the extent that we are unable to acquire newer units or enter into newbuilding contracts as a result of financial constraints. For as long as there is an oversupply of drilling rigs, it may be more difficult for older rigs to secure extensions or new contract awards.
If we are unable to secure contracts for our drilling units upon the expiration of our existing contracts, we may continue to idle or stack our units. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. As at February 28, 2019 we had 16 units either "warm stacked", which means the rig is kept operational and ready for redeployment, and maintains most of its crew, or “cold stacked,” which means the rig is stored in a harbor, shipyard or a designated offshore

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area, and the crew is reassigned to an active rig or dismissed. Please see “-Our drilling contracts contain fixed terms and day-rates, and consequently we may not fully recoup our costs in the event of a rise in expenses, including operating and maintenance costs.”
If we are not able to obtain new contracts in direct continuation of existing contracts, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contract terms, our revenues and profitability could be adversely affected. We may also be required to accept more risk in areas other than price to secure a contract and we may be unable to push this risk down to other contractors or be unable or unwilling at competitive prices to insure against this risk, which will mean the risk will have to be managed by applying other controls. This could lead to us being unable to meet our liabilities in the event of a catastrophic event on one of our rigs.
The market value of our drilling units may decrease.
The market values of drilling units have been trending lower as a result of the recent continued decline in the price of oil, which has impacted the spending plans of our customers and utilization of the global fleet. If the offshore drilling industry suffers further adverse developments in the future, the fair market value of our drilling units may decrease further. Upon emergence from the Chapter 11 Proceedings, our assets, including drilling units, were recognized at fair value. The fair market value of the drilling units that we currently own, or may acquire in the future, may increase or decrease depending on a number of factors, including:
•
the general economic and market conditions affecting the offshore contract drilling industry, including competition from other offshore contract drilling companies;
•
the types, sizes and ages of drilling units;
•
the supply and demand for drilling units;
•
the costs of newbuild drilling units;
•
the prevailing level of drilling services contract dayrates;
•
governmental or other regulations; and
•
technological advances.
If drilling unit values fall significantly, we may have to record an impairment adjustment in our Consolidated Financial Statements, which could adversely affect our financial results and condition. Additionally, if we sell one or more of our drilling units at a time when drilling unit prices have fallen and before we have recorded an impairment adjustment to our Consolidated Financial Statements, the sale price may be less than the drilling unit’s carrying value in our Consolidated Financial Statements, resulting in a loss on disposal and a reduction in earnings and cause us to breach the covenants in our finance agreements. For more information see “-The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.”
Our business and operations involve numerous operating hazards, and in the current market we are increasingly required to take additional contractual risk in our customer contracts and we may not be able to procure insurance to adequately cover potential losses.
Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch-throughs, cratering, fires, explosions and pollution. Contract drilling and well servicing requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause 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, investigations and other proceedings by regulatory authorities which may involve fines and other sanctions, and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather (which may be more acute in certain areas where we operate) and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. We customarily provide contract indemnity to our customers for claims that could be asserted by us relating to damage to or loss of our equipment, including rigs and claims that could be asserted by us or our employees relating to personal injury or loss of life.
Damage to the environment could also result from our operations, particularly through spillage of fuel, lubricants or other chemicals and substances used in drilling operations or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies.
Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our customers generally assume, and indemnify us against certain risks for example, well control and subsurface risks, and we generally assume, and indemnify against, above surface risks (including spills and other events occurring on our rigs). Subsurface risks indemnified by our customers generally include risks associated with the loss of control of a well, such as blowout or cratering or uncontrolled well-flow, the cost to regain control of or re-drill the well and associated pollution. However, there can be no assurances that these customers will be willing or financially able to indemnify us against these risks under our contracts. The terms of our drilling contracts vary based on negotiation, applicable local laws and regulations and other factors, and in some cases, customers may seek to cap indemnities or narrow the scope of their coverage, reducing our level of contractual protection.
In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a decision in a case related to the fire and explosion that took place on the unaffiliated Deepwater Horizon Mobile Offshore Drilling Unit in the Gulf of Mexico in April 2010, or the Deepwater Horizon Incident (to which we were not a party), a U.S. District Court invalidated certain contractual indemnities under a drilling contract governed by U.S. law. Further, pollution and environmental risks generally are not totally insurable. If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from a customer, the occurrence could adversely affect our performance.

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The amount recoverable under insurance may also be less than the related impact on enterprise value after a loss or not cover all potential consequences of an incident and include annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits. Any such lack of reimbursement may cause us to incur substantial costs.
We could decide to retain more risk through self-insurance in the future. This self-insurance results in a higher risk of losses, which could be material, which are not covered by third-party insurance contracts. Specifically, we have at times in the past elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico due to the substantial costs associated with such coverage. Although we currently insure a limited part of this windstorm risk pursuant to a policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico with a combined single limit of $100 million in the annual aggregate, this policy is subject to certain exclusions and limitations and may not be sufficient to cover future losses caused by such storms. In addition, if we elect to self-insure such risks again in the future and such windstorms cause significant damage to any rig and equipment we have in the U.S. Gulf of Mexico, it could have a material adverse effect on our financial position, results of operations and cash flows.
No assurance can be made that we will be able to maintain adequate insurance in the future at rates that we consider reasonable, or that we will be able to obtain insurance against certain risks.
We rely on a small number of customers.
Our contract drilling business is subject to the risks associated with having a limited number of customers for our services. For the period from July 2, 2018 through December 31, 2018 , our five largest customers, Saudi Aramco, ConocoPhillips, Petrobras, Equinor and LLOG, accounted for approximately 81% of our revenues. In addition, mergers among oil and gas exploration and production companies will further reduce the number of available customers, which would increase the ability of potential customers to achieve pricing terms favorable to them. Our results of operations could be materially adversely affected if any of our major customers fail to compensate us for our services or take actions outlined above. Please see "-Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted".
We are subject to risks of loss resulting from non-payment or non-performance by our customers and certain other third parties. Some of these customers and other parties may be highly leveraged and subject to their own operating and regulatory risks. If any key customers or other parties default on their obligations to us, our financial results and condition could be adversely affected. Any material non-payment or non-performance by these entities, other key customers or certain other third parties could adversely affect our financial position, results of operations and cash flows.
Our drilling contracts contain fixed terms and day-rates, and consequently we may not fully recoup our costs in the event of a rise in expenses, including operating and maintenance costs.
Our operating costs are generally related to the number of units in operation and the cost level in each country or region where the units are located. A significant portion of our operating costs may be fixed over the short term.
The majority of our contracts have dayrates that are fixed over the contract term. To mitigate the effects of inflation on revenues from term contracts, most of our long-term contracts include escalation provisions. These provisions allow us to adjust the dayrates based on stipulated external cost indices, including wages, insurance and maintenance costs. However, actual cost increases may result from events or conditions that do not cause correlative changes to the applicable indices. Furthermore, certain indices are updated semi-annually, and therefore may be outdated at the time of adjustment. The adjustments are typically performed on a semi-annual or annual basis. For these reasons, the timing and amount awarded as a result of such adjustments may differ from our actual cost increases, which could adversely affect our financial performance. Some of our long-term contracts contain rate adjustment provisions based on market dayrate fluctuations rather than cost increases. In such contracts, the dayrate could be adjusted lower during a period when costs of operation rise, which could adversely affect our financial performance. In addition, our contracts typically contain provisions for either fixed or dayrate compensation during mobilization. These rates may not fully cover our costs of mobilization, and mobilization may be delayed, increasing our costs, without additional compensation from the customer, for reasons beyond our control.
In connection with new assignments, we might incur expenses relating to preparation for operations under a new contract. Expenses may vary based on the scope and length of such required preparations and the duration of the contractual period over which such expenditures are amortized.
Equipment maintenance costs fluctuate depending upon the type of activity that the unit is performing and the age and condition of the equipment. Our operating expenses and maintenance costs depend on a variety of factors, including crew costs, provisions, equipment, insurance, maintenance and repairs, and shipyard costs, many of which are beyond our control.
In situations where our drilling units incur idle time between assignments, the opportunity to reduce the size of our crews on those drilling units is limited, as the crews will be engaged in preparing the unit for its next contract. When a unit faces longer idle periods, reductions in costs may not be immediate as some of the crew may be required to prepare drilling units for stacking and maintenance in the stacking period. Should units be idle for a longer period, we will seek to redeploy crew members who are not required to maintain the drilling unit to active rigs, to the fullest extent possible. However, there can be no assurance that we will be successful in reducing our costs in such cases.
Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in supply of offshore drilling units and demand for contract drilling services. This could adversely affect our revenue from operations. For more information please see “-The success and growth of our business depend on the level of activity in the offshore oil and gas industry generally, and the drilling industry specifically, which are both highly competitive and cyclical, with intense price competition,"

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“-Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted" and “-Our contract backlog for our fleet of drilling units may not be realized."
Consolidation and governmental regulation of suppliers may increase the cost of obtaining supplies or restrict our ability to obtain needed supplies.
We rely on certain third parties to provide supplies and services necessary for our offshore drilling operations, including, but not limited to, drilling equipment suppliers, catering and machinery suppliers. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing key supplies. With respect to certain items, such as blow-out preventers or “BOPs” and drilling packages, we are dependent on the original equipment manufacturer for repair and replacement of the item or its spare parts. Such consolidation, combined with a high volume of drilling units under construction, may result in a shortage of supplies and services, thereby increasing the cost of supplies and/or potentially inhibiting the ability of suppliers to deliver on time. These cost increases or delays could have a material adverse effect on our results of operations, resulting in rig downtime, and delays in the repair and maintenance of our drilling rigs.
We may be unable to obtain, maintain, and/or renew permits necessary for our operations or experience delays in obtaining such permits including the class certifications of rigs.
The operation of our drilling units will require certain governmental approvals, the number and prerequisites of which cannot be determined until we identify the jurisdictions in which we will operate on securing contracts for the drilling units. Depending on the jurisdiction, these governmental approvals may involve public hearings and costly undertakings on our part. We may not obtain such approvals or such approvals may not be obtained in a timely manner. If we fail to secure the necessary approvals or permits in a timely manner, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment.
Every offshore drilling unit is a registered marine vessel and must be “classed” by a classification society to fly a flag. The classification society certifies that the drilling unit is “in-class,” signifying that such drilling unit has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the drilling unit’s country of registry and the international conventions of which that country is a member. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake them on application or by official order, acting on behalf of the authorities concerned. Our drilling units are certified as being “in class” by the American Bureau of Shipping, or ABS, Det Norske Veritas and Germanisher Lloyd, or DNV GL, and the relevant national authorities in the countries in which our drilling units operate. If any drilling unit loses its flag status, does not maintain its class and/or fails any periodical survey or special survey, the drilling unit will be unable to carry on operations and will be unemployable and uninsurable. Any such inability to carry on operations or be employed could have a material adverse impact on the results of operations. Please see “Item 8. Financial Information-Legal Proceedings-Seabras Sapura joint venture” for more information.
The international nature of our operations involves additional risks including foreign government intervention in relevant markets, for example in Brazil.
We operate in various regions throughout the world. As a result of our international operations, we may be exposed to political and other uncertainties, particularly in less developed jurisdictions, including risks of:
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terrorist acts, armed hostilities, war and civil disturbances;
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acts of piracy, which have historically affected ocean-going vessels;
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significant governmental influence over many aspects of local economies;
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the seizure, nationalization or expropriation of property or equipment;
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uncertainty of outcome in foreign court proceedings;
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the repudiation, nullification, modification or renegotiation of contracts;
•
limitations on insurance coverage, such as war risk coverage, in certain areas;
•
political unrest;
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foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;
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the inability to repatriate income or capital;
•
complications associated with repairing and replacing equipment in remote locations;
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import-export quotas, wage and price controls, and the imposition of trade barriers;
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U.S. and foreign sanctions or trade embargoes;
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compliance with various jurisdictional regulatory or financial requirements;
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compliance with and changes to taxation;
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other forms of government regulation and economic conditions that are beyond our control; and
•
government corruption.

In addition, international contract drilling operations are subject to various laws and regulations of the countries in which we operate, including laws and regulations relating to:
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the equipping and operation of drilling units;
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exchange rates or exchange controls;
•
the repatriation of foreign earnings;
•
oil and gas exploration and development;
•
the taxation of offshore earnings and the earnings of expatriate personnel; and
•
the use and compensation of local employees and suppliers by foreign contractors.

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Some foreign governments favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling rigs owned by their own citizens, (ii) the use of a local agent or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what government regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, the denial of export privileges, injunctions or seizures of assets.
In the years ended December 31, 2018 , 2017 and 2016 , 22% , 17% and 15% , respectively, of our contract revenues were derived from our Brazilian operations. The Brazilian government frequently intervenes in the Brazilian economy and occasionally makes significant changes in policy and regulations. The Brazilian government’s actions to control inflation and other policies and regulations have often involved, among other measures, increases in interest rates, changes in tax policies, changes in legislation price controls, currency devaluations, capital controls and limits on imports. Further changes to monetary policy, the regulatory environment of our industry, and legislation could impact our performance.
The Brazilian markets are experiencing heightened volatility due to the uncertainties derived from the ongoing Lava Jato investigation being conducted by the Office of the Brazilian Federal Prosecutor, and its impact on the Brazilian economy and political environment. Certain of these companies are also facing investigations by the Brazilian Securities Commission (Comissão de Valores Mobiliários). Members of the Brazilian federal government and of the legislative branch, as well as senior officers of large state-owned companies, have faced allegations of political corruption, since they have allegedly accepted bribes by means of kickbacks on contracts granted by the government to several infrastructure, oil and gas, and construction companies. The profits of these kickbacks allegedly financed the political campaigns of political parties of the current federal government coalition that were unaccounted for or not publicly disclosed and served to personally enrich the recipients of the bribery scheme. Individuals who have had commercial arrangements with us have been identified in the Lava Jato investigation and the investigations by the Brazilian authorities are ongoing. The potential outcome of these investigations is uncertain, but they have already had an adverse impact on the image and reputation of the implicated companies, and on the general market perception of the Brazilian economy. We cannot predict whether such allegations will lead to further political and economic instability or whether new allegations against government officials will arise in the future. In addition, we cannot predict the outcome of any such allegations on the Brazilian economy, and the Lava Jato investigation could adversely affect our business and operations. Also, on October 28, 2018, the presidential elections were held in Brazil, with the conservative candidate Jair Bolsonaro as the winner. President Bolsonaro assumed office on January 1, 2019. We cannot predict the impact on the global economy of the policies of the Bolsonaro administration and, consequently, the results of our business, financial condition and the results of our operations.
These and other developments in Brazil’s political conditions, economy and government policies may, directly or indirectly, adversely affect our business and results of operations.
Compliance with, and breach of, the complex laws and regulations governing international trade could be costly, expose us to liability and adversely affect our operations.
Our business in the offshore drilling industry is affected by laws and regulations relating to the energy industry and the environment in the geographic areas where we operate.
Accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail exploration and development drilling for oil and gas. For example, on December 20, 2016, the United States President invoked a law to ban offshore oil and gas drilling in large areas of the Arctic and the Atlantic Seaboard. While the current administration has since attempted to lift the ban and open certain of those areas to oil and gas drilling, the President's legal authority to do so has been challenged and as a result it is difficult to predict if and when such areas may be made available for future exploration activities. A ban on new drilling in Canadian Arctic waters was announced simultaneously. We may be required to make significant capital expenditures or operational changes to comply with governmental laws and regulations. It is also possible that these laws and regulations may, in the future, add significantly to our operating costs or significantly limit drilling activity.
Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from the failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, the seizure of shipments, and the loss of import and export privileges.
Offshore drilling in certain areas, including arctic areas, has been curtailed and, in certain cases, prohibited because of concerns over protecting the environment.

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New laws or other governmental actions that prohibit or restrict offshore drilling or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or to the offshore drilling industry, in particular, could adversely affect our performance.
The amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and production of oil and gas could have a material adverse effect on our business, results of operations or financial condition. Future earnings may be negatively affected by compliance with any such new legislation or regulations.
We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to numerous international, national, state and local laws and regulations, treaties and conventions in force in international waters and the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. These requirements include, but are not limited to the United Nation’s International Maritime Organization ( "IMO" ), the International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended, or MARPOL, including the designation of Emission Control Areas, or ECAs thereunder, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended, or the CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or the Bunker Convention, the International Convention for the Safety of Life at Sea of 1974, as from time to time amended, or SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or the ISM Code, the IMO International Convention on Load Lines in 1966, as from time to time amended, the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004 or the BWM Convention, the U.S. Oil Pollution Act of 1990, or the OPA, requirements of the U.S. Coast Guard, or the USCG, the U.S. Environmental Protection Agency, or the EPA, the U.S. Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Maritime Transportation Security Act of 2002, or the MTSA, the U.S. Outer Continental Shelf Lands Act, certain regulations of the European Union, and Brazil’s National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Federal Law (9966/2000) relating to pollution in Brazilian waters. Compliance with such laws, regulations and standards, where applicable, may require installation of costly equipment or implementation of operational changes and may affect the resale value or useful lifetime of our drilling units. These costs could have a material adverse effect on our business, results of operations, cash flows and financial condition. A failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations. Because such conventions, laws, and regulations are often revised, we cannot predict the ultimate cost of complying with them or the impact thereof on the resale prices or useful lives of our rigs. Additional conventions, laws and regulations may be adopted which could limit our ability to do business or increase the cost of our doing business and which may materially adversely affect our operations.
In addition, environmental laws often impose strict liability for the remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Under OPA, for example, owners, operators and bareboat charterers are jointly and severally strictly liable for the discharge of oil within the 200-mile exclusive economic zone around the United States. An oil or chemical spill, for which we are deemed a responsible party, could result in us incurring significant liability, including fines, penalties, criminal liability and remediation costs for natural resource damages under other federal, state and local laws, as well as third-party damages, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, the 2010 explosion of the Deepwater Horizon well and the subsequent release of oil into the Gulf of Mexico, or other similar events, may result in further regulation of the shipping industry, and modifications to statutory liability schemes, thus exposing us to further potential financial risk in the event of any such oil or chemical spill.
We and, in certain circumstances, our customers are required by various governmental and quasi-governmental agencies to obtain certain permits, licenses and certificates with respect to our operations, and satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents. Although we have arranged insurance to cover certain environmental risks, such insurance is subject to exclusions and other limits, and there can be no assurance that such insurance will be sufficient to cover all such risks or that any claims will not have a material adverse effect on our business, results of operations, cash flows and financial condition.
Although our drilling units are separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under OPA or other environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.
Our drilling units could cause the release of oil or hazardous substances. Any releases may be large in quantity, above our permitted limits or occur in protected or sensitive areas where public interest groups or governmental authorities have special interests. Any releases of oil or hazardous substances could result in fines and other costs to us, such as costs to upgrade our drilling rigs, clean up the releases and comply with more stringent requirements in our discharge permits, as well as subject us to third party claims for damages, including natural resource damages. Moreover, these releases may result in our customers or governmental authorities suspending or terminating our operations in the affected area, which could have a material adverse effect on our business, results of operations and financial condition.
If we are able to obtain from our customers some degree of contractual indemnification against pollution and environmental damages in our contracts, such indemnification may not be enforceable in all instances or the customer may not be financially able to comply with its indemnity obligations in all cases, and we may not be able to obtain such indemnification agreements in the future. In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable.
The insurance coverage we currently hold may not be available in the future, or we may not obtain certain insurance coverage. Even if insurance is available and we have obtained the coverage, it may not be adequate to cover our liabilities, or our insurance underwriters may be unable to pay compensation if a significant claim should occur. Any of these scenarios could have a material adverse effect on our business, results of operations and financial condition.

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Failure to comply with international anti-corruption legislation, including the U.S. Foreign Corrupt Practices Act 1977 or the U.K. Bribery Act 2010, could result in fines, criminal penalties, damage to our reputation and drilling contract terminations.
We currently operate, and historically have operated, our drilling units in a number of countries throughout the world, including some with developing economies. We interact with government regulators, licensors, port authorities and other government entities and officials. Also, our business interaction with national oil companies as well as state or government-owned shipbuilding enterprises and financing agencies puts us in contact with persons who may be considered to be “foreign officials” under the U.S. Foreign Corrupt Practices Act of 1977 or the FCPA and the Bribery Act 2010 of the United Kingdom or the U.K. Bribery Act.
In order to effectively compete in some foreign jurisdictions, we utilize local agents and/or establish entities with local operators or strategic partners. All of these activities may involve interaction by our agents with government officials. Even though some of our agents and partners may not themselves be subject to the FCPA, the U.K. Bribery Act or other anti-bribery laws to which we may be subject, if our agents or partners make improper payments to government officials or other persons in connection with engagements or partnerships with us, we could be investigated and potentially found liable for violations of such anti-bribery laws and could incur civil and criminal penalties and other sanctions, which could have a material adverse effect on our business and results of operation.
We are subject to the risk that we or our affiliated companies or their respective officers, directors, employees and agents may take actions determined to be in violation of anti-corruption laws, including the FCPA and the U.K. Bribery Act. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations in certain jurisdictions, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business.
If our drilling units are located in countries that are subject to, or targeted by, economic sanctions, export restrictions, or other operating restrictions imposed by the United States or other governments, our reputation and the market for our debt and common shares could be adversely affected.
The U.S. and other governments may impose economic sanctions against certain countries, persons and other entities that restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions in particular are targeted against countries (such as Russia, Venezuela, Iran and others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities. U.S. and other economic sanctions change frequently and enforcement of economic sanctions worldwide is increasing.
In 2010, the United States enacted the Comprehensive Iran Sanctions Accountability and Divestment Act, or CISADA, which expanded the scope of the former Iran Sanctions Act. Among other things, CISADA expands the application of the prohibitions to non-U.S. companies such as ours and introduced limits on the ability of companies and persons to do business or trade with Iran when such activities relate to the investment, supply or export of refined petroleum or petroleum products. On August 10, 2012, the U.S. signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012, or the Iran Threat Reduction Act, which places further restrictions on the ability of non-U.S. companies to do business or trade with Iran and Syria. Perhaps the most significant provision in the Iran Threat Reduction Act is that prohibitions in the existing Iran sanctions applicable to U.S. persons will now apply to any foreign entity owned or controlled by a U.S. person. The other major provision in the Iran Threat Reduction Act is that issuers of securities must disclose in their annual and quarterly reports filed with the Commission after February 6, 2013 if the issuer or “any affiliate” has “knowingly” engaged in certain activities involving Iran during the timeframe covered by the report. At this time, we are not aware of any activities conducted by us or by any affiliate, which is likely to trigger such a disclosure requirement. On January 2, 2013, the U.S. signed into law the Iran Freedom and Counter-Proliferation Act of 2012 ( “IFCA” ), as a part of the National Defense Authorization Act for Fiscal Year 2013. Among other measures, IFCA authorizes broad sanctions on certain activities related to Iran’s energy, shipping, and shipbuilding sectors.
On July 14, 2015, the P5+1 and the European Union announced that they reached a landmark agreement with Iran titled the Joint Comprehensive Plan of Action Regarding the Islamic Republic of Iran’s Nuclear Program, or the JCPOA, to significantly restrict Iran’s ability to develop and produce nuclear weapons for 10 years while simultaneously easing sanctions directed toward non-U.S. persons for conduct involving Iran, but taking place outside of U.S. jurisdiction and not involving U.S. persons. On January 16, 2016, or the Implementation Day, the United States joined the European Union and the U.N. in lifting a significant number of their nuclear-related sanctions on Iran following an announcement by the International Atomic Energy Agency, or the IAEA, that Iran had satisfied its respective obligations under the JCPOA.
On May 8, 2018, the U.S. announced that it would be withdrawing from the JCPOA. On August 6, 2018, the U.S. issued Executive Order 13846 which reimposed certain sanctions on Iran effective as of that date and set the reimposition of additional sanctions on Iran effective November 5, 2018. On November 5, 2018, following a wind-down period, the U.S. completed the reimposition of nuclear-related sanctions against Iran that it had previously lifted in connection with the JCPOA.

The Office of Foreign Assets Control ( "OFAC" ) acted several times over the past year to add Iranian individuals and entities to its list of Specially Designated Nationals whose assets are blocked and with whom U.S. persons are generally prohibited from dealing, including re-adding on November 5, 2018, hundreds of individuals and entities that had previously been delisted in connection with the JCPOA.

In August 2017, the U.S. passed the “Countering America’s Adversaries Through Sanctions Act” (Public Law 115-44) ( "CAATSA "), which authorizes imposition of new sanctions on Iran, Russia, and North Korea. The CAATSA sanctions with respect to Russia create heightened sanctions risks for companies operating in the oil and gas sector, including companies that are based outside of the United States. OFAC sanctions targeting Venezuela have likewise increased in the past year, and any new sanctions targeting Venezuela could further restrict our ability to do business in such country. On January 28, 2019, OFAC added the Venezuelan state-owned oil company, Petróleos de Venezuela, S.A. (“PdVSA”), to its List of Specially Designated Nationals and Blocked Persons, increasing the sanctions risk for companies operating in the oil sector.


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In addition to the sanctions against Iran, Russia, and Venezuela, subject to certain limited exceptions, U.S. law continues to restrict U.S. owned or controlled entities from doing business with Cuba and various U.S. sanctions have certain other extraterritorial effects that need to be considered by non-U.S. companies. Moreover, any U.S. persons who serve as officers, directors or employees of our subsidiaries would be fully subject to U.S. sanctions. It should also be noted that other governments are more frequently implementing and enforcing sanctions regimes.

From time to time, we may enter into drilling contracts with countries or government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism where entering into such contracts would not violate U.S. law, or may enter into drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S government and/or identified by the U.S. government as state sponsors of terrorism. However, this could negatively affect our ability to obtain investors. In some cases, U.S. investors would be prohibited from investing in an arrangement in which the proceeds could directly or indirectly be transferred to or may benefit a sanctioned entity. Moreover, even in cases where the investment would not violate U.S. law, potential investors could view such drilling contracts negatively, which could adversely affect our reputation and the market for our shares. We do not currently have any drilling contracts or plans to initiate any drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism.
Certain parties with whom we have entered into contracts may be or may be affiliated with persons or entities that are, the subject of sanctions imposed by the United States, the European Union or other international bodies as a result of the annexation of Crimea by Russia in March 2014 and the subsequent conflict in eastern Ukraine, or malicious cyber-enabled activities. If we determine that such sanctions require us to terminate existing contracts or if we are found to be in violation of such applicable sanctions, our results of operations may be adversely affected, or we may suffer reputational harm. Such sanctions may prevent us from performing some or all of our obligations under any potential drilling contracts with Rosneft, which could impact our future revenue, contract backlog and results of operations, and adversely affect our business reputation. We may also lose business opportunities to companies that are not required to comply with these sanctions.
As stated above, we believe that we are in compliance with all applicable economic sanctions and embargo laws and regulations and intend to maintain such compliance. However, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Rapid changes in the scope of global sanctions may also make it more difficult for us to remain in compliance. Any violation of applicable economic sanctions could result in civil or criminal penalties, fines, enforcement actions, legal costs, reputational damage, or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in our shares. Additionally, some investors may decide to divest their interest, or not to invest, in our shares simply because we may do business with companies that do business in sanctioned countries. Moreover, our drilling contracts may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, or our drilling rigs, and those violations could in turn negatively affect our reputation. Investor perception of the value of our shares may also be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.
An economic downturn could have a material adverse effect on our revenue, profitability and financial position.
We depend on our customers’ willingness and ability to fund operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. There has historically been a strong link between the development of the world economy and the demand for energy, including oil and gas. The world economy is currently facing a number of challenges. Concerns persist regarding the debt burden of certain European countries and their ability to meet future financial obligations and the overall stability of the euro. A renewed period of adverse development in the outlook for the financial stability of European countries, or market perceptions concerning these and related issues, could reduce the overall demand for oil and natural gas and for our services and thereby could affect our financial position, results of operations and cash available for distribution. In addition, turmoil and hostilities in the Ukraine, Korea, the Middle East, North Africa and other geographic areas and countries are adding to the overall risk picture.
Negative developments in worldwide financial and economic conditions could further cause our ability to access the capital markets to be severely restricted at a time when we would like, or need, to access such markets, which could impact our ability to react to changing economic and business conditions. Worldwide economic conditions have in the past impacted, and could in the future impact, lenders willingness to provide credit facilities to our customers, causing them to fail to meet their obligations to us.
A portion of the credit under our credit facilities is provided by European banking institutions. If economic conditions in Europe preclude or limit financing from these banking institutions, we may not be able to obtain financing from other institutions on terms that are acceptable to us, or at all, even if conditions outside Europe remain favorable for lending.
An extended period of adverse development in the outlook for the world economy could also reduce the overall demand for oil and gas and for our services. Such changes could adversely affect our results of operations and cash flows beyond what might be offset by the simultaneous impact of possibly higher oil and gas prices.
Our business is capital intensive and, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to fund our capital expenditures. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations or interpretations thereof and by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.
Any reductions in drilling activity by our customers may not be uniform across different geographic regions. Locations where costs of drilling and production are relatively higher, such as Arctic or deepwater locations, may be subject to greater reductions in activity. Such reductions in high cost regions may lead to the relocation of drilling units, concentrating drilling units in regions with relatively fewer reductions in activity leading to greater competition.

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If our lenders are not confident that we are able to employ our assets, we may be unable to secure additional financing when required.
We have, and may continue, to suffer losses through our investments in other companies in the offshore drilling and oilfield services industry, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We currently hold investments in several other companies in our industry that own/operate offshore drilling rigs with similar characteristics to our fleet of rigs or deliver various other oilfield services. These investments include equity interests in Seadrill Partners, SeaMex, Archer and Seabras Sapura.
The market value of our equity interest in these companies has been, and may continue to be, volatile and has fluctuated, and may continue to fluctuate, in response to changes in oil and gas prices and activity levels in the offshore oil and gas industry. If we sell our equity interest in an investment at a time when the value of such investment has fallen, we may incur a loss on the sale or an impairment loss being recognized, ultimately leading to a reduction in earnings. Furthermore, dividends from Seadrill Partners may be reduced or cancelled going forward as they have been in the past. In current market conditions, we may consider entering into joint venture arrangements where each joint venture partner bareboats their rigs into the joint venture entity. Through such a structure, we would seek to manage and operate all joint venture rigs and enable the Group to access additional markets, increase presence in a particular market or secure drilling contracts from counterparties who may only be willing to grant those drilling contracts pursuant to or as part of implementing a joint venture with us. However, any financial return from drilling contracts entered into in respect of our rig will be diluted to the shareholding percentage we hold in the joint venture entity and financial success of the joint venture will depend on the management fee rates we are able to agree with our joint venture partner.
During the years ended December 31, 2017 and 2016 we recognized charges of $841 million and $895 million respectively relating to certain of our investments due to declining dayrates and future market expectations for dayrates in the sector. Please see Note 11 - Impairment loss on marketable securities and investments in associated companies to our Consolidated Financial Statements included herein for further information.
Our ability to operate our drilling units in the U.S. Gulf of Mexico could be impaired by governmental regulation, particularly in the aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico, and new regulations adopted as a result of the investigation into the Macondo well blowout.
In the aftermath of the Deepwater Horizon Incident (in which we were not involved), various governmental agencies, including the U.S Department of the Interior, U.S. Bureau of Safety and Environmental Enforcement, or the BSEE and its predecessor, the U.S Bureau of Ocean Energy Management or BOEM, and the U.S. Occupational Safety and Health Administration, issued new and revised regulations and guidelines governing safety and environmental management, occupational injuries and illnesses, financial assurance requirements, inspection programs and other well control measure relating to our drilling rigs.
In order to obtain drilling permits, operators must submit applications that demonstrate compliance with the enhanced regulations, which require independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. Operators have previously had, and may in the future have, difficulties obtaining drilling permits in the U.S. Gulf of Mexico.
In addition, the oil and gas industry has adopted new equipment and operating standards, such as the American Petroleum Institute Standard 53 relating to the design, maintenance, installation and testing of well control equipment. Current and pending regulations, guidelines and standards for safety, environmental and financial assurance such as the above and any other new guidelines or standards the U.S. government or industry may issue (including relating to the Deepwater Horizon Incident or the other catastrophic events involving pollution from oil exploration and development activities) or any other steps the U.S. government or industry may take relating to our business activities, could disrupt or delay operations, increase the cost of operations, increase out-of-service time or reduce the area of operations for drilling rigs in U.S. and non-U.S. offshore areas.
As new standards and procedures are being integrated into the existing framework of offshore regulatory programs, there may be increased costs associated with regulatory compliance and delays in obtaining permits for other operations such as re-completions, workovers and abandonment activities.
We are not able to predict the likelihood, nature or extent of additional rulemaking or when the interim rules, or any future rules, could become final. The current and future regulatory environment in the U.S. Gulf of Mexico could impact the demand for drilling units in the U.S. Gulf of Mexico in terms of overall number of rigs in operations and the technical specification required for offshore rigs to operate in the U.S. Gulf of Mexico. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and escalating costs borne by our customers, along with permitting delays, could reduce exploration and development activity in the U.S. Gulf of Mexico and, therefore, reduce demand for our services. In addition, insurance costs across the industry have increased as a result of the Deepwater Horizon Incident and, in the future, certain insurance coverage is likely to become more costly, and may become less available or not available at all. We cannot predict the potential impact of new regulations that may be forthcoming, nor can we predict if implementation of additional regulations might subject us to increased costs of operating and/or a reduction in the area of operation in the U.S. Gulf of Mexico. As such, our cash flow and financial position could be adversely affected if our ultra-deepwater semi-submersible drilling rigs and ultra-deepwater drillships operating in the U.S. Gulf of Mexico were subject to the risks mentioned above.
In addition, hurricanes have from time to time caused damage to a number of drilling units and production facilities unaffiliated to us in the Gulf of Mexico. The BOEM and the BSEE, have in recent years issued more stringent guidelines for tie-downs on drilling units and permanent equipment and facilities attached to outer continental shelf production platforms, moored drilling unit fitness, as well as other guidelines and regulations in an attempt to increase the likelihood of the survival of offshore drilling units during a hurricane. Implementation of new guidelines or regulations that may apply to our drilling units may subject us to increased costs and limit the operational capabilities of our drilling units.

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Failure to obtain or retain highly skilled personnel, and to ensure they have the correct visas and permits to work in the locations in which they are required, could adversely affect our operations.
We require highly skilled personnel in the right locations to operate and provide technical services and support for our business.
Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of rigs activated or added to worldwide fleets has increased, and this may continue to rise. Notwithstanding the general downturn in the drilling industry, in some regions, such as Brazil and Western Africa, the limited availability of qualified personnel in combination with local regulations focusing on crew composition, are expected to further increase the demand for qualified offshore drilling crews, which may increase our costs. These factors could further create and intensify upward pressure on wages and make it more difficult for us to staff and service our rigs. Such developments could adversely affect our financial results and cash flow. Furthermore, as a result of any increased competition for qualified personnel, or as a result of our Chapter 11 Proceedings, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents.
Our ability to operate worldwide, depends on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we operate. Governmental actions in some of the jurisdictions in which we operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits. If we are not able to obtain visas and work permits for the employees we need for operating our rigs on a timely basis, or for third-party technicians needed for maintenance or repairs, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel the contracts. Please see “-Our customers may seek to cancel or renegotiate their contracts to include unfavorable terms such as unprofitable rates, particularly in the circumstance that operations are suspended or interrupted."
Labor costs and our operating restrictions that apply could increase following collective bargaining negotiations and changes in labor laws and regulations.
Some of our employees are represented by collective bargaining agreements. The majority of these employees work in Brazil, Mexico, Nigeria, Norway and the United Kingdom. In addition, some of our contracted labor works under collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and are restricted in our ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance.
Interest rate fluctuations could affect our earnings and cash flow.
In order to finance our growth, we have incurred significant amounts of debt. The majority of our debt arrangements have floating interest rates. As such, following our emergence from Chapter 11 Proceedings, significant movements in interest rates could have an adverse effect on our earnings and cash flow. We had previously managed our exposure to interest rate fluctuations through interest rate swaps that effectively fixed a part of our floating rate debt obligations. These swaps were terminated on September 13, 2017 as a result of entering Chapter 11. However, on May 11, 2018 we entered into an agreement to hedge part of our interest rate risk. Please see "ITEM 11 - Quantitative and qualitative disclosures about market risk" for further details of our use of derivatives to mitigate exposures to interest rate risk.
If we are unable to effectively manage our interest rate exposure through interest rate derivatives in the future, any increase in market interest rates would increase our interest rate exposure and debt service obligations, which would exacerbate the risks associated with our leveraged capital structure.
In addition, the United Kingdom Financial Conduct Authority (the “FCA”), which regulates LIBOR, has announced that it intends to stop persuading or compelling banks to submit rates for the calculation of LIBOR to the administrator of LIBOR after 2021 (the “FCA Announcement”). The FCA Announcement indicates that the continuation of LIBOR on the current basis is not guaranteed after 2021. Significant increases in LIBOR or uncertainty surrounding its phase out after 2021 could adversely affect our business, financial condition and results of operations.

Fluctuations in exchange rates and the non-convertibility of currencies could result in losses to us.
As a result of our international operations, we are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. dollars. Accordingly, we may experience currency exchange losses if we have not adequately hedged our exposure to a foreign currency, or if revenues are received in currencies that are not readily convertible. We may also be unable to collect revenues because of a shortage of convertible currency available in the country of operation, controls over currency exchange or controls over the repatriation of income or capital.
We use the U.S. dollar as our functional currency because the majority of our revenues and expenses are denominated in U.S. dollars. Accordingly, our reporting currency is also U.S. dollars. We do, however, earn revenues and incur expenses in other currencies, such as Norwegian kroner, U.K. pounds sterling, Brazilian real, Nigerian naira, and Angolan kwanza and there is a risk that currency fluctuations could have an adverse effect on our statements of operations and cash flows.
Brexit, or similar events in other jurisdictions, can impact global markets, which may have an adverse impact on our business and operations as a result of changes in currency, exchange rates, tariffs, treaties and other regulatory matters.
A change in tax laws in any country in which we operate could result in higher tax expense.

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We conduct our operations through various subsidiaries in countries throughout the world. Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, regulations and treaties in and between the countries in which we operate, including treaties between the United States and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, regulations or treaties, including those in and involving the United States, or in the interpretation thereof, or in the valuation of our deferred tax assets, which is beyond our control, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings.
In addition, the United States in December 2017 enacted major tax reform legislation.  This is likely to continue to have a material impact on the amount of overall U.S. tax expense of the Group due to reduced effective tax deductions for certain payments our U.S. operating companies make to non-U.S. rig owners and other group and affiliated companies.
A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.
Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.
A change in laws and regulations in any country in which we operate could have a negative impact on our business
During 2017, the European Union Economic and Financial Affairs Council released a list of non-cooperative jurisdictions for tax purposes. The stated aim of the list, and accompanying report, was to promote good governance worldwide in order to maximize efforts to prevent tax fraud and tax evasion. Bermuda was not on the list of non-cooperative jurisdictions, but did feature in the report as having committed to address concerns relating to economic substance by December 31, 2018. In accordance with that commitment, Bermuda enacted the Economic Substance Act 2018 (the “ESA”) in December 2018. The ESA requires each registered entity to maintain a substantial economic presence in Bermuda and provides that a registered entity that carries on a relevant activity complies with economic substance requirements if (i) it is directed and managed in Bermuda, (ii) its core income-generating activities (as may be further prescribed) are undertaken in Bermuda with respect to the relevant activity, (iii) it maintains adequate physical presence in Bermuda, (iv) it has adequate full time employees in Bermuda with suitable qualifications and (v) it incurs adequate operating expenditure in Bermuda in relation to the relevant activity. A registered entity that carries on a relevant activity is obliged under the ESA to file a declaration with the Bermuda Registrar of Companies on an annual basis containing certain information. At present, the impact of the ESA is unclear and it is impossible to predict the nature and effect of these requirements on the Company and its subsidiaries incorporated in Bermuda. We are currently evaluating the potential effect ESA will have on the Company and its Bermuda subsidiaries.
Climate change and the regulation of greenhouse gases could have a negative impact on our business.
Due to concern over the risk of climate change, a number of countries, the European Union and the IMO have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions in the shipping industry. For example, ships (including rigs and drillships) must comply with IMO and European Union regulations relating to the collection and reporting of data relating to greenhouse gas emissions. In April 2018, the IMO adopted a strategy to, among other things, reduce the 2008 level of greenhouse gas emissions from the shipping industry by 50% by the year 2050.
Other governmental bodies, such as the United States Environmental Protection Agency and the State of California also may regulate greenhouse gas emissions from shipping in the future. The future of such regulations is difficult to predict because the requirements continue to evolve.
Compliance with existing regulations and changes in laws, regulations and obligations relating to climate change could increase our costs to operate and maintain our assets, and might also require us to install new emission controls, acquire allowances or pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. Any passage of climate control legislation or other regulatory initiatives by the IMO, the European Union, the United States or other countries in which we operate, or any treaty adopted at the international level to succeed the Kyoto Protocol, which restricts emissions of greenhouse gases, could require us to make significant financial expenditures which we cannot predict with certainty at this time.
Additionally, adverse effects upon the oil and gas industry relating to climate change, including growing public concern about the environmental impact of climate change, may also adversely affect demand for our services. For example, increased regulation of greenhouse gases or other concerns relating to climate change may reduce the demand for oil and gas in the future or create greater incentives for the use of alternative energy sources. Any material adverse effect on the oil and gas industry relating to climate change concerns could have a significant adverse financial and operational impact on our business and operations.
Finally, the impacts of severe weather, such as hurricanes, monsoons and other catastrophic storms, resulting from climate change could cause damage to our equipment and disruption to our operations and cause other financial and operational impacts, including impacts on our major customers.


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Acts of terrorism, piracy, cyber-attack, political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
Acts of terrorism, piracy, and political and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. Our drilling operations could also be targeted by acts of sabotage carried out by environmental activist groups.
We rely on information technology systems and networks in our operations and administration of our business. Our drilling operations or other business operations could be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt our operations, including the safety of our operations, or lead to an unauthorized release of information or alteration of information on our systems. Any such attack or other breach of our information technology systems could have a material adverse effect on our business and results of operations.
In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services and result in lower dayrates. Insurance premiums could also increase and coverage may be unavailable in the future. Increased insurance costs or increased costs of compliance with applicable regulations may have a material adverse effect on our results of operations.
We may be subject to litigation, arbitration, other proceedings and regulatory investigations that could have an adverse effect on us.
We are currently involved in various litigation and arbitration matters, and we anticipate that we will be involved in dispute matters from time to time in the future. The operating and other hazards inherent in our business expose us to disputes, including personal injury disputes, environmental and climate change litigation, contractual disputes with customers, intellectual property and patent disputes, tax or securities disputes, regulatory investigations and maritime lawsuits, including the possible arrest of our drilling units. We cannot predict, with certainty, the outcome or effect of any claim or other dispute matters, or a combination of these. If we are involved in any future disputes, or if our positions concerning current disputes are found to be incorrect, there may be an adverse effect on our business, financial position, results of operations and available cash, because of potential negative outcomes, the costs associated with asserting our claims or defending such lawsuits or proceedings, and the diversion of management’s attention to these matters.
We may also be subject to significant legal costs in defending these actions, which we may or may not be able to recoup depending on the results of such claim. For additional information on litigation matters that we are currently involved in, please see “ITEM 8. Financial Information-A. Consolidated Statements and Other Financial Information-Legal Proceedings.”
We cannot guarantee that the use of our drilling units will not infringe the intellectual property rights of others.
The majority of the intellectual property rights relating to our drilling units and related equipment are owned by our suppliers. In the event that one of our suppliers becomes involved in a dispute over an infringement of intellectual property rights relating to equipment owned by us, we may lose access to repair services or replacement parts or could be required to cease using some equipment. In addition, our competitors may assert claims for infringement of intellectual property rights related to certain equipment on our drilling units and we may be required to stop using such equipment and/or pay damages and royalties for the use of such equipment. The consequences of these technology disputes involving our suppliers or competitors could adversely affect our financial results and operations. We have indemnity provisions in some of our supply contracts to give us some protection from the supplier against intellectual property lawsuits. However, we cannot make any assurances that these suppliers will have sufficient financial standing to honor their indemnity obligations or guarantee that the indemnities will fully protect us from the adverse consequences of such technology disputes. We also have provisions in some of our client contracts to require the client to share some of these risks on a limited basis, but we cannot provide assurance that these provisions will fully protect us from the adverse consequences of such technology disputes. For information on certain intellectual property litigation that we are currently involved in, please see “ITEM 8. Financial Information - A. Consolidated Statements and Other Financial Information - Legal Proceedings.”
We depend on directors who are associated with affiliated companies, which may create conflicts of interest.
Our largest shareholder is Hemen Holding Limited, or Hemen. Many of our directors also serve as directors of other companies affiliated with Hemen. Our directors owe fiduciary duties to both us and other related parties and may have conflicts of interest in matters involving or affecting us and our customers. Please see “ITEM 6. Directors, Senior management and Employees - C. Board Practices” for more information.
We have agreed to market certain of the rigs of our affiliated entity, Northern Drilling Limited (“NODL”), which may create conflicts of
interest.

We have executed an agreement with NODL for the commercial management of certain of the rigs acquired by our affiliated entity, NODL. To date, we have entered into drilling contracts in respect of certain NODL units directly with customers with back-to-back arrangements in place between us and NODL to allocate risk and liability back to NODL commensurate with the structure. Ultimately, we are exposed to the creditworthiness of NODL, to the extent that we have an exposure to the customer under the drilling contract and seek recovery under the back-to-back arrangements. We earn an incentivized management fee from NODL that is intended to reward us for the services we provide and the risks that we are exposed to as well as providing a right of first refusal for purchase of the unit. We currently have stacked rigs that were available but not competitive from a technical or cost perspective with the NODL units that secured drilling contracts through us.

We may be restricted from granting long-term contracts as a result of the Omnibus Agreement with Seadrill Partners.
We have entered into an omnibus agreement with Seadrill Partners, or the Omnibus Agreement, in connection with its initial public offering, which may restrict our ability to, among other things, acquire, own, operate or contract for certain drilling units operating under drilling contracts

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of five or more years, unless we offer to sell such drilling units to Seadrill Partners. These restrictions could harm our business and adversely affect our financial position and results of operations and ability to implement our growth strategy. For additional information, please see “ITEM 7. Major Shareholders and Related Party Transactions - B. Related Party Transactions-Seadrill Partners-Omnibus Agreement with Seadrill Partners.”
If we fail to comply with requirements relating to internal control over financial reporting our business could be harmed and our common stock price could decline.
Rules adopted by the Securities and Exchange Commission pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 require that we assess our internal control over financial reporting annually. The rules governing the standards that must be met for management to assess its internal control over financial reporting are complex. They require significant documentation, testing, and possible remediation of any significant deficiencies in and / or material weaknesses of internal controls in order to meet the detailed standards under these rules. Although we have evaluated our internal control over financial reporting as effective as of December 31, 2018 , in future fiscal years, we may encounter unanticipated delays or problems in assessing our internal control over financial reporting as effective or in completing our assessments by the required dates. In addition, we cannot assure you that our independent registered public accountants will attest that internal control over financial reporting is effective in future fiscal years.
If we are unable to maintain effective internal controls over financial reporting and disclosure controls, investors may lose confidence in our reported financial information, which could lead to a decline in the price of common shares, limit our ability to access the capital markets in the future, and require us to incur additional costs to improve our internal control over financial reporting and disclosure control systems and procedures. Further, if lenders lose confidence in the reliability of our financial statements, it could have a material adverse effect on our ability to fund our operations.
Public health threats could have an adverse effect on our operations and financial results.
Public health threats, such as Ebola, influenza, SARS, the Zika virus, and other highly communicable diseases or viruses, outbreaks of which have from time to time occurred in various parts of the world in which we operate, could adversely impact our operations, and the operations of our customers. In addition, public health threats in any area, including areas where we do not operate, could disrupt international transportation. Our crews generally work on a rotation basis, with a substantial portion relying on international air transport for rotation. Any such disruptions could impact the cost of rotating our crews, and possibly impact our ability to maintain a full crew on all rigs at a given time. Any of these public health threats and related consequences could adversely affect our financial results.
Data protection and regulations related to privacy, data protection and information security could increase our costs, and our failure to comply could result in fines, sanctions or other penalties, which could materially and adversely affect our results of operations, as well as have an impact on our reputation.
We are subject to regulations related to privacy, data protection and information security in the jurisdictions in which we do business. As privacy, data protection and information security laws are interpreted and applied, compliance costs may increase, particularly in the context of ensuring that adequate data protection and data transfer mechanisms are in place.
In recent years, there has been increasing regulatory enforcement and litigation activity in the areas of privacy, data protection and information security in the U.S. and in various countries in which we operate. In addition, legislators and/or regulators in the U.S., the European Union and other jurisdictions in which we operate are increasingly adopting or revising privacy, data protection and information security laws that could create compliance uncertainty and could increase our costs or require us to change our business practices in a manner adverse to our business. For example, the European Union and U.S. Privacy Shield framework was designed to serve as an appropriate safeguard in relation to international transfers of personal data from the EEA to the U.S. However, this self-certification faces a number of legal challenges and is subject to annual review. This has resulted in some uncertainty and obligations to look at other appropriate safeguards to protect the security and confidentiality of personal data in the context of cross-border data transfers. Moreover, compliance with current or future privacy, data protection and information security laws could significantly impact our current and planned privacy, data protection and information security related practices, our collection, use, sharing, retention and safeguarding of consumer and/or employee information, and some of our current or planned business activities. Our failure to comply with privacy, data protection and information security laws could result in fines, sanctions or other penalties, which could materially and adversely affect our results of operations and overall business, as well as have an impact on our reputation. For example, the General Data Protection Regulations (EU) 2016/679 (the “GDPR”), as supplemented by any national laws (such as in the U.K., the Data Protection Act 2018) and further implemented through binding guidance from the European Data Protection Board, came into effect on May 25, 2018. The GDPR expanded the scope of the EU data protection law to all foreign companies processing personal data of EEA individuals and imposed a stricter data protection compliance regime, including the introduction of administrative fines for non-compliance up to 4% of global total annual worldwide turnover or €20 million (whichever is higher), depending on the type and severity of the breach, as well as the right to compensation for financial or non-financial damages claimed by any individuals under Article 82 GDPR and the reputational damages that our business may be facing as a result of any personal data breach or violation of the GDPR.


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Risks Relating to Our Common Shareholders
 
The price of the Shares may be volatile or may decline regardless of our operating performance, and investors may not be able to resell the Shares at or above their initial purchase price.
The market price for the Shares may be volatile and may fluctuate significantly in response to a number of factors, most of which we cannot control, including, among others:
•
announcements concerning 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;
•
fluctuations in the market value of our drilling units and the amount of debt we can incur under certain covenants in its current and future debt financing agreements;
•
general and industry-specific economic conditions;
•
changes in financial estimates or recommendations by securities analysts or failure to meet analysts' performance expectations;
•
additions or departures of key members of management;
•
any increased indebtedness we incur in the future;
•
speculation or reports by the press or investment community with respect to Seadrill or the industry in general;
•
announcements by us or our competitors of significant contracts, acquisitions, dispositions, strategic partnerships, joint ventures or capital commitments;
•
changes or proposed changes in laws or regulations affecting the oil and gas industry or enforcement of these laws and regulations, or announcements relating to these matters; and
•
general market, political and economic conditions, including any such conditions and local conditions in the markets in which we operate.
These and other factors may lower the market price of the Shares, regardless of our actual operating performance. In the event of a drop in the market price of the Shares, investors could lose a substantial part or all of its investment in the Shares. In addition, the stock markets have experienced extreme price and volume fluctuations that have affected and continue to affect the market prices of equity securities of many companies. Shareholders may initiate securities class action litigation following periods of market volatility. If we were to become involved in securities litigation, we could incur substantial costs and our resources and the attention of management could be diverted from the business, which could have a negative effect on the results of operations and thus the price for the Shares.
The market price of our common shares has fluctuated widely and may fluctuate widely in the future.
The market price of our common shares has fluctuated widely and may continue to do so as a result of many factors, such as actual or anticipated fluctuations in our operating results, changes in financial estimates by securities analysts, economic and regulatory trends, general market conditions, rumors and other factors, many of which are beyond our control. Further, there may be no continuing active or liquid public market for our common shares. If an active trading market for our common shares does not continue, the price of our common shares may be more volatile and it may be more difficult and time consuming to complete a transaction in our common shares, which could have an adverse effect on the realized price of our common shares. In addition, an adverse development in the market price for our common shares could negatively affect our ability to issue new equity to fund our activities.
The issuance of share-based awards may dilute investors' holding of the Shares.
An aggregate of 11.1 million of the Shares are reserved for issuance for grant to our employees pursuant to awards under the Employee Incentive Plan in accordance with the Plan. The exercise of equity awards, including any share options that we may grant in the future, could have an adverse effect on the market for the Shares, including the price that an investor could obtain for their Shares. Investors may experience dilution in the net tangible book value of their investment upon the exercise of any share options that may be granted or issued pursuant to the employee incentive plan in the future.
Substantial sales of or trading in the Shares could occur, which could cause the share price to be adversely affected.
A limited number of holders own a substantial portion of the Shares, which may be traded on the NYSE or the Oslo Stock Exchange if such Shares are freely tradable or covered by an effective registration statement. Certain Shares became freely tradable immediately following the Debtors' emergence from Chapter 11 Proceedings and up to 76,359,119 of our common shares may be sold pursuant to a resale registration statement that we are required to maintain pursuant to a registration rights agreement with certain investors. Some of the creditors who received Shares in connection with the Plan may sell these shares for any number of reasons. We cannot predict what effect, if any, future sales of the Shares, or the availability of Shares for future sales, will have on their market price. Sales of substantial amounts of the Shares in the public market, or the perception that such sales could occur, may adversely affect the market price of the Shares, making it more difficult for holders to sell their Shares at a time and price that they deem appropriate. In addition, investment firms that are party to certain put and call agreements may hedge their positions by trading the Shares. The sale of significant amounts of the Shares, substantial trading in the Shares, hedging activities or the perception in the market that any of these activities will occur, may adversely affect the market price of the Shares. Sales of Shares could also impair our ability to raise capital, should we wish to do so, which may cause the share price to decline.
We may pay little or no dividends on the Shares.
The payment of any future dividends to the Company's shareholders will depend on decisions that will be made by the Board of Directors and will depend on then existing conditions, including the Company's operating results, financial conditions, contractual and financing restrictions,

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corporate law restrictions, capital agreements, the applicable laws of Bermuda and business prospects. The Company may pay little or no dividends for the foreseeable future.
In addition, since we are a holding company with no material assets other than the shares of our subsidiaries through which we conduct our operations, our ability to pay dividends will depend on our subsidiaries distributing to us their earnings and cash flow. We suspended the payment of dividends in November 2014, and we cannot predict when, or if, dividends will be paid in the future.
U.S. tax authorities may treat us as a “passive foreign investment company” for U.S. federal income tax purposes, which may have adverse tax consequences for U.S. shareholders.
A foreign corporation will be treated as a “passive foreign investment company” or PFIC, for U.S. federal income tax purposes if either (1) at least 75% of its gross income for any taxable year consists of certain types of “passive income” or (2) at least 50% of the average value of the corporation’s assets produce or are held for the production of those types of “passive income.” For purposes of these tests, “passive income” includes dividends, interest and gains from the sale or exchange of investment property, and rents and royalties other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. For the purposes of these tests, income derived from the performance of services does not constitute “passive income.” As discussed further below, U.S. shareholders of a PFIC are subject to certain adverse U.S. federal income tax consequences including a disadvantageous U.S. federal income tax regime with respect to distributions they receive from the PFIC and the gain, if any, they derive from the sale or other disposition of their shares in the PFIC.
Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we intend to take the position that we will not be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. Our position is based on valuations and projections regarding our assets and income. While we believe these valuations and projections to be accurate, such valuations and projections may not continue to be accurate. Moreover, the determination as to whether we are a PFIC for any taxable year is based on the application of complex U.S. federal income tax rules, which are subject to differing interpretations, and is not determinable until after the end of such taxable year. Further, we have not sought a ruling from the United States Internal Revenue Service, or IRS, on this matter, the IRS or a court could disagree with our position. In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, the nature of our operations may change in the future, and if so, we may not be able to avoid PFIC status in the future.
If the IRS were to find that we are or have been a PFIC for any taxable year, our U.S. shareholders may face adverse U.S. federal income tax consequences.  Under the PFIC rules, unless those shareholders make an election available under the United States Internal Revenue Code of 1986, as amended, or the Code (which election could itself have adverse consequences for such shareholders, as discussed below under “Item 10. Additional Information-E. Taxation”), such shareholders would be liable to pay U.S. federal income tax at the then prevailing income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of the common shares, as if the excess distribution or gain had been recognized ratably over the shareholder’s holding period of the common shares. In the event that our shareholders face adverse U.S. federal income tax consequences as a result of investing in shares of our common stock, this could adversely affect our ability to raise additional capital through the equity markets. See “ITEM 10. Additional Information - E. Taxation” for a more comprehensive discussion of the U.S. federal income tax consequences to U.S. shareholders if we are treated as a PFIC.
Investors are encouraged to consult their own tax advisers concerning the overall tax consequences of the ownership and disposition of the common shares arising in an investor’s particular situation under U.S. federal, state, local or foreign law.
Because we are a foreign corporation, you may not have the same rights that a shareholder in a U.S. corporation may have.
We are incorporated under the laws of Bermuda, and substantially all of our assets are located outside of the United States. In addition, our directors and officers generally are or will be non-residents of the United States, and all or a substantial portion of the assets of these non-residents are located outside the United States. As a result, it may be difficult or impossible for you to effect service of process on these individuals in the United States or to enforce in the United States judgments obtained in U.S. courts against us or our directors and officers based on the civil liability provisions of applicable U.S. securities laws.
In addition, you should not assume that courts in the countries in which we are incorporated or where our assets are located (1) would enforce judgments of U.S. courts obtained in actions against us based upon the civil liability provisions of applicable U.S. securities laws or (2) would enforce, in original actions, liabilities against us based on those laws.
We are permitted to adopt certain home country practices in relation to corporate governance, which may afford you less protection.

As a foreign private issuer, we are permitted to adopt certain home country practices in relation to corporate governance matters that differ significantly from the NYSE corporate governance listing standards. These practices may afford less protection to shareholders than they would enjoy if we complied fully with corporate governance listing standards.

As a foreign private issuer listed on the NYSE, we are subject to corporate governance listing standards of the NYSE. However, rules permit a foreign private issuer like us to follow the corporate governance practices of its home country. Certain corporate governance practices in Bermuda, which is our home country, may differ significantly from corporate governance listing standards. Concurrently, we comply with certain NYSE corporate governance listing standards by following certain home country practices. Therefore, our shareholders may be afforded less protection than they otherwise would have under corporate governance listing standards applicable to U.S. domestic issuers.


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Certain shareholders have the right to appoint directors to the Board of Directors and their interests may not coincide with other investors' interests.
Provided that certain circumstances exist, certain of our shareholders are entitled to appoint directors to the Board of Directors pursuant to the Bye-Laws. In summary, Hemen is entitled to appoint four directors (including the Chairman) to the Board of Directors, two of which must be independent directors and unrelated to Hemen. Centerbridge and the Select Commitment Parties each has the right to appoint one independent director. The remaining director shall also be independent and appointed by mutual agreement of Hemen, Centerbridge and the Select Commitment Parties. Each independent director is required to satisfy the independence rules under the United States Securities Exchange Act of 1934 (the " U.S. Securities Exchange Act "), the NYSE and the Oslo Stock Exchange. As a result of these appointment rights, Hemen, Centerbridge and the Commitment Parties are able to influence the composition of the Board of Directors and Hemen may consequently have influence with respect to the Company's management, business plans and policies, including the appointment and removal of its officers. The interests of Hemen, Centerbridge and the Commitment Parties may not coincide with other investors' interests, and their director designees may make decisions other investors disagree with. Please see Section 15.14.2.2 "Election and removal of Directors" for more information on the director appointment procedure.
Our bye-laws limit shareholders' ability to bring legal action against its officers and directors.
Our bye-laws contain a broad waiver by the shareholders of any claim or right of action, both individually and on behalf of the Company, against any of our officers or directors. The waiver applies to any action taken by an officer or director, or the failure of an officer or director to take any action, in the performance of his or her duties, except with respect to any matter involving any fraud or dishonesty on the part of the officer or director. This waiver limits the right of shareholders to assert claims against our officers and directors unless the act or failure to act involves fraud or dishonesty.
Investors may not be able to exercise their voting rights for Shares registered in a nominee account.
Beneficial owners of the Shares that are registered in a nominee account (such as through brokers, dealers or other third parties) may not be able to vote such Shares unless their ownership is re-registered in their names with the Norwegian Central Securities Depository ( "VPS" ) prior to the general meetings. We can provide no assurances that beneficial owners of the Shares will receive the notice of a general meeting in time to instruct their nominees to either effect a re-registration of their Shares or otherwise vote their Shares in the manner desired by such beneficial owners.

ITEM 4.
INFORMATION ON THE COMPANY
 
A.
HISTORY AND DEVELOPMENT OF THE COMPANY
 
1) Company Details
Seadrill Limited (formerly known as “New SDRL Limited”) or the ("Successor Company") was incorporated under the Laws of Bermuda on March 14, 2018 with registration number 53439. Seadrill Limited has been the parent company of the group of companies collectively known as Seadrill with effect from the Effective Date.
Seadrill Limited is an exempted company limited by shares and is listed under the Symbol "SDRL" on the New York Stock Exchange ("NYSE") and Oslo Stock Exchange ("OSE"). Its registered offices are located at Par-la-Ville Place, 4th Floor, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda and our telephone number is +1 (441) 295-6935.
Before the Effective Date, Seadrill's parent company was Seadrill Limited ("Old Seadrill Limited" or "Predecessor Company") which was a company incorporated under the Laws of Bermuda on May 10, 2005 with registration number 36832. Old Seadrill Limited was an exempted company limited by shares and was previously listed under the Symbol "SDRL" on the NYSE and OSE. It held the same registered offices and telephone number as the Successor Company.
2) Significant Developments for the Period from January 1, 2017 through and including December 31, 2018
In this section we have set out important events in the development of our business. This includes information concerning the nature and results of any material reclassification, merger or consolidation of the company or any of its significant subsidiaries; acquisitions or dispositions of material assets other than in the ordinary course of business; any material changes in the mode of conducting the business; material changes in the types of products produced or services rendered; name changes; or the nature and results of any bankruptcy, receivership or similar proceedings with respect to the company or significant subsidiaries. This section covers the period from the beginning of our last full financial year.
a) Chapter 11 Reorganization
This section provides an overview of the Chapter 11 Proceedings, and the transactions described herein and those contemplated by the Plan are together referred to as the " Reorganization ". The Predecessor Company and certain of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court (the " Debtors "), whereas this section provides an overview of the Debtors' restructuring and emergence from bankruptcy, reflecting the acceptance of the Second Amended Joint Chapter 11 Plan (as modified), as confirmed by the Bankruptcy Court on 17 April 2018 (the " Plan "), by all classes entitled to vote and the confirmation of the Plan by the Bankruptcy Court and pursuant to which the " Effective Date " (meaning the date of the Debtors' emergence from bankruptcy proceedings in accordance with the terms and conditions of the Plan) of the Plan occurred on July 2, 2018. The description in this section is qualified in its entirety by reference to

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the Plan. The terms of the Plan are more detailed than the description provided in this section, which may have omitted descriptions of items that may be of interest to particular investors. Therefore, please carefully consider the actual provisions of the Plan for more complete information about the transactions to be consummated in connection with the Debtors' emergence from bankruptcy.
i.
Introduction to the Reorganization
Prior to filing of the Chapter 11 Proceedings (as defined below), Old Seadrill Limited engaged in extensive discussions with its secured lenders, certain holders of its unsecured bonds and potential new money investors regarding the terms of a comprehensive restructuring.
On September 12, 2017, Old Seadrill Limited entered into a restructuring support and lock-up agreement (the " RSA ") with a group of bank lenders, bondholders, certain other stakeholders, and new-money providers (collectively, the " Consenting Stakeholders "). Old Seadrill Limited's consolidated subsidiaries North Atlantic Drilling Ltd. (" NADL ") and Sevan Drilling, together with certain other of its consolidated subsidiaries also entered into the RSA (together with Old Seadrill Limited the " Company Parties "). Ship Finance and three of its subsidiaries, which charter three drilling units to the Company Parties, also executed the RSA. In connection with the RSA, the Company Parties entered into the " Investment Agreement " under which Hemen Investments Limited, an affiliate of Old Seadrill Limited's largest shareholder Hemen Holding Ltd. and the Commitment Parties, committed to provide $1.06 billion in new cash commitments, subject to certain terms and conditions (the " Capital Commitment ").
On September 12, 2017, to implement the transactions contemplated by the RSA and Investment Agreement, the Debtors commenced prearranged reorganization proceedings (the " Chapter 11 Proceedings ") under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas Victoria Division. During the bankruptcy proceedings, the Debtors continued to operate their business as debtors in possession. As a result of the Reorganization, the Plan equitized approximately $2.4 billion in unsecured bond obligations, more than $1.0 billion in contingent newbuild obligations, substantial unliquidated guarantee obligations, and approximately $250 million in unsecured interest rate and currency swap claims, while extending near term debt maturities, providing the Group with over $1.0 billion in new capital and leaving employee, customer and ordinary trade claims largely unimpaired.
ii.
Corporate Reorganization
The Plan provided for Seadrill Limited to serve as the ultimate parent holding company for Old Seadrill Limited's subsidiaries after the Debtors' emergence from the Chapter 11 Proceedings. Seadrill Limited was initially formed as a wholly-owned subsidiary of Old Seadrill Limited and had not conducted any material operations prior to the Effective Date. Following the Debtors' emergence from bankruptcy, the economic interests in the existing shares of Old Seadrill Limited were extinguished, and Old Seadrill Limited was dissolved under Bermuda law. In accordance with the Plan, the common shares of Seadrill Limited were issued to the parties entitled thereto under the Plan and under the Investment Agreement. As part of the concurrent corporate reorganization, Seadrill Limited became the ultimate parent holding company of Old Seadrill Limited's subsidiaries. The Plan was effective on July 2, 2018, and some of the information provided in this annual report therefore relates to Seadrill prior to the Effective Date.
The corporate reorganization also included: (i) the formation of a new wholly-owned intermediate holding company (" IHCo ") as a subsidiary of Seadrill, (ii) and a new wholly-owned intermediate holding company (" RigCo ") as a subsidiary of IHCo which holds interests in Seadrill's rig-owning, rig-operating and management entities transferred to RigCo in the corporate reorganization, (iii) the formation of a new wholly-owned intermediate holding company Seadrill New Finance Limited (" NSNCo "), as a subsidiary of IHCo for the purpose of issuing the " New Secured Notes " or " NSN " (being the USD 880 million aggregate principal amount of 12% Senior Secured Notes due 2025 issued by NSNCo in connection with the Reorganization, as further described below) and (iv) the formation of certain new wholly-owned intermediate holding companies as subsidiaries of NSNCo for the purpose of holding interests in certain of the non-consolidated entities transferred to NSNCo by Old Seadrill Limited in the corporate reorganization.
iii.
The Plan
The Debtors filed a proposed plan of reorganization and disclosure statement with the Bankruptcy Court on September 12, 2017, as well as a disclosure statement relating to the proposed plan of reorganization. Subsequent to September 12, 2017, the Debtors negotiated with their various creditors, including an ad hoc group of holders of unsecured bonds (the " Ad Hoc Group ") and certain newbuild ship yards with which the Debtors had contractual relationships to build new rigs. On 26 February 2018, the Debtors announced a global settlement with various creditors, including the Ad Hoc Group, the official committee of unsecured creditors (the " Committee ") and other major creditors in its Chapter 11 cases, including Samsung and DSME, two of the Debtors' newbuild shipyards, and an affiliate of Barclays Bank PLC (" Barclays "), another holder of unsecured bonds. In connection with the global settlement, the Debtors entered into an amendment to the RSA and an amendment to the Investment Agreement. The amendments to the RSA and Investment Agreement provided for inclusion of the Ad Hoc Group and Barclays into the Capital Commitment as Commitment Parties, increased the Capital Commitment to $1.08 billion, increased recoveries for general unsecured creditors under the Plan, an agreement regarding the allowed claim of the newbuild shipyards and an immediate cessation of all litigation and discovery efforts in relation to the Plan as well as the Debtors' rejection and recognized termination of the newbuild contracts. The Investment Agreement, as amended, provided for certain milestones for the Debtors' restructuring: (1) the Bankruptcy Court entered an order confirming the Plan on April 17, 2018 (the " Confirmation Date ") and (2) the effective date of the Plan had to occur within 90 days of the Confirmation Date, and in any event no later than August 8, 2018.
In connection with the global settlement, on February 26, 2018, the Debtors filed a proposed Second Amended Joint Chapter 11 Plan of Reorganization with the Bankruptcy Court and on April 17, 2018, the Bankruptcy Court entered an order confirming the Second Amended Joint Chapter 11 Plan (as modified) of Reorganization, as amended and supplemented. Reference is made to the Second Amended Joint Chapter 11 Plan (as modified) of Reorganization, in the form confirmed by the Bankruptcy Court, with any further amendments or supplements thereto, as the Plan. The Plan became effective on July 2, 2018. Under the Plan and the terms of the Investment Agreement and the transactions contemplated

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therein, the Commitment Parties to the Investment Agreement were issued certain common shares of Seadrill Limited and purchased additional common shares of Seadrill Limited in connection with the completion of an equity rights offering to holders of claims against the Debtors. Seadrill Limited also agreed to register its common shares for resale by the selling shareholders.
iv.
Rights offering
Pursuant to the Plan and an order of the Bankruptcy Court, a set of rights offering procedures were approved. As a result, eligible holders of general unsecured claims against the Debtors were offered the right to participate in (i) a rights offering of up to $119.4 million in principal amount of the New Secured Notes (the " Notes Rights Offering ") and the corresponding pro rata portion of 57.5% of common shares in Seadrill Limited were issued to holders who participated in the Notes Rights Offering and (ii) a rights offering of up to $48.1 million in value of common shares in Seadrill Limited (the " Equity Rights Offering ").
The Equity Rights Offering was directed to eligible holders of General Unsecured Claims (as defined in the Plan), who either (i) were located in the United States or (ii) were located outside the United States and who satisfied one of the following criteria (a) they were located in a member state of the European Economic Area (EEA); (b) they were located in the United Kingdom and were qualified (i) to make an investment in Seadrill Common Shares under the applicable laws of the EEA (ii) satisfied certain criteria under the laws of the United Kingdom; or (c) were located in a different jurisdiction, and under the laws of that jurisdiction were entitled to subscribe for and purchase the Seadrill Common Shares, in each case without the need for any registration or similar filing by Seadrill Limited. The subscription period for the Equity Rights Offering commenced on May 7, 2018 and ended on 5:00 pm New York City Time on June 8, 2018. The subscription right to participate in the Equity Rights Offering could not be separated from the related General Unsecured Claims, hence the only way to transfer the subscription rights was to transfer the related General Unsecured Claims. The holders of General Unsecured Claims could purchase up to 2.700 Seadrill Common Shares for each USD 1,000 in allowed amount of its claims in aggregate in the Equity Rights Offering. The subscription price for Seadrill Common Shares in the Equity Rights Offering was $8.421 per share. Holders of General Unsecured Claims who were not entitled to participate in the Equity Rights Offering, were eligible to receive a cash payment in the amount of $30 per $1,000 of the allowed amount of their claim.
The New Secured Notes and the Seadrill Common Shares were acquired by the Commitment Parties under the Investment Agreement and were reduced to the extent the Note Rights and Equity Rights were exercised in the Notes Rights Offering and the Equity Rights Offering, respectively. The Commitment Parties did not participate in the Notes Rights Offering nor the Equity Rights Offering, in accordance with the terms of the Investment Agreement.
v.
Issuance and distribution of the new shares under the Plan and Investment Agreement
The following table sets forth the allocation of common shares issued on the Effective Date, subject to the terms and conditions of the Plan:
 
 
 
 
Percentage
Recipient of Common Shares
 
Number of shares

 
Prior to dilution by Primary Structuring Fee and the shares reserved under the Employee Incentive Plan

 
Prior to dilution by the shares reserved under the Employee Incentive Plan

 
Fully diluted

Commitment Parties (in exchange for cash paid pursuant to the Investment Agreement) and Equity Rights Offering Subscribers
 
23,750,000

 
25.00
%
 
23.75
%
 
21.38
%
Recipients of New Secured Notes (including Commitment Parties and Notes Rights Offering Subscribers)
 
54,625,000

 
57.50
%
 
54.63
%
 
49.16
%
Holders of General Unsecured Claims
 
14,250,000

 
15.00
%
 
14.25
%
 
12.82
%
Former Holders of Old Seadrill Limited Equity and Seadrill Limited 510(b) Claimants
 
1,900,000

 
2.00
%
 
1.90
%
 
1.71
%
Fees to Select Commitment Parties
 
475,000

 
0.50
%
 
0.47
%
 
0.43
%
All creditors, excluding Primary Structuring Fee
 
95,000,000

 
100.00
%
 
95.00
%
 
85.50
%
Hemen (on account of Primary Structuring Fee)
 
5,000,000

 
-

 
5.00
%
 
4.50
%
Total, prior to dilution by shares reserved under the Employee Incentive Plan
 
100,000,000

 
-

 
100.00
%
 
90.00
%
Reserved for the Employee Incentive Plan
 
11,111,111

 
-

 
-

 
10.00
%
Total, fully diluted
 
111,111,111

 
-

 
-

 
100.00
%
vi.
New Secured Notes
In accordance with the terms and conditions of the Investment Agreement, the Commitment Parties purchased the full principal amount of the New Secured Notes for $880 million in cash, less the principal amount purchased by participants in the Notes Rights Offering, and on the Effective Date, NSNCo issued $880 million in principal amount of New Secured Notes. As described above, Seadrill Limited issued approximately

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57.5% of the common shares in Seadrill (prior to dilution by the Primary Structuring Fee and the shares reserved under the employee incentive plan) on a pro rata basis to the purchasers of the New Secured Notes.
b) Acquisitions or disposals of material assets
On March 13, 2017, we reached settlement with Hyundai Samho Heavy Industries ( "HSHI" ) with regard to the West Mira , pursuant to which we received a cash payment of $170 million on March 14, 2017, representing the yard installment receivable excluding any additional accrued interest. We recorded a non-cash impairment of $44 million for the year ended December 31, 2017 to reflect the difference in the carrying value of the West Mira receivable and the settlement value. As part of this settlement, Northern Drilling (" NODL "), a related party, purchased the West Mira from HSHI. In June 2018 we executed an agreement with NODL for the commercial and technical management of the West Mira as well as a right of first refusal for purchase of the Unit.
On April 29, 2017 we reached an agreement with Shelf Drilling to sell the West Triton, West Mischief and West Resolute for a total consideration of $225 million . The West Triton and West Resolute were delivered in May 2017, whilst the West Mischief was delivered in September 2017. The sale resulted in a loss on disposal of $166 million .
On April 5, 2018, we entered into a settlement and release agreement, subject to Bankruptcy Court approval, with Jurong in respect of the West Rigel, which was recorded in our Consolidated Balance Sheet as an asset held for sale at December 31, 2017. The sale completed, and the proceeds were received on May 9, 2018. Per the terms of the New Secured Notes, we were required to redeem a proportion of the principal and interest outstanding on the notes using our share of the West Rigel sale proceeds. We used the proceeds to make a mandatory redemption of $121 million of principal and $5 million of accrued interest on November 1, 2018.
c) Other significant developments
On April 26, 2017, as part of Archer’s restructuring plans, we agreed to make cash payments totaling $28 million to extinguish $278 million of financial guarantees provided by us on behalf of Archer. We also converted $146 million, including accrued interest and fees, in subordinated loans provided to Archer into a $45 million subordinated convertible loan. The subordinated convertible loan bears interest of 5.5%, matures in December 2021 and has a conversion right into equity of Archer Limited in 2021. The exercise price of the option is $2.083 per share, which was approximately 75% above the subscription price in Archer’s private placement on March 2, 2017.
On May 11, 2018, we purchased an interest rate cap for $68 million to mitigate our exposure to future increases in LIBOR on our floating rate debt. 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 principal amount covered by the cap as at December 31, 2018 is $4.5 billion.
On July 18, 2018 Seadrill Partners, received approximately $248 million relating to the West Leo early termination litigation award, of which $204 million was recognized as revenue in Seadrill Partners' Statement of Operations for the second quarter ended June 30, 2018. Seadrill Partners is an associated company in which we hold an investment (see ITEM 4C "Organizational Structure").
On October 31, 2018, we completed a transaction that fully extinguished the sponsor guarantees given by Seadrill Limited and Sapura Energy Berhad for the benefit of the lenders of certain debt facilities of the Seabras Sapura joint venture. Seadrill Limited’s guarantee obligations were previously released, discharged and terminated as part of the Chapter 11 proceedings and under the terms of the October 31 transaction, the lenders confirmed that they had no outstanding claims against Seadrill Limited in respect of its guarantees and released and discharged Sapura Energy Berhad’s guarantees. In return for the release and discharge of both sponsors’ guarantees, the lenders under the debt facilities received, amongst other things, cross-collateralisation of the debt facilities, a prepayment from the joint venture, an increase in margin and a consent fee.
On November 1, 2018, we redeemed $121 million of principal and $5 million of accrued interest on our New Secured Notes. Per the terms of the New Secured Notes, we were required to redeem a proportion of the principal and interest outstanding on the notes using our share of the West Rigel sale proceeds (refer to section 2b above).
In December 2018, we reached an amicable agreement with Transocean over alleged patent infringement of the Transocean dual activity patent. Under the terms of the settlement, Seadrill and Seadrill Partners have entered into a global license agreement with Transocean of the dual activity drilling method on our rigs covering alleged past infringements and future use.
3) Capital expenditures
Our capital expenditures primarily relate to (i) our newbuilding drilling unit program, (ii) upgrades to our existing drilling units and (iii) costs incurred on major maintenance projects.
We have summarized capital expenditures for the periods covered by this annual report in the table below.

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(In $ millions)
 
Successor

 
Predecessor
Summary of capital expenditures
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Additions to newbuilding
 
—

 
(1
)
 
(33
)
 
(52
)
Additions to drilling units and equipment
 
(27
)
 
(48
)
 
(59
)
 
(84
)
Payments for long-term maintenance
 
(71
)
 
(78
)
 
(58
)
 
(95
)
Total capital expenditure
 
(98
)
 
(127
)
 
(150
)
 
(231
)
4) Further information
The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. You may find additional information on Seadrill on that site. The address of that site is http://www.sec.gov.


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B.
BUSINESS OVERVIEW

1) Introduction
We are an offshore drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership and operation of drillships, semi-submersible rigs and jack-up rigs for operations in shallow to ultra-deepwater areas in both benign and harsh environments. We contract our drilling units to drill wells for our customers on a dayrate basis. Typically, our customers are oil super-majors and major integrated oil and gas companies, state-owned national oil companies and independent oil and gas companies.
Through a number of acquisitions of companies, second-hand units and newbuildings, we have developed into one of the world's largest international offshore drilling contractors. We own and operate 35 drilling rigs and we manage and operate 18 rigs on behalf of Seadrill Partners, SeaMex and Northern Drilling.
We are recognized for providing high quality operations, in some of the most challenging sectors of offshore drilling. We employee 4,888 employees across the globe. We are incorporated in Bermuda, and have worldwide operations based on where activities are conducted in the global oil and gas industry.
We operate through the following segments: (i) floaters; (ii) jack-up rigs; and (iii) other, as further explained below and in 5A - "Operating and Financial Review".
2) Our Fleet
Our fleet is one of the youngest and most modern of all the major offshore drilling contractors. We currently own and operate a fleet of 35 drilling units, including seven drillships, 12 semi-submersible rigs and 16 jack-up rigs. We also have an option to purchase one semi-submersible rig. You may find additional information on our drilling units and newbuildings in item 4D - "Property, Plant and Equipment".
We categorize the drilling units in our fleet as (i) floaters and (ii) jack-ups. This is further explained below.
a) Floaters
Our floaters segment encompasses our drillships and semi-submersible rigs.
i.
Drillships :
Drillships are self-propelled ships equipped for drilling offshore in water depths ranging from 1,000 to 12,000 feet and are positioned over the well through a computer-controlled thruster system similar to that used on semi-submersible rigs. Drillships are suitable for drilling in remote locations because of their mobility and large load-carrying capacity. Depending on country of operation, drillships operate with crews of 65 to 100 people.
ii.
Semi-submersible drilling rigs:
Semi-submersibles are self-propelled drilling rigs (which include cylindrical designed units) consisting of an upper working and living quarters deck connected to a lower hull consisting of columns and pontoons. Such rigs operate in a “semi-submerged” floating position, in which the lower hull is below the waterline and the upper deck protrudes above the surface. The rig is situated over a wellhead location and remains stable for drilling in the semi-submerged floating position, due in part to its wave transparency characteristics at the water line.
Semi-submersible rigs can be either moored or dynamically positioned. Moored semi-submersible rigs are positioned over the wellhead location with anchors and typically operate in water depths ranging up to 1,500 feet. Dynamically positioned semi-submersible rigs are positioned over the wellhead location by a computer-controlled thruster system and typically operate in water depths ranging from 1,000 to 12,000 feet. Depending on country of operation, semi-submersible rigs generally operate with crews of 65 to 100 people.
b) Jack-Up Rigs
Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the seabed. A jack-up rig is mobilized to the drill site with a heavy lift vessel or a wet tow. At the drill site, the legs are lowered until they penetrate the sea bed and the hull is elevated to an approximate operational airgap of 50 to 100 feet depending on the expected environmental forces. After completion of the drilling operations, the hull is lowered to floating draft, the legs are raised and the rig can be relocated to another drill site. Jack-ups are generally suitable for water depths of 450 feet or less and operate with crews of 90 to 120 people.
3) Competitive Strengths
We believe that our competitive strengths include:
i.
One of the largest offshore drilling contractors
Since our inception in 2005, we have developed into one of the world’s largest international offshore drilling contractors. While we are one of the largest offshore drilling companies, we also have one of the youngest rig fleets in our industry, with an average fleet age of approximately 9 years.

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ii.
Commitment to safety and the environment
We believe that the combination of quality drilling units and experienced and skilled employees allows us to provide our customers with safe and effective operations. Quality assets and operational expertise allow us to establish, develop and maintain a position as a preferred provider of offshore drilling services for our customers.
iii.
Technologically advanced and young fleet
Our drilling units are among the most technologically advanced in the world, based on the age of our fleet. The majority of our rigs were built after 2007, which is among the lowest average fleet age in the industry. Although current offshore drilling demand is weak, new and modern units that offer superior technical capabilities, operational flexibility and reliability are preferred by customers and are winning most available opportunities. We believe, based on our proven operational track record and fleet composition, that we will be better placed to secure new drilling contracts than some of our competitors with older, less advanced rig fleets.
iv.
Strong and diverse customer relationship s
We have strong relationships with our customers that we believe are based on our operational track record and quality of our fleet. Our customers are oil and gas exploration and production companies, including integrated oil companies, state-owned national oil companies and independent oil and gas companies.
4) Overall Strategy
During the current challenging period for the industry and to maintain our position as a leading offshore driller, our strategy includes being able to deliver in the following key areas:
i.
Best Operations
We are a leading offshore deepwater drilling company and our key objective is to deliver the best operations possible - both in terms of utilization and health, safety and environment. To do this, we leverage having one of the most modern fleets in the industry and our combination of experienced and skilled employees across the organization. Using our strong operational record, we intend to maximize opportunities for new drilling contracts and sustain a competitive cost structure, which we have been pursuing through our multi-year savings program, while minimizing chances of contract terminations.
ii.
Right rigs
Our business model includes both jack-ups and floaters and we will continue to maintain our presence in both segments. Having the right rigs in these two segments allows us to offer a range of assets to suit our customer needs, to work in various geographies and water depths, and to position ourselves for future growth in the industry.
iii.
Strongest relationships
We have established strong and long-term relationships with key players in the industry and we will seek to deepen and strengthen these relationships as part of our strategy. This involves identifying additional value-adding services for our existing customers and developing long-term partnerships. By providing the best possible service to our customers, we aim to help them unlock energy and be valued partners in their success.
iv.
Leading organization
We are proud of our Seadrill culture and we recognize that our business is built on people. As part of our strategy, we aim to recruit, retain, and develop the best people in the industry and to build an organization that adapts to business needs.
5) Markets
Our operations are geographically dispersed in oil and gas exploration and development areas throughout the world. We operate in a single, global offshore drilling market, as our drilling rigs are mobile assets and are able to be moved according to prevailing market conditions. We organize our business into the following segments: (i) floaters, (ii) jack-ups and (iii) other. You can find an analysis of our revenues and fixed assets by operating segment and geography in Note 6 to the Consolidated Financial Statements included within this report.
The "floater" and "jack-up" segments are driven by category of rig as explained in section two above. Our "other" segment predominantly relates to the provision of management services to third parties and related parties, in which we charge a management fee income for such services. Please refer to Note 30 to the Consolidated Financial Statements included within this report for more information on management and administrative services provided to related parties.
6) Seasonality
In general, seasonal factors do not have a significant direct effect on our business. However, we have operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operational utilization of the rigs and our ability to relocate rigs between drilling locations, and as such, limit contract opportunities in the short term. Such adverse weather could include the hurricane season and loop currents for our operations in the Gulf of Mexico, the winter season in offshore Norway, West of the Shetlands and Canada, and the monsoon season in Southeast Asia.

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7) Customers
Our customers are oil and gas exploration and production companies, including major integrated oil companies, independent oil and gas producers and government-owned oil and gas companies. You can find an analysis of our most significant customers in Note 6 to the Consolidated Financial Statements included within this report.
8) Drilling contracts
In general, we contract our drilling units to oil and gas companies to provide offshore drilling services at an agreed dayrate for a specified contract term. Dayrates can vary, depending on the type of drilling unit and its capabilities, contract length, geographical location, operating expenses, taxes and other factors such as prevailing economic conditions. We do not provide "turnkey" or other risk-based drilling services to the customer. Instead, we provide a drilling unit and rig crews and charge the customer a fixed amount per day regardless of the number of days needed to drill the well. The customer bears substantially all the ancillary costs of constructing the well and supporting drilling operations, as well as most of the economic risk relative to the success of the well.
Where operations are interrupted or restricted due to equipment breakdown or operational failures, we do not generally receive dayrate compensation for the period of the interruption in excess of contractual allowances. Furthermore, the dayrate we receive can be reduced in instances of interrupted or suspended service due to, among other things, repairs, upgrades, weather, maintenance, force majeure or requested suspension of services by the customer and other operating factors.
However, contracts normally allow for compensation when factors beyond our control, including weather conditions, influence the drilling operations and, in some cases, for compensation when we perform planned maintenance activities. In some of our contracts, we are entitled to cost escalation to compensate for industry specific cost increases as reflected in publicly available cost indexes.
We may receive lump sum or dayrate based fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to the start of drilling services. In some cases, we may also receive lump sum or dayrate based fees for demobilization upon completion of a drilling contract.
Our contracts may generally be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for an extended period because of a breakdown of major rig equipment, "force majeure" or upon the occurrence of other specified conditions. Some contracts include provisions that allow the customer to terminate the contract without cause for a specified early termination fee.
A drilling unit may be "stacked" if it has no contract in place. Drilling units may be either warm stacked or cold stacked. When a rig is warm stacked, the rig is idle but can deploy quickly if an operator requires its services. Cold stacking a rig involves reducing the crew to either zero or just a few key individuals and storing the rig in a harbor, shipyard or designated area offshore.
9) Competition
The offshore drilling industry is highly competitive, with market participants ranging from large multinational companies to small locally-owned companies. The demand for offshore drilling services is driven by oil and gas companies’ exploration and development drilling programs. These drilling programs are affected by oil and gas companies’ expectations regarding oil and gas prices, anticipated production levels, worldwide demand for oil and gas products, the availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments.
Oil and gas prices are volatile, which has historically led to significant fluctuations in expenditures by our customers for drilling services. Variations in market conditions during cycles impact us in different ways, depending primarily on the length of drilling contracts in different regions.
Offshore drilling contracts are generally awarded on a competitive bid basis. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability and sustainability, rig location, condition of equipment, operating integrity, safety performance record, crew experience, reputation, industry standing and client relations.
Furthermore, competition for offshore drilling rigs is generally on a global basis, as rigs are highly mobile. However, the cost associated with mobilizing rigs between regions is sometimes substantial, as entering a new region could necessitate upgrades of the unit and its equipment to specific regional requirements. In particular, for rigs to operate in harsh environments, such as offshore Norway and Canada, as opposed to benign environments, such as the Gulf of Mexico, West Africa, Brazil and Southeast Asia, more demanding weather conditions would require more costly investment in the outfitting and maintenance of the drilling units.
For further information on current market conditions and global offshore drilling fleet, please see “Item 5D - Trend Information.”
10) Risk of Loss and Insurance
Our operations are subject to hazards inherent in the drilling of oil and gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, or seriously damage or destroy the equipment involved. Offshore drilling contractors are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our rig insurance package policy provides insurance coverage for physical damage to our rigs, loss of hire for our working rigs and third-party liability.

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i.
Physical Damage Insurance
We purchase hull and machinery insurance to cover for physical damage to our drilling rigs. We retain the risk, through self-insurance, for the deductibles relating to physical damage insurance on our drilling unit fleet; currently, a maximum of $5 million per occurrence.
ii.
Loss of Hire Insurance
We also have insurance to cover loss of revenue for our operational rigs (floaters and harsh environment jack-ups only) in the event of extensive downtime caused by physical damage, where such damage is covered under our physical damage insurance. The loss of hire insurance has a deductible period of up to 60 days after the occurrence of physical damage. Thereafter we are compensated for loss of revenue up to 290 days per event aggregated per year. The daily indemnity will vary from 75% to 100% of the contracted dayrate. We retain the risk related to loss of hire during the initial up to 60-day period, as well as any loss of hire exceeding the number of days permitted under the insurance policy. If the repair period for any physical damage exceeds the number of days permitted under the loss of hire policy, we will be responsible for the loss of revenue in such a period.
iii.
Protection and Indemnity Insurance
We also purchase Protection and Indemnity insurance (P&I) and excess liability insurance for personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling rigs to cover claims of up to $500 million and $900 million in the United States per event and in the aggregate. We retain the risk for the deductible of up to $25,000 per occurrence relating to protection and indemnity insurance or up to $500,000 for claims made in the United States.
iv.
Windstorm Insurance
We have elected to place an insurance policy for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico with a Combined Single Limit of $100 million in the annual aggregate, which includes loss of hire. We intend to renew our policy to insure a limited part of this windstorm risk for a further period starting May 1, 2019 through April 30, 2020.
11) Environmental and Other Regulations in the Offshore Drilling Industry
Our operations are subject to numerous laws and regulations in the form of international treaties and maritime regimes, flag state requirements, national environmental laws and regulations, navigation and operating permits requirements, local content requirements, and other national, state and local laws and regulations in force in the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. See “Item 3. Key Information – D. Risk Factors – Risks Relating to Our Company and Industry – Governmental laws and regulations, including environmental laws and regulations, may add to our costs, expose to us liability, or limit our drilling activity.”
i.
Flag State Requirements
All our drilling units are subject to regulatory requirements of the flag state where the drilling unit is registered. The flag state requirements are international maritime requirements and, in some cases, further interpolated by the flag state itself. These include engineering, safety and other requirements related to the maritime industry. In addition, each of our drilling units must be “classed” by a classification society. The classification society certifies that the drilling rig is “in-class,” signifying that such drilling rig has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the flag state and the international conventions of which that country is a member. Maintenance of class certification requires expenditure of substantial sums and can require taking a drilling unit out of service from time to time for repairs or modifications to meet class requirements.  Our drilling units must generally undergo a class survey once every five years. In addition, for some of the internationally-required class certifications, such as the Code for the Construction and Equipment of Mobile Offshore Drilling Units (the “ MODU Code ”) certificate, the classification society will act on a flag state’s behalf.
ii.
International Maritime Regimes
Applicable international maritime regime requirements include, but are not limited to, the International Convention for the Prevention of Pollution from Ships (“ MARPOL ”), the International Convention on Civil Liability for Oil Pollution Damage of 1969 (the “ CLC ”), the International Convention on Civil Liability for Bunker Oil Pollution Damage of 2001 (ratified in 2008), or the Bunker Convention, the International Convention for the Safety of Life at Sea of 1974 (“ SOLAS ”), the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or the ISM Code, MODU Code, and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004 (the “ BWM Convention ”).  These various conventions regulate air emissions and other discharges to the environment from our drilling units worldwide, and we may incur costs to comply with these regimes and continue to comply with these regimes as they may be amended in the future. In addition, these conventions impose liability for certain discharges, including strict liability in some cases. See Item 3 “Key Information - D. Risk Factors - Risks Relating to Our Company and Industry - We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.”

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Annex VI to MARPOL sets limits on sulfur dioxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances. Annex VI applies to all ships and, among other things, imposes a global cap on the sulfur content of fuel oil and allows for specialized areas to be established internationally with even more stringent controls on sulfur emissions. For vessels 400 gross tons and greater, platforms and drilling rigs, Annex VI imposes various survey and certification requirements. Moreover, amendments to Annex VI require the imposition of progressively stricter limitations on sulfur emissions from ships. Since January 1, 2015, these limitations have required that fuels of vessels in covered Emission Control Areas (“ ECAs ”) contain no more than 0.1% sulfur, including the Baltic Sea, North Sea, North America and United States Sea ECAs. For non-ECA areas, the sulfur limit in marine fuel is currently capped at 3.5%, which will then decrease to 0.5% on January 1, 2020, but this was subject to a feasibility review.
At MEPC 73 in October 2018, it was confirmed that there will be no change to the 1 January 2020 0.50% SOx limit and a ban was adopted on the carriage of fuel with sulphur content above the limit for ships without an approved alternative means, such as a scrubber.  This will enter into force on 1 Mar 2020, because this is the earliest possible date for a MARPOL amendment to enter into force - it does not change the underlying 1 Jan 2020 limit change.  There are related IMO regulations concerning the discharge of scrubber washwater, but some coastal states and ports have implemented local regulations with more stringent requirements that restrict, or completely prohibit, the discharge of washwater from open loop scrubbers or prohibit the use of scrubbers.  This is an issue in several European countries, California, Hawaii & Connecticut in USA, UAE, India, Singapore and China.  Annex VI also requires tiers of stringent nitrogen oxide emissions standards for new marine engines, depending on their date of installation. All our rigs are in compliance with these requirements. Tier III engines are already required in the North American and US Caribbean ECAs, and vessels built after 1 January 2021 will require such engines to enter the North Sea and Baltic ECA.  As part of IMO data gathering related to Green House Gas (GHG) emissions, Annex VI also requires data collection for fuel oil consumption and reporting of this to the flag state. 
The BWM Convention calls for a phased introduction of mandatory ballast water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The BWM Convention entered into force on September 8, 2017. Under its requirements, for units with ballast water capacity more than 5,000 cubic meters that were constructed in 2011 or before, only ballast water treatment will be accepted by the BWM Convention. All Seadrill units considered in operational status are in full compliance with the staged implementation of the BWM Convention by International Maritime Organization guidelines.
iii.
Environmental Laws and Regulations
Applicable environmental laws and regulations include the U.S. Oil Pollution Act of 1990, (" OPA "), the Comprehensive Environmental Response, Compensation and Liability Act, (" CERCLA "), the U.S. Clean Water Act, (" CWA "), the U.S. Clean Air Act, (" CAA "), the U.S. Outer Continental Shelf Lands Act (" OCSLA "), the U.S. Maritime Transportation Security Act of 2002, (“ MTSA "), European Union regulations, including the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations, and Brazil’s National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Federal Law (9966/2000) relating to pollution in Brazilian waters. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection. In certain circumstances, these laws may impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. Implementation of new environmental laws or regulations that may apply to ultra-deepwater drilling units may subject us to increased costs or limit the operational capabilities of our drilling units and could materially and adversely affect our operations and financial condition. See Item 3 “Key Information - D. Risk Factors - Risks Relating to Our Company and Industry - We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.”
iv.
Safety Requirements
Our operations are subject to special safety regulations relating to drilling and to the oil and gas industry in many of the countries where we operate. The United States undertook substantial revision of safety regulations applicable to our industry following the 2010 Deepwater Horizon Incident, in which we were not involved. Other countries also have undertaken or are undertaking a review of their safety regulations related to our industry. These safety regulations may impact our operations and financial results by adding to the costs of exploring for, developing and producing oil and gas in offshore settings. For instance, in 2016, the BSEE published a final rule that sets more stringent design requirements and operational procedures for critical well control equipment used in offshore oil and gas drilling and separately announced a risk-based inspection program for offshore facilities. Also, in 2016, BOEM issued a final Notice to Lessees and Operators imposing more stringent supplemental bonding procedures for the decommissioning of offshore wells, platforms and pipelines. These regulations, which may result in additional costs for us, have since become the subject of additional review and possible revision by BSEE and BOEM and, as a result, we cannot predict their impact on our future operations. The EU also has undertaken a significant revision of its safety requirements for offshore oil and gas activities through the issue of the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations. These other future safety and environmental laws and regulations regarding offshore oil and gas exploration and development may increase the cost of our operations, lead our customers to not pursue certain offshore opportunities and result in additional downtime for our drilling units. In addition, if material spill events similar to the Deepwater Horizon Incident were to occur in the future, or if other environmental or safety issues were to cause significant public concern, the United States or other countries could elect to, again, issue directives to cease drilling activities in certain geographic areas for lengthy periods of time.
v.
Navigation and Operating Permit Requirements
Numerous governmental agencies issue regulations to implement and enforce the laws of the applicable jurisdiction, which often involve lengthy permitting procedures, impose difficult and costly compliance measures, particularly in ecologically sensitive areas, and subject operators to substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Some of these laws contain criminal sanctions in addition to civil penalties.

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vi.
Local Content Requirements
Governments in some countries have become increasingly active in local content requirements on the ownership of drilling companies, local content requirements for equipment utilized in our operations, and other aspects of the oil and gas industries in their countries. These regulations include requirements for participation of local investors in our local operating subsidiaries in countries such as Angola and Nigeria. There are currently also local content requirements in relation to drilling unit contracts in which we are participating in Brazil, although Brazil recently lessened local content requirements for future projects. Although these requirements have not had a material impact on our operations in the past, they could have a material impact on our earnings, operations and financial condition in the future.
vii.
Other Laws and Regulations
In addition to the requirements described above, our international operations in the offshore drilling segment are subject to various other international conventions and laws and regulations in countries in which we operate, including laws and regulations relating to the importation of, and operation of, drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling units and other equipment. There is no assurance that compliance with current laws and regulations or amended or newly adopted laws and regulations can be maintained in the future or that future expenditures required to comply with all such laws and regulations in the future will not be material.

C.
ORGANIZATIONAL STRUCTURE

1) Consolidated Subsidiaries
A full list of our significant management, operating and rig-owning subsidiaries is shown in Exhibit 8.1. All subsidiaries are, indirectly or directly, wholly-owned by us, except as follows:
i.
Asia Offshore Drilling (" AOD ")
We have a 66.24% interest in Asia Offshore Rig 1 Ltd, Asia Offshore Rig 2 Ltd, and Asia Offshore Rig 3 Ltd which own the benign environment jack-up rigs AOD 1, AOD 2 and AOD 3. The remaining 33.76% interest is owned by Mermaid Maritime Public Company Limited (" Mermaid ").
ii.
Ship Finance Variable Interest Entities
Between 2007 and 2013 we entered into sale and leaseback arrangements for the semi-submersible rigs West Taurus and West Hercules and the jack-up rig West Linus. The counterparty to these arrangements was Ship Finance International Ltd (" Ship Finance "), who is a related party because our largest shareholder, Hemen, has a significant interest in both us and Ship Finance. Ship Finance incorporated SFL Deepwater Ltd, SFL Hercules Ltd, and SFL Linus Ltd for the sole purpose of owning and leasing the drilling units. Whilst these companies are wholly-owned subsidiaries of Ship Finance, we consolidate them under the variable interest entity model because we are the primary beneficiary of the entities.
iii.
Seadrill Nigeria Operations Limited
We have a controlling interest in Seadrill Nigeria Operations Limited, a service company that supports the operations of our drillship West Jupiter on its contract with Total in Nigeria. The non-controlling interest is owned by HH Global Alliance Investments Limited, an unrelated party.
2) Investments in Non-Consolidated Entities
In addition to owning and operating our offshore drilling units through our subsidiaries, we also, from time to time, make investments in other offshore drilling and oil services companies. We currently have the following significant equity investments:
i.
Seadrill Partners
Seadrill Partners is a Marshall Islands limited liability company that owns four drillships, four semi-submersible rigs and three tender rigs. Seadrill Partners focuses on owning and operating offshore drilling rigs under long-term contracts with major oil companies. As of February 28, 2019 , we own 46.6% of the outstanding limited liability interests of Seadrill Partners, which includes 35% of the outstanding common units and 100% of its subordinated units. We also own significant non-controlling interests in most of the operating and rig-owning subsidiaries of Seadrill Partners. Seadrill Partners’ common units trade on the NYSE under the symbol “SDLP”.
ii.
SeaMex
SeaMex is a joint venture that owns and operates five jack-up drilling units located in Mexico under contract with Pemex. As of February 28, 2019 , we have a 50% ownership stake in SeaMex. The remaining 50% interest is owned by an investment fund controlled by Fintech Advisory Inc., (" Fintech ").
iii.
Archer
Archer is a global oilfield service company that specializes in drilling and well services. As of February 28, 2019 we own 15.7% of the outstanding common shares of Archer. We also own a $45 million convertible loan note that has a conversion right into equity of Archer in 2021.

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iv.
Seabras Sapura
Seabras Sapura is a group of related companies that own and operate pipe-laying service vessels in Brazil. As of February 28, 2019 , we have a 50% ownership stake in each of these companies. The remaining 50% interest is owned by Sapura Energy Berhad (" SapuraEnergy ").
You can find further information on our investments in non-consolidated entities in Note 18 to the Consolidated Financial Statements included in this report.

D.
PROPERTY, PLANT AND EQUIPMENT
 
In this section, we provide details of our major categories of property, plant and equipment. We have categorized our assets as (i) drilling units, (ii) newbuildings and (iii) office and equipment. You can find further information in the notes to the Consolidated Financial Statements included in this report. Please refer to Note 19 for information on newbuildings, Note 20 for information on drilling units and Note 21 for information on office and equipment.
1) Drilling units
The following tables, presented as of February 28, 2019, provide certain specifications for our operational drilling rigs. Unless otherwise noted, the stated location of each rig indicates either the current drilling location, if the rig is operating, or the next operating location, if the rig is mobilizing for a new contract.
a) Drillships (7)
Unit
Year built
 
Water depth (feet)
 
Drilling depth (feet)
 
Area of location
 
Estimated month of rig availability
West Navigator
2000
 
7,500
 
35,000
 
Norway
 
available
West Gemini
2010
 
10,000
 
35,000
 
Angola
 
May 2019
West Tellus
2013
 
12,000
 
40,000
 
Brazil
 
October 2019
West Neptune
2014
 
12,000
 
40,000
 
USA
 
December 2019
West Jupiter
2014
 
12,000
 
40,000
 
Nigeria
 
December 2019
West Saturn
2014
 
12,000
 
40,000
 
Brazil
 
September 2019
West Carina
2015
 
12,000
 
40,000
 
Malaysia
 
June 2019
b) Semi-submersible Rigs (12)
Unit
Year built
 
Water depth (feet)
 
Drilling depth (feet)
 
Area of location
 
Estimated month of rig availability
West Alpha
1986
 
2,000
 
23,000
 
Norway
 
available
West Venture
2000
 
2,600
 
30,000
 
Norway
 
available
West Phoenix
2008
 
10,000
 
30,000
 
Norway
 
January 2021
West Hercules   (i)
2008
 
10,000
 
35,000
 
Norway
 
November 2019
West Taurus   (i)
2008
 
10,000
 
35,000
 
Spain
 
available
West Eminence
2009
 
10,000
 
30,000
 
Spain
 
available
West Orion
2010
 
10,000
 
35,000
 
Malaysia
 
available
West Pegasus
2011
 
10,000
 
35,000
 
Norway
 
available
West Eclipse
2011
 
10,000
 
40,000
 
Namibia
 
available
Sevan Driller
2009
 
10,000
 
40,000
 
Malaysia
 
available
Sevan Brasil
2012
 
10,000
 
40,000
 
Aruba
 
available
Sevan Louisiana
2013
 
10,000
 
40,000
 
USA
 
May 2019

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c) Jack-up Rigs (16)
Unit
Year built
 
Water depth (feet)
 
Drilling depth (feet)
 
Area of location
 
Estimated month of rig availability
 
 
 
 
 
 
 
 
 
 
Jack-up rigs
 
 
 
 
 
 
 
 
 
West Epsilon
1993
 
400
 
30,000
 
Norway
 
available
West Prospero
2007
 
400
 
30,000
 
Malaysia
 
available
West Vigilant
2008
 
350
 
30,000
 
Malaysia
 
available
West Ariel
2008
 
400
 
30,000
 
United Arab Emirates
 
available
West Freedom
2009
 
350
 
30,000
 
Colombia
 
available
West Cressida
2009
 
375
 
30,000
 
Thailand
 
January 2020
West Callisto
2010
 
400
 
30,000
 
Saudi Arabia
 
June 2019
West Leda
2010
 
375
 
30,000
 
Malaysia
 
available
West Elara
2011
 
450
 
40,000
 
Norway
 
September 2027
West Castor
2013
 
400
 
30,000
 
Suriname
 
January 2020
West Telesto
2013
 
400
 
30,000
 
India
 
March 2019
West Tucana
2013
 
400
 
30,000
 
Qatar
 
December 2019
AOD I (ii)
2013
 
400
 
30,000
 
Saudi Arabia
 
June 2019
AOD II   (ii)
2013
 
400
 
30,000
 
Saudi Arabia
 
July 2019
AOD III   (ii)
2013
 
400
 
30,000
 
Saudi Arabia
 
December 2019
West Linus (i)
2014
 
450
 
40,000
 
Norway
 
December 2028
Our drilling units have been pledged as collateral for our borrowing facilities. Please refer to Note 22 to the Consolidated Financial Statements included in this report for further details.
As of February 28, 2019 , we wholly-owned all the drilling rigs in our fleet noted in the tables above, except as follows:
i.
The jack-up rig West Linus and the semi-submersible rigs West Hercules and West Taurus are owned by wholly-owned subsidiaries of Ship Finance and leased to us under capital leases. We consolidate the Ship Finance rig owning entities for these rigs under the variable interest model. Please see Note 35 to the Consolidated Financial Statements included in this report for further details of these arrangements.
ii.
We own a 66.23% interest in the jack-up rigs AOD I , AOD II and AOD III . Please see ITEM 4C "Organizational Structure" for further details.
2) Newbuildings
In addition to the drilling units above, we have an option to acquire the semi-submersible rig Sevan Developer . The following table sets out details of this rig.
Unit
Rig type
 
Water depth (feet)
 
Drilling depth (feet)
 
Area of location
 
Status
Sevan Developer
Semi-submersible
 
10,000
 
40,000
 
Cosco Shipyard (China)
 
Under construction
In July 2017, we agreed with Cosco to defer the Sevan Developer delivery period until June 30, 2020. The rig will remain in China at the Cosco Shipyard during which time we retain the right to market the rig and acquire the rig at the original contracted amount. The termination agreement also gives Cosco a right to terminate the contract.
We previously had newbuild contracts for eight jack-up rigs with the Dalian shipyard. Please see the "capital commitments" section within ITEM 5B and Note 33 - Commitments and Contingencies for further details.
3) Office and Equipment
We lease offices and other properties in several locations including Stavanger and Oslo in Norway, Singapore, Houston in the United States, Rio de Janeiro in Brazil, Dubai in the United Arab Emirates and Aberdeen, Liverpool and London in the United Kingdom. Our Consolidated Balance Sheet includes office equipment, IT equipment and leasehold improvements held in these locations.


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ITEM 4A.
UNRESOLVED STAFF COMMENTS

None.


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ITEM 5.
OPERATING AND FINANCIAL REVIEW

In this section, we present management’s discussion and analysis of results of operations and financial condition. It should be read in conjunction with our Consolidated Financial Statements and accompanying notes thereto included herein. You should also carefully read the following sections of this annual report entitled “Cautionary Statement Regarding Forward-Looking Statements,” Item 3 - "Key Information—A. Selected Financial Data", Item 3 "Key Information—D. Risk Factors” and Item 4 "Information on the Company”.
Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and are presented in U.S. dollars unless otherwise indicated. We refer you to the notes to our Consolidated Financial Statements for a discussion of the basis on which our Consolidated Financial Statements are prepared.
1) Introduction
We are an offshore drilling contractor providing worldwide offshore drilling services to the oil and gas industry. For a detailed description of our business please read ITEM 4B - "Business Overview".
2) Chapter 11 Reorganization and Application of Fresh Start Accounting
In this section we have provided a summarized description of our Chapter 11 Reorganization below, together with an overview of Fresh Start Accounting which we applied on emergence from Chapter 11. Please read ITEM 4A - "History and Development of the Company" for a detailed description of the Chapter 11 Reorganization.
i.
Chapter 11 Reorganization
Prior to the filing of Chapter 11 Proceedings (as defined below), we were engaged in extensive discussions with our secured lenders, certain holders of our unsecured bonds and potential new money investors regarding the terms of a comprehensive restructuring. The objectives of the restructuring were to build a bridge to a recovery and achieve a sustainable capital structure. To achieve this, we had proposed an extension to our bank maturities, reduced debt amortization payments, amendments to financial covenants and raising of new capital.
On September 12, 2017, Old Seadrill Limited, certain of its subsidiaries (together "the Company Parties ") and certain Ship Finance companies entered into a restructuring support and lock-up agreement (" RSA ") with a group of bank lenders, bondholders, certain other stakeholders, and new-money providers. In connection with the RSA, the Company Parties entered into an " Investment Agreement " under which Hemen Investments Limited, an affiliate of Old Seadrill Limited's largest shareholder Hemen Holding Ltd. and certain other commitment parties, committed to provide $1.06 billion in new cash commitments, subject to certain terms and conditions (the " Capital Commitment ").
On September 12, 2017, to implement the transactions contemplated by the RSA and Investment Agreement, Old Seadrill Limited and certain of its subsidiaries (the " Debtors ") commenced prearranged reorganization proceedings (the " Chapter 11 Proceedings ") under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas Victoria Division. During the bankruptcy proceedings, the Debtors continued to operate the business as debtors in possession.
After September 12, 2017, the Debtors negotiated with their various creditors and on February 26, 2018 announced a " Global Settlement" , following which there were amendments to the RSA and Investment Agreement. These amendments provided for, amongst other things, the inclusion of certain other creditors as Commitment Parties, an increase of the Capital Commitment to $1.08 billion, increased recoveries for general unsecured creditors under the Plan and an agreement regarding allowed claims from certain newbuild shipyards.
On February 26, 2018, the Debtors filed a proposed Second Amended Joint Chapter 11 Plan of Reorganization (the " Plan ") with the Bankruptcy Court. The Plan was confirmed by the Bankruptcy Court on April 17, 2018. The Plan became effective and the Debtors emerged from Chapter 11 Proceedings on July 2, 2018 (the " Effective Date ").
The Plan extinguished approximately $2.4 billion in unsecured bond obligations, more than $1.0 billion in contingent newbuild obligations, substantial unliquidated guarantee obligations, and approximately $250 million in unsecured interest rate and currency swap claims, while extending near term debt maturities, providing Seadrill with over $1.0 billion in new capital and leaving employee, customer and ordinary trade claims largely unimpaired.
ii.
Application of Fresh Start Accounting
Upon emergence from Chapter 11 bankruptcy, on July 2, 2018, we adopted fresh start accounting in accordance with the provisions set forth in ASC 852, Reorganizations. Adopting fresh start accounting results in a new financial reporting entity with no retained earnings or deficits brought forward. Upon the adoption of fresh start accounting, our assets and liabilities were recorded at their fair values which differ materially from the recorded values of our assets and liabilities as reflected in the Predecessor historical Consolidated Balance Sheets. The effects of the Plan and the application of fresh start accounting were applied as of July 2, 2018 and the new basis of our assets and liabilities are reflected in our Consolidated Balance Sheet as of December 31, 2018 and the related adjustments thereto were recorded in the Consolidated Statement of Operations of the Predecessor as "Reorganization items" during the 2018 Predecessor period.

Accordingly, our Consolidated Financial Statements for periods after July 2, 2018 are not and will not be comparable to the Predecessor Consolidated Financial Statements prior to July 1, 2018. Our Consolidated Financial Statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on July 2, 2018 and dates prior. Our financial results for future periods following the application of fresh start accounting will be different from historical trends and the differences may be material.

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Refer to Note 5 – Fresh Start Accounting to our Consolidated Financial Statements included herein.
3) Changes to our fleet
The below table shows the number of operational drilling units included in our fleet for each of the periods covered by this report.
 
 
Successor
 
Predecessor
Operational drilling units
 
December 31, 2018
 
December 31, 2017
 
December 31, 2016
Drillships
 
7
 
7
 
7
Semi-submersible rigs
 
12
 
12
 
12
Total floaters
 
19
 
19
 
19
Jack-up rigs
 
16
 
16
 
19
Total operational units
 
35
 
35
 
38
In 2017, we sold three jack-ups, West Triton, West Mischief and West Resolute, to Shelf Drilling for an aggregate consideration of $225 million and recorded a loss on disposal of $166 million.
The below table shows the number of newbuildings for each of the periods covered by this report.
 
 
Successor
 
Predecessor
Number of units
 
December 31, 2018

 
December 31, 2017
 
December 31, 2016
Drillships
 
—

 
4
 
4
Semi-submersible rigs
 
1
 
2
 
3
Total floaters
 
1
 
6
 
7
Jack-up rigs
 
2
 
8
 
8
Total operational units
 
3
 
14
 
15
Drillships decreased by four during 2018 due to the rejection and termination of the newbuild contracts for the West Dorado, West Draco, West Aquila and the West Libra in accordance with the Global Settlement (described above). In return, the counterparties to these contracts, Samsung Heavy Industries Co., Ltd. (" Samsung ") and Daewoo Shipbuilding & Marine Engineering Co., Ltd (" DSME "), received an allowed claim and became Commitment Parties to the Investment Agreement. At December 2017, we recorded a liability of $1,064 million for the allowed claim and impairment of $696 million against the newbuild assets we had previously recorded for those rigs.
Semi-submersible newbuild rigs decreased by one during 2017 relating to a settlement agreement reached with Hyundai Samho Heavy Industries Co Ltd. (" HSHI ") for the West Mira . A cash payment of $170 million was received in March 2017 as full settlement of the dispute. We recorded a $31 million impairment and $13 million reversal of interest income in December 31, 2016 in relation to this transaction.
On May 9, 2018, the semi-submersible newbuild, West Rigel, was sold by Jurong Shipyard Pte Ltd. (" Jurong ") and we received a share of proceeds totaling $126 million. We recorded a $2 million loss on disposal for this transaction at December 31, 2017 .
Jack-up newbuild rigs decreased by six during 2018 due to terminations of Newbuild contracts between us and the Dalian Shipyard. Please refer to Note 33 - Commitments and Contingencies for further details.
Please read "ITEM 4D. - Property, Plant and Equipment" for further information on our operational drilling units and newbuilds at December 31, 2018 .

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4) 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)
 
Successor
 
Predecessor
Contract backlog
 
February 28, 2019

 
March 31, 2018

 
February 24, 2017

Floaters
 
565

 
802

 
1,752

Jack-ups
 
1,362

 
1,628

 
785

Total
 
1,927

 
2,430

 
2,537

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 February 28, 2019 contract backlog to unwind over the following periods.
(In $ millions)
 
 
 
For the years ending December 31,
Contract backlog
 
Total

 
2019

 
2020

 
2021

 
Thereafter

Floaters
 
565

 
472

 
93

 
—

 
—

Jack-ups
 
1,362

 
177

 
144

 
141

 
900

Total
 
1,927

 
649

 
237

 
141

 
900

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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A.
RESULTS OF OPERATIONS
The 2018 Successor period, the 2018 Predecessor period and the year ended 2017
The tables included below set out financial information for the periods presented. The 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 or prior periods. We have therefore not made comparisons between accounting measures in non-comparable periods. We have made comparisons for non-accounting driven performance indicators, where applicable.
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Operating revenues
 
541

 
712

 
2,088

Operating expenses
 
(737
)
 
(918
)
 
(1,902
)
Other operating items
 
21

 
(407
)
 
(914
)
Operating loss
 
(175
)
 
(613
)
 
(728
)
Interest expense
 
(261
)
 
(38
)
 
(285
)
Reorganization items
 
(9
)
 
(3,365
)
 
(1,337
)
Other income and expense
 
(152
)
 
161

 
(686
)
Loss before income taxes
 
(597
)
 
(3,855
)
 
(3,036
)
Income tax expense
 
(8
)
 
(30
)
 
(66
)
Net loss
 
(605
)
 
(3,885
)
 
(3,102
)
1) Operating revenues
Total 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
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Contract revenues
 
469

 
619

 
1,888

Reimbursable revenues
 
26

 
21

 
38

Other revenues
 
46

 
72

 
162

Operating revenues
 
541

 
712

 
2,088

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
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Floaters
 
307

 
437

 
1,283

Jack-ups
 
162

 
182

 
605

Contract revenues
 
469

 
619

 
1,888

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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Table of Contents

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
(Number)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Floaters
 
7

 
10

 
8

Jack-ups
 
8

 
8

 
11

Average number of rigs on contract
 
15

 
18

 
19

The average number of floaters on contract increased by two between the year ended 2017 and the 2018 Predecessor period primarily due to the reactivation of the West Hercules which started work in the North Sea in April 2018 and the West Saturn commencing a new contract with Equinor in Brazil in February 2018.
The average number of floaters on contract decreased by three between the 2018 Predecessor period and the 2018 Successor period primarily due to the West Carina and Sevan Brazil completing their contracts with Petrobras in Brazil and the West Eclipse completing its contract with ExxonMobil in Angola.
The average number of jack-ups on contract decreased by three between the year ended 2017 and the 2018 Predecessor period primarily due to the West Tucana, West Cressida and West Ariel completing their contracts in 2017 and early 2018.
The average number of jack-ups on contract was unchanged between the 2018 Predecessor period and the 2018 Successor period as the West Cressida and West Tucana started work on new contracts in July 2018 and October 2018 which was offset by West Castor completing its 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 days for the reporting period. We have set out the average contractual dayrates for the periods presented in the below table:
 
 
Successor
 
Predecessor
(In $ thousands)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Floaters
 
231

 
279

 
395

Jack-ups
 
106

 
131

 
150

The average contractual dayrate for floaters decreased by $116k per day between the year ended 2017 and the 2018 Predecessor period primarily due to the completion of legacy contracts on the West Neptune and West Gemini which were replaced with lower dayrate contracts.
The average dayrate for floaters decreased by $48k per day between the 2018 Predecessor and 2018 Successor periods primarily 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 $19k per day between the year ended 2017 and the 2018 Predecessor period primarily due to the West Elara moving to a lower dayrate as part of securing a long term contract with ConocoPhillips in Norway and the West Tucana and West Ariel completing legacy contracts.
The average dayrate for jack-ups decreased by $25k per day between 2018 Predecessor and 2018 Successor periods 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 its 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 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 95% to 99% for each of the periods presented.
 
 
Successor
 
Predecessor
(Percentage)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Floaters
 
95
%
 
95
%
 
97
%
Jack-ups
 
99
%
 
98
%
 
98
%
b) Reimbursable revenues
We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel and other services provided at their request in accordance with a drilling contract. We classify such revenues as reimbursable revenues.
c) Other revenues
Other revenues include the following:
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Related party revenues ( i )
 
46

 
43

 
110

Amortization of unfavorable contracts ( ii )
 
—

 
21

 
43

Other ( iii )
 
—

 
8

 
9

Other revenues
 
46

 
72

 
162

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 2018 Predecessor period and the year ended 2017 included early termination fee revenue for the West Pegasus and West Hercules, respectively.

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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
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Vessel and rig operating expenses
 
(357
)
 
(407
)
 
(792
)
Depreciation
 
(236
)
 
(391
)
 
(798
)
Amortization of intangibles
 
(58
)
 
—

 
—

Reimbursable expenses
 
(24
)
 
(20
)
 
(35
)
General and administrative expenses
 
(62
)
 
(100
)
 
(277
)
Operating expenses
 
(737
)
 
(918
)
 
(1,902
)
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. Vessel and rig expenses for the periods presented include several significant one-time items as follows:
Vessel and rig expenses for jack-ups in the 2018 Predecessor period included a bad debt expense of $48 million relating to an overdue receivable. This receivable was not recognized as part of fresh start accounting in the 2018 Successor period. We subsequently recovered $21 million on November 27, 2018 and a further $26 million on January 10, 2019 which is recognizable on receipt within "other operating income" (see section 3 below).
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 Successor periods are therefore not comparable.
We have analyzed vessel and rig operating expenses by segment in the table below.
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Floaters
 
223

 
239

 
480

Jack-ups
 
119

 
158

 
286

Other
 
15

 
10

 
26

Vessel and rig operating expenses
 
357

 
407

 
792

Excluding the effect of the one-time items discussed above, 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.
As set out in the revenue section above for the year ended 2017, we had an average of 19 rigs in operation, nine cold stacked floaters, one warm stacked floater, four cold stacked jack ups and two warm stacked jack ups.
In the 2018 Predecessor period we reactivated one floater, the West Hercules, as it returned to work. In the 2018 Successor period, the Sevan Driller was cold stacked and the West Carina and West Eclipse were warm stacked following completion of their contracts. This was offset by the Sevan Louisiana returning to operations and more days in operation for the West Phoenix and West Hercule s.
In the 2018 Predecessor period, we cold stacked the West Ariel which was offset by the West Telesto starting its contract in April 2018. In the 2018 Successor period, the West Tucana and West Cressida started operations, offset by the West Castor becoming warm stacked after completion of its contract.

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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 when we (i) applied fresh start accounting on emergence from Chapter 11 and (ii) recorded long-lived asset impairments against the West Alpha , West Navigator and West Epsilon at June 30, 2018. The depreciation expense for 2018 Successor period is therefore based on lower carrying values of drilling units and equipment and is not comparable to the level of depreciation expense recorded in the Predecessor periods.
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 in section 2 above, we changed the classification of certain support function costs for periods after emergence. General and administrative expenses for the 2018 Successor period is therefore not comparable to the level of expense recorded in the Predecessor.
3) Other operating items
Other operating items include impairments of long-lived assets, loss on sale of assets and other operating income. We have analyzed other operating items between these categories in the below table:
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Loss on impairment of long-lived assets
 
—

 
(414
)
 
(696
)
Loss on sale of assets
 
—

 
—

 
(245
)
Other operating income
 
21

 
7

 
27

Other operating items
 
21

 
(407
)
 
(914
)
i.
Impairment of long-lived assets
In the year ended 2017, as part of the Chapter 11 re-organization, we terminated the newbuild contracts for the drillships West Draco , West Dorado , West Aquila and West Libra and the shipyards, Samsung and DSME, received an allowed claim. As a result, we recorded a $696 million non-cash impairment charge against the newbuild assets for these rigs. We also recorded a reorganization expense of $1,064 million for the allowed claim (see section 5 below).
In the 2018 Predecessor period, we determined that the continuing downturn in the offshore drilling market was an indicator of impairment on certain assets. Following an assessment of recoverability, we recorded an impairment charge of $414 million against three of our older rigs.
ii.
Loss on sale of assets
The loss on sale of assets for the year ended 2017 was due to the sale of the West Triton, West Mischief and West Resolute to Shelf Drilling, recognizing a loss on disposal of $166 million, and the derecognition of the Sevan Developer , following renegotiated terms with Cosco which deemed us to have lost control of the asset, resulting in a $75 million loss.
iii.
Other income
Other income for the year ended 2017 and the 2018 Predecessor period represents amounts recognized for contingent consideration from the sales of the West Vela and West Polaris to Seadrill Partners in 2014 and 2015. On emergence from Chapter 11 we recognized receivables equal to the fair value of expected future cash flows under these arrangements and have therefore not recognized further income in the 2018 Successor period.
Other income for the 2018 Successor period relates to a $21 million overdue receivable that was collected in the quarter which had not been recognized as an asset as part of fresh start accounting. We recovered a further $26 million on January 10, 2019. We determined that the second receipt was a non-adjusting subsequent event and will recognize the income in 2019.

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Table of Contents

4) Interest expense
We have analyzed interest expense into the following components:
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Cash and payment-in-kind interest on debt facilities
 
(237
)
 
(37
)
 
(286
)
Unwind of discount on debt
 
(24
)
 
—

 
—

Loan fee amortization
 
—

 
(1
)
 
(27
)
Capitalized interest
 
—

 
—

 
28

Interest expense
 
(261
)
 
(38
)
 
(285
)
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
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Senior credit facilities and unsecured bonds
 
(162
)
 
(116
)
 
(320
)
Less: adequate protection payments
 
—

 
104

 
81

New secured notes
 
(50
)
 
—

 
—

Debt of consolidated variable interest entities
 
(25
)
 
(25
)
 
(47
)
Cash and payment-in-kind interest
 
(237
)
 
(37
)
 
(286
)
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, under the terms of the Plan. There has also been an increase in LIBOR rates over the second half of 2018. Both factors increased the effective interest rate on our senior credit facilities.
During the period we were in Chapter 11 (September 12, 2017 to July 1, 2018), 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 (classified under reorganization items - see section 5 below).
On emergence from Chapter 11 we issued $880 million of New Secured Notes. We incur 4% cash interest and 8% payment-in-kind interest on these notes.
Our Consolidated Balance Sheet includes approximately $1 billion of debt facilities held by subsidiaries of Ship Finance that we consolidate as variable interest entities. Our interest expense includes the interest incurred by these entities on those facilities .
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. We expensed capitalized loan issuance costs for debt subject to compromise when we filed for Chapter 11 on September 12, 2017. Loan fee amortization expense is therefore not comparable between these periods.
iv.
Capitalized interest
We capitalize the interest cost incurred to finance Newbuilds. We ceased capitalization of interest on Newbuilds when we filed for Chapter 11 on September 12, 2017.

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5) Reorganization items
We have analyzed reorganization items into the following components:
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
December 31, 2017

Professional and advisory fees
 
(9
)
 
(187
)
 
(66
)
New investor commitment fees
 
—

 
—

 
(53
)
Gain on liabilities subject to compromise
 
—

 
2,958

 
—

Fresh start valuation adjustments
 
—

 
(6,142
)
 
—

Loss on Newbuilding global settlement claim
 
—

 
—

 
(1,064
)
Loss on other pre-petition allowed claims
 
—

 
—

 
(3
)
Write-off of debt issuance costs
 
—

 
 
 
(66
)
Reversal of credit risk on derivatives
 
—

 
—

 
(89
)
Interest income on surplus cash invested
 
—

 
6

 
4

Total reorganization items, net
 
(9
)
 
(3,365
)
 
(1,337
)
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 compromise 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.
You can find additional detail on reorganization items in Note 4 to the Consolidated Financial Statements included within this report.
6) Other income and expense
We have analyzed other income and expense into the following components:
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
December 31, 2017

Interest income
 
40

 
19

 
60

Share in results from associated companies
 
(90
)
 
149

 
174

Impairment of investments
 
—

 
—

 
(841
)
(Loss) / gain on derivative financial instruments
 
(31
)
 
(4
)
 
11

Gain on debt extinguishment
 
—

 
—

 
19

Foreign exchange loss
 
(4
)
 
—

 
(65
)
Loss on marketable securities
 
(64
)
 
(3
)
 
—

Other financial items
 
(3
)
 
—

 
(44
)
Other income and expense
 
(152
)
 
161

 
(686
)
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 and $4 million for the year ended 2017.

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ii.
Share of results in associated companies
Share of results in associated companies represents our share of earnings or losses in our investments accounted under the equity method. We reduced the carrying value of our equity method investments when we applied fresh start accounting on emergence from Chapter 11. This led to the recognition of basis differences between the book value of the drilling unit or pipe laying service vessel and contract intangible balances recorded in the balance sheets of our equity method investees and the implied value of those assets reflected in the equity method investments recorded in our Consolidated Balance Sheet. We unwind these basis differences over the lives of the associated assets and liabilities when calculating our share of results of the equity method investments. Therefore, the share of results in associated companies for the 2018 Successor period is not comparable to the share of results in associated companies recorded in the Predecessor company.
We have analyzed our share of results in associated companies by equity method investment below:
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
December 31, 2017

Seadrill Partners
 
(102
)
 
99

 
104

Seamex
 
(12
)
 
4

 
—

Seabras Sapura
 
24

 
46

 
80

Archer
 
—

 
—

 
(10
)
Share of results from associated companies
 
(90
)
 
149

 
174

The share in after tax loss of associated companies for the 2018 Successor period reflects a share in after-tax profits of our investments in Seabras Sapura joint venture offset by a share of losses in our investments in Seadrill Partners and SeaMex. This includes a net expense for the unwind of basis differences of $57 million . The results of Seadrill Partners included an income tax expense of $87 million, which was primarily due to an uncertain tax position related to US tax reform.

The share in after-tax profit for 2018 Predecessor period reflected our share of the after-tax profit of each of our equity method investments. Our share in the after-tax profit of Seadrill Partners included the benefit of a litigation ruling in the favor of Seadrill Partners. Seadrill Partners recorded net income totaling approximately $220 million in June 2018 for this ruling .
The share of results from associated companies for the year ended 2017 reflected our share of the net income from Seadrill Partners, and Seabras Sapura, offset by our share of the loss of Archer. From April 2017 onwards, we reclassified our investment in Archer from an equity method investment to an investment in marketable security. Please see Note 15 of the enclosed financial statements for further details on this transaction.
iii.
Impairment of investments
As at December 31, 2017, the carrying value of the Seadrill Partners subordinated units was found to exceed the fair value by $82 million, and the carrying value of the direct ownership interests in Seadrill Partners was found to exceed the fair value by $723 million. Additionally, the carrying value of the investment in SeaMex was found to exceed the fair value by $36 million. The fair value was derived using a discounted cash flow model. We recorded these impairments within “Loss on impairment of investments” in the Consolidated Statement of Operations.

The assumptions used in the DCF model were derived from significant unobservable inputs (representative of Level 3 inputs for Fair Value Measurement) and are based on management’s judgments and assumptions available at the time of performing the impairment test.
iv.
(Loss) gain on derivative financial instruments
The loss on derivatives in the 2018 Successor period of $31 million comprised a fair value loss of $22 million on our interest rate cap derivatives and a $9 million fair value loss on the conversion option associated with a convertible bond we hold in Archer. The fair value loss on the interest rate cap was caused by a decrease in forward interest rates. The fair value loss on the Archer conversion option was caused by a decrease in Archer's share price.
The loss on derivatives in the 2018 Predecessor period of $4 million comprised a fair value loss of $6 million on our interest rate cap derivatives offset by a $2 million fair value gain on the conversation option on the Archer convertible bond.
The gain on derivatives in the year ended 2017 of $11 million related to net gains on the interest rate swap and cross currency swap agreements that we previously used to mitigate exposures to interest rate risk and foreign exchange risk on our debt prior to filing for Chapter 11.
v.
Gain on debt extinguishment
On April 26, 2017, we converted $146 million, including accrued interest and fees, in subordinated loans provided to Archer into a $45 million subordinated convertible loan. We recognized a gain on debt extinguishment equal to the difference between the fair value of the convertible loan we received and the previous carrying value of the loan, accrued interest and fees that were extinguished. This was a gain of $19 million.

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Table of Contents

vi.
Foreign exchange loss
Foreign exchange gains and losses relate to exchange differences on the settlement or revaluation of monetary balances denominated in currencies other than the US Dollar. Prior to filing for Chapter 11 on September 12, 2017, our foreign exchange exposure was primarily driven by NOK and SEK denominated unsecured bonds. These bonds were no longer revalued after we filed for Chapter 11 and were extinguished through the Chapter 11 restructuring.
vii.
Loss on marketable securities
The loss on marketable securities in the 2018 Successor and 2018 Predecessor periods reflect the changes in mark to market movements in our investments in Seadrill Partners common units and our Archer shares.
We did not record a gain or loss on our investments in marketable securities, within income and expense, for the year-ended 2017. This was because, for all periods before we adopted ASU 2016-10 on January 1, 2018, we recorded fair value gains and losses on marketable securities in other comprehensive income until they were realized.
viii.
Other financial items
Other financial items for the 2018 Successor period of $3 million included several minor items of expense including rig postponement costs and legal and advisory expenses connected to financing transactions.
We did not incur significant other financial items for the 2018 Predecessor period.
Other financial items for the year ended 2017 primarily comprised pre-petition professional and advisory fees related to our reorganization (after filing for Chapter 11 we classified such costs as reorganization items - see section 5 above).
7) Income tax expense
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.


Year-ended December 31, 2017 (Predecessor) compared to Year-ended December 31, 2016 (Predecessor)
The following table sets forth our operating results (by segment) for 2017 and 2016.
 
Year ended December 31, 2017
 
Year ended December 31, 2016
(In $ millions)
Floaters

 
 Jack-
up rigs

 
Other

 
Total

 
Floaters

 
 Jack-
up rigs

 
Other

 
Total

Total operating revenues
1,387

 
617

 
84

 
2,088

 
2,212

 
865

 
92

 
3,169

Loss on disposals
(79
)
 
(166
)
 
—

 
(245
)
 
—

 
—

 
—

 
—

Contingent consideration realized
27

 
—

 
—

 
27

 
21

 
—

 
—

 
21

Total operating expenses (excluding impairment of long-lived assets)
(1,261
)
 
(563
)
 
(78
)
 
(1,902
)
 
(1,430
)
 
(598
)
 
(92
)
 
(2,120
)
Loss on impairment of long-lived assets
(696
)
 
—

 
—

 
(696
)
 
(44
)
 
—

 
—

 
(44
)
Operating (loss)/income
(622
)
 
(112
)
 
6

 
(728
)
 
759

 
267

 
—

 
1,026

Interest expense
 
 
 
 
 
 
(285
)
 
 

 
 

 
 
 
(412
)
Impairment of investments
 
 
 
 
 
 
(841
)
 
 
 
 
 
 
 
(895
)
Reorganization Items, net
 
 
 
 
 
 
(1,337
)
 
 
 
 
 
 
 
—

Other financial items
 
 
 
 
 
 
155

 
 

 
 

 
 
 
325

(Loss)/ income before taxes
 
 
 
 
 
 
(3,036
)
 
 

 
 

 
 
 
44

Income taxes
 
 
 
 
 
 
(66
)
 
 

 
 

 
 
 
(199
)
Net loss
 
 
 
 
 
 
(3,102
)
 
 

 
 

 
 
 
(155
)

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Table of Contents

1) Total operating revenues
(In $ millions)
2017

 
2016

 
Change

Floaters
1,387

 
2,212

 
(37
)%
Jack-up rigs
617

 
865

 
(29
)%
Other
84

 
92

 
(9
)%
Total operating revenues
2,088

 
3,169

 
(34
)%
Total operating revenues were $2.1 billion for 2017, compared to $3.2 billion in 2016, a decrease of $1.1 billion, or 34%. Total operating revenues are predominantly contract revenues with additional amounts of reimbursable and other revenues. The decrease in total operating revenues compared to 2016 was primarily driven by an increase in the number of idle rigs and reductions in certain operating dayrates.
Total operating revenues in the floaters segment were $1.4 billion in 2017 compared to $2.2 billion in 2016, a decrease of $0.8 billion, or 37%. The decrease primarily resulted from the increase in the number of idle rigs and reductions in certain operating dayrates. The average number of floaters on contract and operating in 2017 was 8, compared to 12 in 2016. The average contracted dayrates earned by the floaters was $395,000 during 2017 compared to $445,000 during 2016. We also received the early termination fee for the West Hercules of $66 million, of which $8 million was recognized in 2017 and $58 million recognized in 2016.
Total operating revenues in the jack-up rigs segment were $0.6 billion in 2017 compared to $0.9 billion in 2016, a decrease of $0.3 billion, or 29%. The decrease was primarily due to an increase in the number of idle rigs and reductions in certain operating dayrates. The average number of jack-ups on contract and operating in 2017 was 9, compared to 12 in 2016. The average contracted dayrates earned by the jack-ups was $150,000 during 2017 compared to $170,000 during 2016. In addition, we disposed of the West Triton, West Mischief and West Resolute to Shelf Drilling. We also recognized an early termination fee for the West Epsilon of $11 million in 2016.
2) Loss on disposals
In 2017 we recorded a net loss on disposals of $245 million. In April 2017 we agreed to sell the West Triton, West Mischief and West Resolute to Shelf Drilling, recognizing a loss on disposal of $166 million. In July 2017 we amended the contractual agreement with Cosco for the Sevan Developer . Due to the renegotiated terms, we deemed to have lost control of the asset and the newbuilding was derecognized, resulting in a $75 million loss on disposal. In April 2018 we entered into a settlement and release agreement, subject to Bankruptcy Court approval, with Jurong for the West Rigel . To reflect our agreed share of sales proceeds in the value of the asset held for sale, we recognized a $2 million loss on disposal.
In 2016, we did not record any material gains or losses on the disposal of assets.
3) Contingent consideration realized
In 2017 we recorded contingent consideration realized of $27 million (2016: $21 million) relating to the disposals of the West Polaris and West Vela.
4) Total operating expenses (excluding loss on impairment of long-lived assets)
(In $ millions)
2017

 
2016

 
Change

Floaters
1,261

 
1,430

 
(12
)%
Jack-up rigs
563

 
598

 
(6
)%
Other
78

 
92

 
(15
)%
Total operating expenses (excluding loss on impairment of long-lived assets)
1,902

 
2,120

 
(10
)%
Total operating expenses, excluding loss on impairment of long-lived assets, were $1,902 million in 2017 compared to $2,120 million in 2016, a decrease of $218 million or 10%. Total operating expenses consist of vessel and rig operating expenses, depreciation and amortization, reimbursable expenses and general and administrative expenses. The decrease in operating expenses resulted from a reduced number of drilling units in operation in 2017 as compared to 2016.
Total operating expenses, excluding loss on impairment of long-lived assets, for the floaters segment were $1,261 million in 2017 compared to $1,430 million in 2016, a decrease of $169 million, or 12%. This decrease was mainly related to the decrease in the number of operating units during the period.
Total operating expenses, excluding loss on impairment of long-lived assets, for the jack-up rigs segment were $563 million in 2017 compared to $598 million in 2016, a decrease of $35 million, or 6%. This decrease was mainly related to the decrease in the number of operating units during the period.
Other operating expenses predominately relate to costs associated with the provision of management services to external parties and related parties.

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5) Loss on impairment of long-lived assets
As part of the Chapter 11 proceedings, the Debtors negotiated and announced a global settlement with various creditors, including Samsung Heavy Industries Co., Ltd. ("Samsung") and Daewoo Shipbuilding & Marine Engineering Co., Ltd ("DSME"). The global settlement included an agreement regarding the allowed claim of the newbuild shipyards Samsung and DSME, and the Debtors’ rejection and recognized termination of the newbuild contracts for the West Dorado, West Draco, West Aquila and the West Libra . As our plan of reorganization anticipated the rejection and termination of the newbuild contracts we recognized an impairment of the newbuild assets related to the West Dorado, West Draco, West Aquila and the West Libra, totaling $696 million, in the year ended December 31, 2017.
In 2016 a total of $44 million of impairments were recorded against the West Mira , following the settlement of the arbitration, as well as other impairments as a result of revisions to costs capitalized in our capital spares pool .
6) Interest expense
Interest expense was $285 million in 2017 compared to $412 million in 2016, a decrease of $127 million, or 31%. The decrease is mainly due to post-petition contractual interest expenses of $81 million related to debt held as subject to compromise which have not been recognized in the Consolidated Statement of Operations, but instead recorded as a reduction to debt principal value in the Consolidated Balance Sheet.
7) Other financial items
Other financial items, excluding interest expense, reported in the Statement of Operations include the following items: 
(In $ millions)
2017

 
2016

Interest income
60

 
66

Share in results of associated companies (net of tax)
174

 
283

Loss on impairment of investments
(841
)
 
(895
)
Gain/(loss) on derivative financial instruments
11

 
(74
)
Net gain on debt extinguishment
19

 
47

Foreign exchange (loss)/gain
(65
)
 
18

Reorganization items, net
(1,337
)
 
—

Other financial items and other (expense)/income, net
(44
)
 
(15
)
Total financial items and other (expense)/income, net
(2,023
)
 
(570
)
Share in results from associated companies was an income of $174 million in 2017 compared to income of $283 million in 2016. The income mainly comprised our share of income from Seadrill Partners, as well as SeaMex and Seabras Sapura. The decrease is primarily due to the decreased share of income from Seadrill Partners as a result of a decrease in the number of operating units and rigs and a reduction in certain operating dayrates.
During 2017 we recorded an "other than temporary" impairment of investments of $841 million, compared to an other than temporary impairment of investments of $895 million in 2016. The impairments relate to our investments in Seadrill Partners and SeaMex in both years. Refer to Note 11 - "Impairment loss on marketable securities and investments in associated companies" to our Consolidated Financial Statements included herein for further information.
The gain on derivative financial instruments was $11 million in 2017, compared to a loss of $74 million in 2016. The gain in 2017 was primarily due to gains of $46 million on our cross-currency interest swaps which were partially offset by a loss of $30 million on our interest rate swap agreements due to unfavorable movement in swap interest rates during the year and a loss on other derivatives of $5 million. On filing for Chapter 11, we triggered an event of default under our swap agreements, resulting in the termination of our derivatives by our counterparties on September 13, 2017. The loss on derivative financial instruments in 2016 was mainly related to a loss of $48 million on our interest rate swap agreements and losses on our cross-currency interest rate swaps of $20 million due to unfavorable movements in our interest rate swap agreements and a loss on our TRS agreements of $6 million.
The results for 2017 included a gain of $19 million of debt extinguishment compared to a gain of $47 million in 2016, of which the 2017 gain is due to the conversion of subordinated loans, fees and interest provided to Archer into a new convertible instrument. The gain recognized in 2016 is related to the extinguishment of our convertible bonds.
Foreign exchange losses amounted to $65 million in 2017 compared to gains of $18 million in 2016. This was mainly due to the revaluation of our NOK-denominated and SEK-denominated bonds to the U.S. dollar.
After the filing of our bankruptcy petition on September 12, 2017, we incurred $66 million of post-petition professional fees associated with the bankruptcy cases. Additionally, we incurred non-cash charges of $66 million relating to unamortized debt issuance costs and $89 million in respect of reversal of issuing entities credit risk on derivatives.
As part of the Chapter 11 proceedings, the Debtors negotiated and announced a global settlement with various creditors, including Samsung Heavy Industries Co., Ltd. ("Samsung") and Daewoo Shipbuilding & Marine Engineering Co., Ltd ("DSME"). The global settlement included an agreement regarding the allowed claim of the newbuild shipyards Samsung and DSME, and the Debtors’ rejection and recognized termination of the newbuild contracts for the West Dorado, West Draco, West Aquila and the West Libra . As the Plan anticipates the rejection and termination

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of the newbuild contracts we have recognized an impairment of the newbuild assets related to the West Dorado, West Draco, West Aquila and the West Libra, totaling $696 million loss through reorganization items, in 2017.
8) Income taxes
Income tax expense was $8 million for the successor period ended December 31, 2018 while predecessor period was $30 million and $66 million for the year ended December 31, 2017.
Our effective tax rate was approximately (1.3)% for the year ended December 31, 2018, compared to (0.8)% for predecessor period ending July 1, 2018 and (2.2)% for the year ended December 31, 2017. This means that we continue to pay tax on consolidated losses after impairments, such that there were tax charges reported on overall losses before tax inclusive of discrete items. The 2018 and 2017 negative rates reflect no tax relief on the impairments or the derivative loss, as well as no tax chargeable on the disposal transactions. This was due to these items largely falling within the zero tax rate on Bermuda companies.

Significant amounts of our income and costs are reported in non-taxable jurisdictions such as Bermuda. Our drilling rig operations are normally carried out in taxable jurisdictions. In the tax jurisdictions where we operate, the corporate income tax rates range from 17% to 34% for earned income and the deemed tax rates vary from 4% to 10% of revenues. Further, losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, our effective tax rate may differ significantly from period to period depending on the level of activity in each of the tax jurisdictions in which our operations are conducted.


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B.
LIQUIDITY AND CAPITAL RESOURCES

1) Introduction
We operate in a capital-intensive industry. We have historically funded acquisitions of drilling units and investments in associated companies through a combination of debt and equity issuances and from cash generated from operations. Although we restructured our debt through the Chapter 11 Reorganization we remain a highly leveraged company with outstanding borrowings on our external debt facilities totaling $7.1 billion as of December 31, 2018 .
Our liquidity requirements relate to servicing our debt, making capital investments, funding working capital requirements and maintaining adequate cash reserves to mitigate the effects of fluctuations in operating cash flows. Most of our contract and other revenues are received between 30 and 60 days in arrears, and most of our operating costs are paid monthly. We believe our current resources, available cash and cash from operations will be sufficient to meet our working capital requirements and other obligations as they fall due for at least the next twelve months.
Our funding and treasury activities are conducted in accordance with our corporate policies, which aim to maximize returns while maintaining appropriate liquidity for our operating requirements. Cash and cash equivalents are held mainly in U.S. dollars, with lesser amounts held in Norwegian Kroner, Brazilian Reais and Great British Pounds.
This section discusses the most important factors affecting our liquidity and capital resources.
2) Liquidity
Our level of liquidity fluctuates depending on a number of factors. These include, among others, our contract backlog, economic utilization achieved, timing of accounts receivable collection, timing of payments for operating costs and other obligations. Our liquidity comprises cash and cash equivalents. The below tables show cash and restricted cash balances for each period presented.
 
 
Successor
 
Predecessor
(In $ millions)
 
December 31, 2018

 
July 1, 2018

 
December 31, 2017

Unrestricted cash
 
1,542

 
1,599

 
1,255

Restricted cash
 
461

 
578

 
104

Cash and cash equivalents, including restricted
 
2,003

 
2,177

 
1,359

We have shown our sources and uses of cash by category of cash flow in the below table.
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Cash flows from operating activities
 
(26
)
 
(213
)
 
399

Cash flows from investing activities
 
61

 
149

 
358

Cash flows from financing activities
 
(208
)
 
887

 
(846
)
Effect of exchange rate changes in cash and cash equivalents
 
(1
)
 
(5
)
 
5

Change in period
 
(174
)
 
818

 
(84
)
This reconciles to the total cash and cash equivalents, including restricted, which is as follows:
 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Opening cash and cash equivalents, included restricted
 
2,177

 
1,359

 
1,443

Change in period
 
(174
)
 
818

 
(84
)
Closing cash and cash equivalents, included restricted
 
2,003

 
2,177

 
1,359


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a) Cash flows from operating activities
Cash flows from operating activities 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)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Net loss
 
(605
)
 
(3,885
)
 
(3,102
)
Adjustments to reconcile net loss to net cash provided by operating activities (1)
 
477

 
3,808

 
3,603

Net loss after adjustments
 
(128
)
 
(77
)
 
501

Payments for long-term maintenance
 
(71
)
 
(78
)
 
(58
)
Distributions received from associated companies
 
32

 
17

 
39

Changes in operating assets and liabilities
 
141

 
(75
)
 
(83
)
Cash flows from operating activities
 
(26
)
 
(213
)
 
399

(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 materially lower levels of spending for offshore exploration and development. This has negatively affected our revenues, profitability and operating cash flows. During the 2018 Successor period and the 2018 Predecessor period 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
Cash flows from investing activities include purchases and sales of newbuildings, drilling units and equipment, investments and sales of investments in unconsolidated entities, cash flows from purchases and sales of debt or marketable securities and certain cash flows from business combinations.
Net cash flows from investing activities for the 2018 Successor period were primarily generated by loan repayments from our joint venture Seabras Sapura, contingent consideration payments from Sapura Energy from the sale of our Tender Rig business in 2014, and contingent consideration payments from Seadrill Partners from sale of the drillship West Vela in 2015. These cash inflows were partly offset by capital expenditures.
Net cash flows from investing activities for the 2018 Predecessor period 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 and West Polaris in 2015, and related party loan repayments from Seadrill Partners. These cash inflows were partly offset by capital expenditures.
Net cash flows from investing activities for the year ended 2017 were driven by cash inflows from the sale of the West Mira newbuild contract, sales of the jack-up rigs West Resolute, West Mischief and West Triton , proceeds from Seadrill Partners for contingent consideration related to the West Vela and West Polaris, payments of interest and principal on loans granted to Seadrill Partners and refunds of Sevan Developer yard installments. This was offset by capital expenditures and a payment to remove guarantees on Archer debt.
c) Cash flows from financing activities
Cash flows from financing activities include proceeds from issue of new equity and payment of cash dividends, proceeds from issuing debt and repayments of debt, payment of debt issue costs, purchases of treasury shares, proceeds from exercise of stock options and cash flows from transactions with non-controlling interests.
Net cash flows from financing activities for the 2018 Successor period were related to repayments of debt contained within three consolidated variable interest entities (VIEs) managed and financed by Ship Finance International Limited from whom we lease rigs under sale and leaseback arrangements.
Net cash flows from financing activities for the 2018 Predecessor period were mainly driven by proceeds from issue of New Secured Notes and new equity on emergence from Chapter 11, offset by repayments of debt contained within our Ship Finance VIEs and debt fees paid on our senior credit facilities.
Net cash flows from financing activities for the year ended 2017 were for repayments of debt and revolving lines of credit and for debt fees paid.

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3) Information on our borrowings
As at December 31, 2018 , we had total outstanding borrowings under our external debt facilities of $7.1 billion . This included senior credit facility debt of $5.7 billion , borrowings on our New Secured Notes of $0.8 billion and debt held by consolidated variable interest entities of approximately $0.6 billion . In addition to our external debt facilities, we had interest bearing debt of $0.3 billion under loan agreements with related parties.
Our credit facilities are secured by, among other things, liens on our drilling units. Our credit facility agreements contain cross-default provisions, meaning that if we defaulted and amounts became due and payable under one of our credit agreements, this would trigger a cross-default in our other facilities so that amounts outstanding under our other credit facility agreements become due and payable and capable of being accelerated.
The New Secured Notes are secured by, among other things, our investments in Seadrill Partners, SeaMex, Seabras Sapura and Archer.
Please refer to Note 22 – "Debt" in the Consolidated Financial Statements included in this report for additional information on our debt facilities as of December 31, 2018 .
4) Capital commitments
At December 31, 2018, we had contractual commitments under two (2017: eight) newbuilding contracts with Dalian totaling $0.4 billion (2017: $1.7 billion). In January 2019, Dalian appointed an administrator to restructure its liabilities.
Contracts for the newbuild jack-up rigs West Titan , West Proteus , West Rhea , West Hyperion , West Tethys and West Umbriel were terminated as of December 31, 2018. Further, in February 2019, the Seadrill contracting party terminated the contract to acquire the jack-up rig West Dione due to: (i) delays to delivery of the rig, and (ii) Dalian being subject to bankruptcy proceedings. In March 2019, Dalian purported to terminate the eighth newbuilding contract for the West Mimas . The Seadrill contracting party rejected Dalian’s termination of the contract as wrongful and reserved all its rights. The Seadrill contracting party will obtain a right to terminate the contract for the West Mimas for delay and claim a refund of the pre-delivery installments plus interest in early April 2019, and it intends to enforce all its rights under the contract as they arise.
In March 2019, the Seadrill contracting parties commenced arbitration proceedings in the UK for all eight rigs and will claim for the return of the paid installments plus interest and further damages for losses. They will also file claims for these amounts as part of the Dalian insolvency. Dalian has maintained it has a damages claim in respect of each of the rigs. The contracts are all with limited liability subsidiaries of Seadrill. There are no parent company guarantees. Apart from the Seadrill contracting parties’ claims for repayment of the paid installments plus interest, no quantification of claims has been made by either party.
In addition to these Newbuild commitments we expect to incur capital expenditures for purchases in the ordinary course of business.

C.
RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES, ETC.

We do not undertake any significant expenditure on research and development and have no significant interests in patents or licenses.


D.
TREND INFORMATION

The below table show the average oil price over the period 2014 to 2018. The Brent oil price at February 28, 2019 was $66.

 
 
2014

 
2015

 
2016

 
2017

 
2018

 
Average Brent oil price ($/bbl)
 
99

 
54

 
45

 
55

 
71

 

We have seen an improvement in the oil and gas market over 2018 with Brent oil prices remaining above $60 per barrel for most of the year. This favorable development in oil prices, combined with efficiencies across the industry, has led to improved economics for our customers. This has in turn led to increased tendering activity and a positive trend in dayrates. We expect these trends to continue in 2019 as our customers continue to increase their levels of investment.

The below table shows the global number of rigs on contract and marketed utilization at December 31, 2018 and for each of the four preceding years.

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2014

 
2015

 
2016

 
2017

 
2018

 
Contracted rigs
 
 
 
 
 
 
 
 
 
 
 
Harsh environment floater
 
48

 
45

 
35

 
30

 
31

 
Benign environment floater
 
232

 
196

 
139

 
120

 
116

 
Jack-up 1
 
190

 
180

 
152

 
154

 
168

 
Marketed utilization
 
 
 
 
 
 
 
 
 
 
 
Harsh environment floater
 
99
%
 
93
%
 
81
%
 
83
%
 
85
%
 
Benign environment floater
 
93
%
 
83
%
 
71
%
 
71
%
 
73
%
 
Jack-up 1
 
95
%
 
83
%
 
70
%
 
70
%
 
74
%
 
1 Jack-up rigs with water depth greater than 350 feet.

Activity has remained subdued over 2018 in the floater market. The harsh environment has higher marketed utilization, continuing to trend ahead of benign environment. There is high demand for high specification harsh environment units relative to their supply, which has led to increased dayrates and higher utilization within this segment. There is still an excess supply of benign environment units which has delayed the recovery in this market.

We have seen a bigger improvement in shallow water markets and this has led to an increase in the number of contracted jack-ups. The increase in demand and dayrates have seen newbuilds begin to enter the market.

Floaters - outlook

Based on the current level of activity, age of the floater fleet and level of consolidation in the industry, we expect scrapping activity to continue. A total of 119 floaters have been scrapped or retired since the beginning of 2014, equivalent to 38% of the total fleet, and currently there are 22 cold or warm stacked units that are 30 years old or older, with no follow-on work identified which are prime scrapping candidates. In the next 18 months, a further 17 units that are 30 years old or older will become available unless they win new work. These units represent additional scrapping candidates. A key rational for scrapping is the 35-year classing expenditures that can cost upwards of $100 million. Many rig owners will choose to retire the unit rather than incur this cost without a visible recovery in demand on the horizon.

Larger drilling companies with diversified fleets will find it easier to make economic decisions and cold stack idle rigs as each individual unit represents a smaller percentage of the overall fleet. Cold stacked units will generally require an improvement in dayrates sufficient to overcome reactivation costs before they are reintroduced into marketed supply.

Marketed utilization is 75% across benign and harsh environment floaters. The global floater order book stands at approximately 42 units, comprised of 28 drillships and 14 semi-submersible rigs. 22 units are scheduled for delivery in 2019, 11 in 2020 and 9 in 2021 and beyond.

Jack-ups - outlook

We saw improved activity levels in the jack-up market during 2018. The shorter-term contract profile in this market lends itself to more rig turnover and the market has likely reached the base level of units required to maintain existing decline curves.

Globally, marketed utilization is 74%. We expect scrapping activity to continue for older units. Currently there are 50 cold stacked units that are 30 years old or older. Additionally, in the next 18 months, 73 units that are 30 years old or older will become available unless they win new work. Together these 123 units, or 24% of the delivered fleet, represent potential scrapping candidates.

78 jack-ups are currently under construction; however, a significant portion of these orders were placed by investors with little or no operating track record. While a number of these speculators may exit projects, these units will eventually reach the market, possibly in the hands of more established companies. The deployment of this incremental supply may be somewhat rationalized in the longer term as the more established players will likely only take delivery when economically viable.

E.
OFF-BALANCE SHEET ARRANGEMENTS
 
We had no off-balance sheet arrangements as at December 31, 2018 or 2017 , other than operating lease obligations and other commitments in the ordinary course of business that we are contractually obligated to fulfill with cash under certain circumstances. These commitments include guarantees in favor of banks, suppliers and VIEs and guarantees towards third parties such as surety performance guarantees to customers as they relate to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these guarantees are not normally called, as we typically comply with the underlying performance requirement. As at December 31, 2018 , we had not been required to make collateral deposits with respect to these agreements.

The maximum potential future payments are summarized in Note 33 - "Commitments and Contingencies,” of our Consolidated Financial Statements included herein.


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F.
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
 
At December 31, 2018 , we had the following contractual obligations and commitments:
 
 
Payment due by period
 
 
Year Ended December 31,
(In $ millions)
 
2019

 
2020 - 2021

 
2022 - 2023

 
Thereafter

 
Total

Interest-bearing debt (1) (2)
 
33

 
977

 
2,721

 
3,355

 
7,086

Related party interest-bearing debt
 
—

 
—

 
—

 
314

 
314

Total debt repayments
 
33

 
977

 
2,721

 
3,669

 
7,400

Pension obligations (3)
 
2

 
4

 
6

 
13

 
25

Operating lease obligations
 
11

 
18

 
8

 
1

 
38

Newbuilding commitments  (4)
 
368

 
—

 
—

 
—

 
368

Total contractual obligations
 
414

 
999

 
2,735

 
3,683

 
7,831

(1)
Debt principal repayments, excluding cash and payment-in-kind interest.
(2)
The above table assumes that we will make amortization payments on our secured credit facilities from 2020. Per the terms of our senior secured credit facilities, we can elect to defer up to $500m of such amortization payments until 2021 through the initiation of new loans.
(3)
Pension obligations are the forecasted employer’s contributions to our defined benefit plans, expected to be made over the next ten years.
(4)  
Newbuilding commitments for two jack-up rigs totaling $0.4 billion (2017: $1.7 billion) with the Dalian shipyard. See "Capital Commitments" section within ITEM 5B - "Liquidity and Capital Resources" and Note 33 - Commitments and Contingencies for further details.
In addition to the above, we have recognized liabilities for uncertain tax positions of $100 million including interest and penalties as at December 31, 2018 .
Please refer to Note 33 - "Commitments and contingencies” of our Consolidated Financial Statements included herein for further information.


G.
CRITICAL ACCOUNTING ESTIMATES
Overview
The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience, available information and assumptions that we believe to be reasonable. Our critical accounting estimates are important factors to our financial condition and results of operations, and require us to make subjective or complex assumptions or judgments about matters that are uncertain. We believe that the following are the critical accounting estimates used in the preparation of our Consolidated Financial Statements. In addition, there are other items in our Consolidated Financial Statements that require estimation. Our significant accounting policies are discussed in Note 2 - "Accounting Policies" and Note 5 – "Fresh Start Accounting" to our Consolidated Financial Statements included herein.
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 December 31, 2018 (Successor) and December 31, 2017 (Predecessor), the carrying amount of our drilling units was $7 billion and $13 billion, representing 61% and 73% 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 tender 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.

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Impairment
The carrying values of our long-lived assets are reviewed for impairment when certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be recoverable. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in significantly different carrying values of our assets and could materially affect our results of operations. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount is not recoverable.
With regard to our older drilling units which have relatively short remaining estimated useful lives, the results of impairment tests are particularly sensitive to management’s assumptions. These assumptions include the likelihood of the unit obtaining a contract upon the expiration of any current contract, and our intention for the drilling unit should no contract be obtained, including warm/cold stacking or scrapping. The use of different assumptions in the future could potentially result in an impairment of older drilling units, which could materially affect our results of operations. If market supply and demand conditions in the ultra-deepwater offshore drilling sector do not improve it is likely that we will be required to impair certain drilling units.
In the 2018 Predecessor period, we determined that the continuing downturn in the offshore drilling market was an indicator of impairment on certain assets. Following an assessment of recoverability, we recorded an impairment charge of $414 million against three non-modern drilling rigs West Alpha , West Navigator and West Epsilon .
During the 2018 Successor period and the years ended December 31, 2017 and 2016 we identified indicators that the carrying value of our drilling units may not be recoverable. Market indicators included the reduction in new contract opportunities, fall in market dayrate and contract terminations. We assessed recoverability of our drilling units by first evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilizations of the units. The estimated undiscounted future net cash flows were found to be greater than the carrying value of our drilling units. As a result, we did not need to proceed to assess the discounted cash flows of our drilling units, and no impairment charges were recorded.
Impairment of Equity Method Investments and Marketable Securities
Overview
We assess our equity method investments and marketable securities for impairment during each reporting period. 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. 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. If actual events differ from management’s estimates, or to the extent that these estimates are adjusted in the future, our financial condition and results of operations could be affected in the period of any such change of estimate.
During 2017 and 2016, the deteriorating market conditions in the oil and gas industry, as well as the supply and demand conditions in the industry we operate, were indicators of impairment for our investments in Seadrill Partners and SeaMex, as well as our investment in Seadrill Partners’ member interest and incentive distribution rights. We have determined the length and severity of the deterioration of market conditions to be representative of an "other than temporary" impairment for the year ended December 31, 2017 and 2016. We have recognized impairment of these investments within “Loss on impairment of investments” in our Consolidated Statement of Operations for the years ended December 31, 2017 and 2016.
During the 2018 Successor period and the 2018 Predecessor period we did not identify indicators of impairment for our equity method investments and marketable securities. As such, we did not recognize any impairment of these investments during these periods within the “Loss on impairment of investments” in our Consolidated Statement of Operations.
Seadrill Partners direct ownership interest and SeaMex investment
To perform an impairment assessment on our equity method investment in Seadrill Partners’ and SeaMex, we derived the fair value using an income approach which discounts future free cash flows, or the ‘DCF’ model. The cash flows are estimated over the remaining useful economic lives of the underlying assets but no longer than 30 years in total and discounted using the following estimated market participant weighted average cost of capital:
 
Year ended
December 31, 2017
Year ended
December 31, 2016
Seadrill Partners direct ownership interest
9.75%
9.50%
SeaMex equity interest
10.25%
11.00%
The DCF model derived an enterprise value of the investments, after which associated debt was subtracted to provide equity values. The assumptions used in the DCF model were derived from significant unobservable inputs (representative of Level 3 inputs for Fair Value Measurement) and are based on management’s best judgments and assumptions available at the time of performing the impairment test. The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios were developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability considering the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance and

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inspection costs, are estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment.
Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment.
Seadrill Partners- Seadrill member interest and Incentive Distribution Rights (‘IDRs’)
To assess the investments accounted for using the cost method for impairment, the fair value was determined using a Monte Carlo simulation method, or the Monte Carlo Model. The assumptions used in the Monte Carlo Model were derived from both observable and unobservable inputs and are based on management’s judgments and assumptions available at the time of performing the impairment test. The method considers the cash distribution waterfall, historical volatility, estimated dividend yield and the share price of the common units. We employ significant judgment in developing these estimates and assumptions.
Impairment
During the 2018 Successor period and the 2018 Predecessor period, we did not recognize any impairment of equity method investments and marketable securities within the “Loss on impairment of investments” in our Consolidated Statement of Operations.
During 2017 and 2016, we determined the length and severity of the deterioration of market conditions affecting our investments to be indicative of an "other than temporary" impairment for the years ended December 31, 2017 and 2016. During 2017 and 2016, we recognized a total impairment loss of $841 million and $895 million, respectively. The table below summarizes the total impairments of investments made during the years ended December 31, 2017 and 2016 :
(In $ millions)
Period from July 2, 2018 through December 31, 2018


 
P eriod from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

 
Year ended December 31, 2016

Impairments of marketable securities
 
 
 
 
 
 
 
Seadrill Partners - Common units
—

 
—

 
—

 
153

Total impairment of marketable securities investments (reclassification from OCI)
—

 
—

 
—

 
153

 
 
 
 
 
 
 
 
Impairments of investment in associated companies
 
 
 
 
 
 
 
Seadrill Partners - Total direct ownership investments
—

 
—

 
723

 
400

Seadrill Partners - Subordinated units
—

 
—

 
82

 
180

Seadrill Partners - Seadrill Member Interest and IDRs
—

 
—

 
—

 
73

SeaMex
—

 
—

 
36

 
76

Sete Brasil Participacoes SA
—

 
—

 
—

 
13

Total impairment of investments in associated companies
—

 
—

 
841

 
742

 
 
 
 
 
 
 
 
Total impairment of investments
—

 
—

 
841

 
895

Refer to Note 11 - "Impairment loss on marketable securities and investment in associated companies" to our Consolidated Financial Statements included herein for further information on the various estimates and assumptions used for calculating the loss on impairment of equity method investments and marketable securities.
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

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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 recent 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 12 – "Taxation" to our Consolidated Financial Statements included herein for further information.

H.
SAFE HARBOR
 
Forward-looking information discussed in this Item 5 includes assumptions, expectations, projections, intentions and beliefs about future events. These statements are intended as “forward-looking statements.” We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and the differences can be material. Please see “Cautionary Statement Regarding Forward-Looking Statements” in this annual report.


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ITEM 6.
DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
 
A.
DIRECTORS AND SENIOR MANAGEMENT
 
1) Board of Directors
The Board of Directors consists of seven individuals. The names and positions of the Directors as of February 28, 2019 are set out in the table below.
Name
Position
Birgitte Ringstad Vartdal
Director
Eugene I. Davis
Director
Harald Thorstein
Director
John Fredriksen
Director and Chairman of the Board
Kjell-Erik Østdahl
Director
Peter J. Sharpe
Director
Scott D. Vogel
Director
Certain biographical information about each of our directors is set forth below.
Birgitte R. Vartdal serves as an independent director appointed by Hemen. Ms. Vartdal has served as Chief Executive Officer of Golden Ocean Management AS since May 2016 and previously served as Chief Financial Officer of Golden Ocean from June 2010 to April 2016. Ms. Vartdal currently serves on the board of Marine Harvest ASA and as a member of the corporate assembly of Equinor ASA. She also previously served as a director of Sevan Drilling Ltd (formerly Sevan Drilling ASA). Ms. Vartdal holds a degree of Siv.Ing. (MSc) in Physics and Mathematics from the Norwegian University of Science and Technology (Nw. NTNU) and an MSc in Financial Mathematics from Heriot-Watt University, Scotland.
Eugene I. Davis serves as an independent director appointed by the mutual agreement of Hemen, Centerbridge and the Select Commitment Parties. Mr. Davis is the Chairman and Chief Executive Officer of PIRINATE Consulting Group, LLC, a privately held consulting firm specializing in turnaround management, merger and acquisition consulting, hostile and friendly takeovers, proxy contests and strategic planning advisory services for domestic and international public and private business entities. Since forming PIRINATE in 1997, Mr. Davis has advised, managed, sold, liquidated and served as a chief executive officer, chief restructuring officer, director, chairman or committee chairman of a number of businesses operating in diverse sectors. He was the President, Vice Chairman and a director of Emerson Radio Corporation, a consumer electronics company, from 1990 to 1997 and was the Chief Executive Officer and Vice Chairman of Sport Supply Group, Inc., a direct-mail marketer of sports equipment, from 1996 to 1997. Mr. Davis began his career in 1980 as an attorney and international negotiator with Exxon Corporation and Standard Oil Company (Indiana) and was in private practice from 1984 to 1998.
Mr. Davis currently serves as Co-Chairman of Verso Corporation, and also serves as a director of Sanchez Energy, as well as certain private, non-SEC reporting companies. During the past five years, Mr. Davis has been a director of the following public or formerly public companies: ALST Casino Holdco, LLC; Atlast Air Worldwide Holdings, Inc.; The Cash Store Financial Services, Inc.; Dex One Corp.; Genco Shipping & Trading Limited; Global Power Equipment Group, Inc.; Goodrich Petroleum Corp.; Great Elm Capital Corp.; GSI Group, Inc.; Hercules Offshore, Inc.; HRG Group, Inc.; Knology, Inc.; SeraCare Life Sciences, Inc.; Spansion, Inc.; Spectrum Brands Holdings, Inc.; and WHIM Corp.
Mr. Davis obtained a Bachelor's degree from Columbia College, a Master of International Affairs degree (MIA) in international law and organization from the School of International Affairs of Columbia University, and a Juris Doctorate from Columbia University School of Law.
Harald Thorstein serves as a director appointed by Hemen. Harald Thorstein has served as a director of Seadrill Partners LLC since September 2012. Mr. Thorstein is currently employed by Seatankers Consultancy Services (UK) Limited (previously Frontline Corporate Services) in London, prior to which he was employed in the Corporate Finance division of DnB NOR Markets, specializing in the offshore and shipping sectors. He has also served as a director of Ship Finance International Limited since 2011. Mr. Thorstein has served as a director of Solstad Farstad ASA since June 2017 and Axactor AB since September 2017.
John Fredriksen serves as a director appointed by Hemen. Mr. Fredriksen has served as Chairman of the Board, President, and a director of Old Seadrill since its inception in May 2005. Mr. Fredriksen has also served since 1997 as Chairman, President, and a director of Frontline Ltd., a Bermuda company listed on the NYSE and the OSE, and from 2001 until September 2014 as Chairman of the Board, President and a director of Golar LNG Limited, or Golar, a Bermuda company listed on the Nasdaq Global Market. Mr. Fredriksen also currently serves as a director of Golden Ocean Group Limited, a Bermuda company listed on the Nasdaq Stock Market and the OSE, since March 2015. Mr. Fredriksen also served as a director and chairman of the board of North Atlantic Drilling Limited from its inception in 2011 until September 2015.
Kjell-Erik Østdahl serves as an independent director appointed by Hemen. Since 2016, Mr. Østdahl has been a senior advisor to Blackstone's Private Equity Energy division in London. Prior to that, between 2014 to 2015, Mr. Østdahl worked in Norway as a senior partner at HitecVision, a private equity investor focused on the upstream oil and gas industry. Prior to that, between 1990 and 2005, and again between 2007 to 2013, Mr. Østdahl worked at Schlumberger and its subsidiary, WesternGeco, including working in France as EVP Operations and Support and Chief Procurement, in the U.K. and Norway as VP Operations, General Manager, Marketing Manager, Business Development Manager and Local

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Manager and in China and Indonesia as a Field Engineer. Between 2006 and 2007, Mr. Østdahl worked at Statoil as Chief Procurement Officer (Norway). He holds and has held various non-executive directorships and advisory roles including: (a) as Chairman of Sekal (Norway) from 2015 to date, and of Atlantica Tender Drilling (U.S.A) from 2014 to 2016; and (b) as a board member of the Flux Group (Norway) from 2015 to 2016 and of Wirescan (Norway) from 2014 to 2015. Mr. Østdahl has also agreed to act as a director of Mime, a new independent E&P player in the North Sea. Mr. Østdahl holds an MSc Electrical Engineering degree from NTNU Norwegian University of Science & Technology, Norway.
Peter J. Sharpe serves as an independent director appointed by Centerbridge. Mr. Sharpe retired from Shell in 2017 after holding a diverse range of Executive Management positions in international locations over a period of 37 years. Mr. Sharpe served as Executive Vice President of Royal Dutch Shell for over 10 years, with responsibility for managing Shell upstream investments in well construction and maintenance globally. Mr. Sharpe brings significant experience in all aspects of upstream development, asset management, and major project delivery. Mr. Sharpe served as Chairman of SWMS Pte Ltd an independent Joint Venture between Shell and CNPC from 2012 to 2017 and as a non-Executive director of Xtreme Drilling and Coil Services Corporation from 2008 to 2014. He brings to the Board expertise in strategic and operational risk management, supply chain management, organizational change and monetization of technology. Mr. Sharpe received a Bachelor of Science degree from the University of Hull in 1980.
Scott D. Vogel serves as an independent director appointed by the Select Commitment Parties. Mr. Vogel is the Managing Member of Vogel Partners LLC, a private investment firm. He was previously a managing director at Davidson Kempner Capital Management, L.L.C., in the Global Distressed Debt Group managing over USD 15 billion in assets and 75 investment professionals. Mr. Vogel also serves as a Director on the public company Boards of Bonanza Creek Energy, Key Energy Services and Avaya Inc and several private companies.
2) Senior Management
Our executive management team consists of the following four employees who are responsible for overseeing the management of our business (" Management "). The Board of Directors has organized the provision of management services through Seadrill Management Ltd. (" Seadrill Management "), a subsidiary incorporated in the United Kingdom. The Board of Directors has defined the scope and terms of the services to be provided by Seadrill Management. The Board of Directors must be consulted on all matters of material importance and/or of an unusual nature and, for such matters, will provide specific authorization to personnel in Seadrill Management to act on its behalf.
The names of the members of Management as of February 28, 2019 , and their respective positions, are presented in the table below:
Name
Age
Position
Anton Dibowitz
47
Chief Executive Officer
Mark Morris
55
Chief Financial Officer
Leif Nelson
44
Chief Operating Officer
Chris Edwards
54
General Counsel
Anton Dibowitz serves as the Chief Executive Officer of Seadrill Management and as the Company's Principal Executive Officer. Mr. Dibowitz was appointed Chief Executive Officer of the Group in July 2017. Prior to this Mr. Dibowitz served as Executive Vice President of Seadrill Management since June 2016, and as Chief Commercial Officer since January 2013. He has over 20 years drilling industry experience most recently serving as Vice President of Marketing and prior to that as Commercial Director, Deepwater Western Hemisphere Division. Prior to joining Seadrill, Mr. Dibowitz held various positions within tax, process reengineering and marketing at Transocean Ltd. and Ernst & Young LLP. He is a Certified Public Accountant and a graduate of the University of Texas at Austin where he received a Bachelor's degree in Business Administration, and Master's degrees in Professional Accounting (MPA) and Business Administration (MBA).
Mark Morris serves as the Chief Financial Officer of Seadrill Management and as the Company’s Principal Financial Officer and Principal Accounting Officer. Mr. Morris was appointed Chief Financial Officer of the Group in September 2015. Prior to joining Seadrill, Mr. Morris was the chief financial officer for Rolls-Royce Group plc as well as serving as a director on its main board and held several roles in his 28 years with the company. During his career at Rolls-Royce, amongst other roles, Mr. Morris served as group treasurer, ran Rolls-Royce Capital, its aircraft and engine leasing division and was treasurer of IAE International Aero Engines AG, a Rolls-Royce joint venture based in the USA. Mr. Morris also serves as the Chief Executive Officer of Seadrill Partners, a position he has held since September 2015.  He is a graduate of the University of Manchester where he received a Bachelor’s degree in Aeronautical Engineering, is a member of the Association of Corporate Treasurers (ACT) Advisory Panel and an Honorary Fellow of the ACT.
Leif Nelson has served as Seadrill Management's Chief Operating Officer since July 2015. He has over 18 years' experience in the drilling industry most recently as the Group's Vice President Operations Performance. Prior to joining Seadrill, Mr. Nelson held various operational positions for Transocean Ltd. Mr. Nelson is a graduate of the Colorado School of Mines and holds a BSc in Petroleum Engineering. Mr. Nelson also sits on the board of the Well Control Institute.
Chris Edwards has served as Seadrill Management's General Counsel since February 2015 and was appointed Senior Vice President in June 2016. He has over 20 years of in-house legal experience in the natural resources sector, including most recently serving as General Counsel Corporate and General Counsel of the Aluminium Division at BHP Billiton. Prior to working in-house, he trained and worked at Linklaters LLP in its London and Hong Kong offices.


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B.
COMPENSATION

1) Directors
During the 2018 Successor period , we paid an aggregate $0.4 million in directors’ fees to the current members of the Board of Directors as shown in ITEM 6A - "Directors and Senior Management". Certain current members of the Board of Directors were also Directors of the Predecessor Company. We paid these Directors an aggregate $1 million in directors' fees for the 2018 Predecessor period .
In addition, certain members of our current Board of Directors received awards of restricted stock units (" RSUs ") under our Employee Incentive Plan in September 2018. For details of these awards please see ITEM 6E - "Share Ownership".
2) Senior Management

Members of our Management receive compensation for the services they provide. Their compensation currently includes base salary, performance bonus and awards under our Employee Incentive Plan. In addition, members of Management may participate in our retirement savings plans and are eligible to participate in benefit programs available to our UK workforce generally including medical, life insurance and disability benefits. We believe that the compensation awarded to our Management is consistent with that of our peers and similarly situated companies in our industry.

During the 2018 Successor period , we paid an aggregate compensation of $3.4 million to our Management. In addition we incurred compensation expense in the aggregate amount of $0.1 million for their pension and retirement benefits. We paid our Management aggregate compensation of $2.5 million for the 2018 Predecessor period . We additionally incurred compensation expense in the aggregate amount of $0.1 million for their pension and retirement benefits during this period.

Our Management received awards of RSUs under our Employee Incentive Plan in September 2018. For details of these awards please see ITEM 6E - "Share Ownership".

The Chief Executive Officer, Chief Financial Officer and General Counsel have termination related payment clauses in their contracts. These relate to terminations in the context of a "Change of Control Event" or terminations agreed due to "Good Reason" other than "Cause". "Cause" is defined as one of the following: Gross misconduct; Serious breach of Contract; UK criminal offence; Fraud & corrupt practices relating to the Bribery Act 2010 and ineligibility to work legally in the UK. All the above contracts are signed by the current incumbents. Other than the listed termination related payment clauses, no employee, including members of Management, has entered into employment agreements which provide for any special benefits upon termination of employment.

C.
BOARD PRACTICES

The Board of Directors is responsible for the overall management of the Company and may exercise all the powers of the Company not reserved to the Company's shareholders by the Bye-Laws or Bermuda law.
1) Terms of office
Each member of the Board of Directors was appointed in 2018 and is up for re-election in 2019.
The Bye-Laws provide that, as long as Hemen's ownership interest is equal to or exceeds 5% and its ownership percentage has not previously fallen below 5%, the Board of Directors shall consist of not more than seven Directors, unless the Company's shareholders by Ordinary Resolution (as such term is defined in the Bye-Laws) resolve otherwise and Hemen provides its prior written consent thereto. If Hemen's ownership interest falls below 5%, the number of Directors shall be such number as the Company's shareholders by Ordinary Resolution may from time to time determine. The Directors are either appointed by certain of the Company's shareholders pursuant to appointment rights set out in the Bye-Laws or elected by the Company's shareholders at the annual general meeting or any special general meeting called for that purpose. The Company's shareholders may authorize the Board of Directors to fill any vacancy in their number left unfilled at an annual general meeting or any special general meeting called for that purpose. If there is a vacancy of the Board of Directors occurring as a result of the death, disability, disqualification or resignation of any Director (other than an Investor Appointed Director (as defined in the Bye-Laws)), the Board of Directors has the power to appoint a Director to fill the vacancy.
2) Directors' service contracts
The Directors are entitled to one months' salary upon termination of their service.
3) Board committees
Our Board of Directors has established an Audit Committee, a Compensation Committee and a Conflicts Committee, and may create such other committees as the Board of Directors shall determine from time to time. Each of the standing committees of our Board of Directors has the composition and responsibilities described below.

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i.
Audit committee
The Board of Directors has established an Audit Committee among the members of the Board of Directors. The Audit Committee comprises Eugene I. Davis (chairman), Scott Vogel (committee member) and Birgitte R. Vartdal (committee member). The Audit Committee is responsible for overseeing the quality and integrity of the Company's Consolidated Financial Statements and its accounting, auditing and financial reporting practices; the Group's compliance with legal and regulatory requirements; the independent auditor's qualifications, independence and performance; and the Group's internal audit function.
ii.
Compensation committee
The Board of Directors has established a Compensation Committee among the members of the Board of Directors. The Compensation Committee comprises Peter J. Sharpe (chairman), Eugene I. Davis (committee member) and Harald Thorstein (committee member). The Compensation Committee is responsible for establishing and reviewing the executive officer's and senior management's compensation and benefits.
iii.
Conflicts committee
The Board of Directors has established a Conflicts Committee among the members of the Board of Directors. The Conflicts Committee comprises Scott Vogel (chairman), Peter Sharpe (committee member), Eugene I. Davis (committee member) and Kjell-Erik Østdahl (committee member). The primary purpose of the Conflicts Committee is to monitor and make recommendations to the board in relation to potential conflicts of interest between the Company and any of its affiliates or related third parties. The committee will also evaluate any conflicts of interest between a director and the Company.

D.
EMPLOYEES
 
The table below shows the development in the numbers of employees (including contracted-in staff) at December 31, 2018, 2017 and 2016. Please note that some of our employees provide services for Seadrill Partners, SeaMex and Northern Drilling. They are shown in the "Other" category below.
 
Total employees (including contracted-in staff)
As at December 31,
2018

 
As at December 31,
2017

 
As at December 31,
2016

Operating segments:
 
 
 
 
 
Floaters
1,598

 
1,484

 
1,710

Jack-up rigs
974

 
938

 
1,230

Other
1,617

 
1,221

 
1,100

Corporate
699

 
685

 
740

Total employees
4,888

 
4,328

 
4,780

Geographical location:
 
 
 
 
 
Norway
737

 
510

 
600

Rest of Europe
390

 
235

 
210

North America and Mexico
1,493

 
1,095

 
1,100

South America
425

 
742

 
600

Asia Pacific
845

 
462

 
450

Africa and Middle East
998

 
1,284

 
1,820

Total employees
4,888

 
4,328

 
4,780

Some of our employees and our contracted labor, most of whom work in Angola, Brazil, Nigeria, Norway and the United Kingdom, are represented by collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and have restricted ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance.
We consider our relationships with the various unions as stable, productive and professional. At present, there are no ongoing negotiations or outstanding issues, other than as disclosed in Note 33 - "Commitments and contingencies” of our Consolidated Financial Statements included herein.


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E.
SHARE OWNERSHIP

As at February 28, 2019 , members of the Board of Directors and members of Management had the following shareholding in the Company. Also shown are their interests in unvested restricted stock units (" RSUs ") awarded to them under the Employee Incentive Plan. These awards were made in September 2018.

Name
Position
Number of $0.10 shares
Number of unvested RSUs
Birgitte Ringstad Vartdal
Director
—
5,105
Eugene I. Davis
Director
—
5,105
Harald Thorstein
Director
—
5,105
John Fredriksen (1)
Director and Chairman
—
5,105
Kjell-Erik Østdahl
Director
—
5,105
Peter J. Sharpe
Director
—
5,105
Scott D. Vogel
Director
—
5,105
Anton Dibowitz
Management
—
90,056
Mark Morris
Management
—
42,605
Leif Nelson
Management
—
50,124
Chris Edwards
Management
—
20,049
(1)  
Mr. Fredriksen disclaims beneficial ownership of the 30,193,826 shares held by Hemen, a company which is indirectly controlled by trusts established by Mr. Fredriksen for the benefit of his immediate family, except to the extent of his voting and dispositive interest in such shares of common stock. Mr. Fredriksen has no pecuniary interest in the shares held by Hemen. The address of Hemen is c/o Seatankers Management Co. Ltd., P.O. Box 53562, CY-3399 Limassol, Cyprus.

ITEM 7.
MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.
MAJOR SHAREHOLDERS

The following table presents certain information as of February 28, 2019 , regarding the ownership of our common shares with respect to each shareholder whom we know to beneficially own more than 5% of our outstanding common shares.
 
Common Shares Held
Shareholder
Number

 
%

Hemen Holding Ltd (1)
30,193,826

 
30.2
%
King Street Capital Management LP
7,856,039

 
7.9
%
Centerbridge Partners LP
6,657,192

 
6.7
%
Aristeia Capital LLC
5,037,657

 
5.0
%
(1)
For further information regarding Hemen, please see Item 6. "Directors, Senior Management and Employees – E. Share Ownership.”
We had a total of 100,000,000 common shares outstanding as of February 28, 2019 .
Our major shareholders have the same voting rights as our other shareholders. No corporation or foreign government owns more than 50% of our outstanding common shares. We are not aware of any arrangements, the operation of which may at a subsequent date result in a change in control of Seadrill.

B.
RELATED PARTY TRANSACTIONS

Please see Note 30 - "Related Party Transactions" of the Consolidated Financial Statements included within this report.

C.
INTERESTS OF EXPERTS AND COUNSEL

Not applicable.

 
ITEM 8.
FINANCIAL INFORMATION

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A.
CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

1) Financial Statements

Please see the section of this Annual Report on Form 20-F entitled “Item 18. Financial Statements.”
 
2) Legal Proceedings

Please see Note 33 - "Commitments and Contingencies" to the Consolidated Financial Statements included within this report.
3) Dividends
The payment of any future dividends to shareholders will depend upon decisions that will be at the sole discretion of the Board of Directors and will depend on the then existing conditions, including Seadrill's operating results, financial condition, contractual restrictions, corporate law restrictions, capital requirements, the applicable laws of Bermuda and business prospects. Under Bermuda law, a company may not declare or pay a dividend, or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (a) it is, or would after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of its assets would thereby be less than its liabilities.
Although the Board of Directors may consider the payment of dividends, there can be no assurance that any dividend will be paid, or if declared, the amount of such dividend. The terms of our senior credit facilities and the agreements governing our subsidiary NSNCo's indebtedness under the New Secured Notes may restrict our ability to declare or pay dividends. Further, as Seadrill Limited is a holding company with no material assets other than the shares of its subsidiaries through which it conducts its operations, its ability to pay dividends will also depend on the subsidiaries distributing their respective earnings and cash flow.
Seadrill Limited was incorporated on 14 March 2018 and has not paid any dividends since its incorporation. Old Seadrill Limited did not pay dividends on its common shares since it suspended dividend distributions on November 26, 2014.

B.
SIGNIFICANT CHANGES
 
Not applicable.

ITEM 9.
THE OFFER AND LISTING

A.
OFFER AND LISTING DETAILS

Shares of our common stock, par value $0.10 per share, have traded on the NYSE since July 3, 2018 and on the OSE since July 26, 2018 under the trading symbol “SDRL”.
 
The NYSE listing is intended to be our primary listing and the OSE listing is intended to be our secondary listing.
 
B.
PLAN OF DISTRIBUTION

Not applicable.


C.
MARKETS

Our common shares currently trade on the NYSE and the OSE under the trading symbol “SDRL.”


D.
SELLING SHAREHOLDERS

Not applicable.


E.
DILUTION

Not applicable.



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F.
EXPENSES OF THE ISSUE

Not applicable.


ITEM 10.
ADDITIONAL INFORMATION
 
A.
SHARE CAPITAL
 
Not applicable.

 
B.
MEMORANDUM OF ASSOCIATION AND BYE-LAWS
 
The Bye-Laws are filed as an exhibit to this 20-F report. Below is a summary of provisions of the Bye-Laws and certain aspects of applicable Bermuda law. The Bye-Laws do not place more stringent conditions for the change of rights of holders than those required by the Bermuda Companies Act.
1) Objective of the Company
The objective of the Company's business are unrestricted, meaning that the Company has the capacity of a natural person, and can carry out any trade or business which, in the Board of Directors' opinion, can be advantageously carried out by the Company. Moreover, this means that the Company's objectives are not specified in the Bye-Laws. The Company can therefore undertake activities without restriction on its capacity.
2) Board of Directors
i.
Proceedings of the Board of Directors
The Bye-Laws provide that, subject to the Bermuda Companies Act, the business of the Company shall be managed by the Board of Directors. Generally, the Board of Directors may exercise the powers of the Company, except to the extent the Bermuda Companies Act or the Bye-Laws reserve such power to the shareholders. Bermuda law permits individual or corporate directors and there is no requirement in the Bye-Laws or Bermuda law that directors hold any of the Company's shares. There is also no requirement in the Bye-Laws or Bermuda law that the Directors must retire at a certain age.
The remuneration of the Directors is determined by the shareholders in a general meeting, by ordinary resolution. The Directors may also be paid all reasonable travel, hotel and incidental expenses properly incurred by them in connection with the Company's business or in discharge of their duties as Directors.
No physical meeting of the Board of Directors may take place in Norway or the United Kingdom. For any meeting of the Board of Directors or any board committee held electronically, a majority of the Directors participating (including the Chairman) must be physically located outside the United Kingdom, and the Board of Directors must use reasonable endeavors to ensure that the meeting is not deemed to be held in Norway.
Provided a Director discloses a direct or indirect interest in any contract or arrangement with the Company, as required by Bermuda law, such Director is pursuant to the Bye-Laws entitled to vote in respect of any such contract or arrangement in which he or she is interested and shall be considered in determining the quorum for the relevant board meeting. The Director must declare the nature of that interest, as required by the Bermuda Companies Act, however, no such contract or proposed contract will be void or voidable by reason only that such Director voted on it or was counted in the quorum of the relevant board meeting. Matters decided at a board meeting are determined by a majority of votes cast. No Director (including the chairman of the Board of Directors (if any)) is entitled to a second or casting vote. In the case of an equality of votes, the motion will be deemed to be lost.
A Director (including the spouse or children of the Director or any company of which such Director, spouse or children own or control more than 20% of the capital or loan debt) cannot borrow from the Company, (except loans made to Directors who are bona fide employees or former employees pursuant to an employees' share scheme) unless Shareholders holding 90% of the total voting rights have consented to the loan.
ii.
Election and removal of Directors
The Bye-Laws provide that, provided Hemen's Percentage Interest (as defined therein) is at least 5% (and has not previously fallen below 5%), the Board of Directors shall not have more than seven directors unless the shareholders by Ordinary Resolution (as defined in the Bye-Laws) determine otherwise and Hemen provides its prior written consent. In the event that Hemen's Percentage Interest falls below 5%, the number of Directors shall be such number as the Company by Ordinary Resolution may determine from time to time.
Pursuant to the Bye-Laws, members of the Board of Directors are appointed as follows:
a)
provided that Hemen's Percentage Interest is equal to or exceeds 10% (and has not previously fallen below 10%), Hemen shall have the right from the Plan Effective Date (as defined in the Bye-Laws) to: (a) appoint two persons as Hemen Directors (as defined in the Bye-Laws), of whom one shall be the Chairman; and (b) appoint two persons as Independent Nominees (as defined in the Bye-Laws), provided that the other Directors are given reasonable opportunity to meet and consult with Hemen and such Independent Nominees prior to their appointment to the Board of Directors;
b)
provided that Hemen's Percentage Interest is equal to or exceeds 5% but is less than 10% (and has not previously fallen below 5%), Hemen shall have the right from the Plan Effective Date to: (a) appoint one person as a Hemen Director, who shall be the Chairman; and (b) appoint two persons as Independent Nominees, provided that the other Directors are given reasonable opportunity to meet and consult with Hemen and such Independent Nominees prior to their appointment to the Board of Directors;

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c)
provided that Centerbridge retains at least 50% of the Initial Centerbridge Investment (as defined in the Bye-Laws) (and has not previously held less than 50% of the Initial Centerbridge Investment), Centerbridge shall have the right from the Plan Effective Date to appoint one person as a Centerbridge Director (as defined in the Bye-Laws), including at the time of the first election of directors that follows the first anniversary of the Plan Effective Date (but not any subsequent election). From the second election of directors which takes place following the first anniversary of the Plan Effective Date (and subsequent elections thereafter), Centerbridge shall no longer have the right to appoint a Centerbridge Director;
d)
provided that the Select Commitment Parties retain at least 50% of the Initial Select Commitment Parties' Investment (as defined in the Bye-Laws) (and have not previously held less than 50% of the Initial Select Commitment Parties' Investment), the Select Commitment Parties, acting by a majority shall have the right from the Plan Effective Date until immediately prior to the first annual general meeting after the Plan Effective Date to appoint Select Commitment Parties Director (as defined in the Bye-Laws); and
e)
Hemen, Centerbridge and the Select Commitment Parties, acting by a majority of each of Hemen, Centerbridge and the Select Commitment Parties, shall have the right from the Plan Effective Date to appoint one Joint Designee Director (as defined in the Bye-Laws). The New Commitment Parties (as defined in the Bye-Laws) shall have the right to suggest up to three candidates for the position of Joint Designee Director, which candidates will be considered by Hemen, Centerbridge and the Select Commitment Parties when determining the identity of the Joint Designee Director, provided that the New Commitment Parties will provide the names of the suggested candidates to Hemen, Centerbridge and the Select Commitment Parties, not less than 10 Business Days (as defined in the Bye-Laws) in advance of the proposed date of appointment of the Joint Designee Director in accordance with the Bye-Laws. Prior to appointing the Joint Designee Director, Hemen, Centerbridge and the Select Commitment Parties will deliver written notice of the proposed identity of the Joint Designee Director to the Ad Hoc Group (with separate notice to the outside legal counsel of the Ad Hoc Group) and Barclays not less than three Business Days in advance of the proposed date of appointment of the Joint Designee Director, and shall take into consideration any objections raised by the New Commitment Parties as to the identity of the Joint Designee Director. Notwithstanding the foregoing, each of Hemen, Centerbridge and the Select Commitment Parties shall not unreasonably withhold its consent to any appointment of such Joint Designee Director.
From and after such time as Hemen, Centerbridge and the Select Commitment Parties cease to have the right to appoint their respective Director(s) or Independent Nominee, as the case may be, such Directors shall be subject to re-election by Ordinary Resolution at each annual general meeting.
A Director may resign by providing notice in writing to the Company of such resignation. A Director (other than an Investor Appointed Director (as defined in the Bye-Laws), may be removed by the Shareholders in a general meeting, provided that the notice of any such general meeting of shareholders convened for the purpose of removing a Director is given to the Director concerned. The notice must contain a statement of the intention to remove the Director and must be served the Director not less than 14 days before the meeting. The Director shall be entitled to attend the meeting and be heard on the motion for his or her removal. An Investor Appointed Director may be removed by written notice delivered to the Company's registered office by the Investor(s) entitled to make the appointment.
The majority of all the Directors, when taken together, shall not be resident in the United Kingdom.
iii.
Duties of Directors
The Bye-Laws provide that the Company's business is to be managed by the Board of Directors. Under Bermuda common law, members of the board of directors of a Bermuda company owe a fiduciary duty to the company to act in good faith in their dealings with or on behalf of the company and exercise their powers and fulfill the duties of their office honestly. This duty includes the following elements:
•
a duty to act in good faith in the best interest of the company;
•
a duty not to make a personal profit from opportunities that arise from the officer of director;
•
a duty to avoid conflicts of interest; and
•
a duty to exercise powers for the purpose for which such powers were intended.
The Bermuda Companies Act imposes a duty on directors and officers of a Bermuda company to act honestly and in good faith with a view to the best interests of the company, and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. In addition, the Bermuda Companies Act imposes various duties on directors and officers of a company with respect to certain matters of management and administration of the company. Directors and officers generally owe fiduciary duties to the company, and not to the company's individual shareholders.
3) Share rights
The holders of Shares have no pre-emptive, redemption, conversion or sinking fund rights. The holders of Shares are entitled to one vote per Share on all matters submitted to a vote of the holders of Shares. Unless a different majority is required by law or by the Bye-Laws, resolutions to be approved by the holders of Shares require approval by a simple majority of votes cast at a meeting at which a quorum is present.
In the event of the liquidation, dissolution or winding up of the Company, the holders of Shares are entitled to share equally and ratably in its assets, if any, remaining after the payment of all the Company's debts and liabilities, subject to any liquidation preference on any issued and outstanding preference shares.
i.
Variation of share rights
The Bye-Laws provide that, subject to the Bermuda Companies Act, the rights attached to any class of the shares issued, unless otherwise provided for by the terms of issue of the relevant class, may be altered or abrogated either: (i) with the consent of the holders of not less than

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75% of the issued shares of that class; or (ii) with the sanction of a resolution passed by a majority of 75% of the votes cast at a general meeting of the relevant class of shareholders at which a quorum consisting of at least two persons holding or representing at least one-third of the issued shares of the relevant class is present. However, if the Company or a class of shareholders only has one shareholder, one shareholder present in person or by proxy shall constitute the necessary quorum, as specified in (i) and (ii). The Bye-Laws specify that the creation or issue of Shares ranking equally with existing Shares will not, unless expressly provided by the terms of issue of existing Shares, vary the rights attached to existing Shares.
ii.
Voting rights
Under Bermuda law, the voting rights of Shareholders are regulated by the Bye-laws, except in certain circumstances provided in the Bermuda Companies Act. At any general meeting, every holder of Shares present in person and every person holding a valid proxy shall have one vote on a show of hands. On a poll, every such holder of Shares present in person or by proxy shall have one vote for every Share held.
Except where a greater majority is required by the Bermuda Companies Act or the Bye-Laws, any question proposed for the consideration of the shareholders at a general meeting shall be decided by the affirmative votes of a majority of the votes cast in accordance with the provisions of the Bye-Laws and in case of an equality of votes the chairman of such meeting shall not be entitled to a second or deciding vote and the resolution shall fail.
4) Amendment of the memorandum of association and Bye-Laws
Bermuda law provides that the memorandum of association of a company may be amended in the manner provided for in the Bermuda Companies Act, i.e. by a resolution passed at a general meeting of shareholders. The Bye-laws provide that the Bye-laws may be amended by the Board of Directors but any such amendment shall only become operative to the extent that it has been confirmed by an Ordinary Resolution (as defined in the Bye-laws). The Bye-Laws provide that as long as Hemen's Percentage Interest (as defined in the Bye-Laws) is at least 5%, Hemen's prior written consent is required for any amendment that would modify or otherwise affect Hemen's right to appoint the Hemen Directors and/or the Independent Nominees (as terms are defined in the Bye-Laws) or the right and powers of the Hemen Directors and/or the Independent Nominees once appointed. The Bye-Laws also provide that as long as Centerbridge retains at least 50% of the Initial Centerbridge Investment (as defined in the Bye-Laws), the Company may not, without prior written consent of Centerbridge, amend the Bye-Laws or its memorandum of association in any way that would modify or otherwise negatively impact: (i) Centerbridge's right to appoint the Centerbridge Director (as defined in the Bye-Laws); or (ii) the rights and powers of the Centerbridge Director once appointed.
Under Bermuda law, the holders of an aggregate of not less than 20% in par value of the Company's issued share capital or any class thereof have the right to apply to the Supreme Court of Bermuda for an annulment of any amendment of the memorandum of association adopted by shareholders at any general meeting, other than an amendment which alters or reduces a company's share capital as provided in the Bermuda Companies Act. Where such an application is made, the amendment becomes effective only to the extent that it is confirmed by the Supreme Court of Bermuda. An application for an annulment of an amendment of the memorandum of association must be made within 21 days after the date on which the resolution altering the Company's memorandum of association is passed and may be made on behalf of persons entitled to make the application or by one or more of their numbers as they may appoint in writing for the purpose. No application may be made by shareholders voting in favor of the amendment.
5) General Meetings of shareholders
The annual general meeting of the Company shall be held once in every year at such time and place as the Board of Directors appoints. Pursuant to Bermuda law, the Board of Directors may call for a special general meeting whenever they think fit, and the Board of Directors must call for a special general meeting upon the request of shareholders holding not less than 10% of the paid-up capital of the Company carrying the right to vote at general meetings. Bermuda law also requires that shareholders of a company are given at least five days' advance notice of a general meeting, unless notice is waived. The Bye-Laws provide that the Board of Directors may convene an annual general meeting or a special general meeting. General meetings of shareholders may not be held in Norway or the United Kingdom.
Under the Bye-Laws, at least seven days' notice of an annual general meeting must be given to each shareholder entitled to attend and vote thereat, stating the date, place and time at which the meeting is to be held. At least seven days' notice of a special general meeting must be given to each shareholder entitled to attend and vote thereat, stating the date, place and time and the general nature of the business to be considered at the meeting. This notice requirement is subject to the ability to hold such meetings on shorter notice if such notice is agreed: (i) in the case of an annual general meeting by all of the shareholders entitled to attend and vote at such meeting; or (ii) in the case of a special general meeting by a majority in number of the shareholders entitled to attend and vote at the meeting holding not less than 95% in nominal value of the shares entitled to attend and vote at such meeting. Pursuant to the Bye-Laws, the quorum required for a general meeting of shareholders is two or more shareholders present in person or by proxy and entitled to vote (whatever the number of shares held by them).
The accidental omission to give notice of a general meeting to, or the non-receipt of a notice of a general meeting by, any person entitled to receive notice does not invalidate the proceedings at that meeting.
Pursuant to the Bye-Laws, no Shareholder is entitled to attend any general meeting of shareholders unless the Shareholder has delivered to the Company's registered office written notice of its intention to attend and vote in person or by proxy at least 48 hours before the time of the meeting or the adjournment thereof.
6) Shareholders' proposals
Under Bermuda law, shareholders may, as set forth below and at their own expense (unless the company otherwise resolves), require the company to: (i) give notice to all shareholders entitled to receive notice of the annual general meeting of any resolution that the shareholders may properly

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move at the next annual general meeting; and/or (ii) circulate to all shareholders entitled to receive notice of any general meeting a statement (of not more than one thousand words) in respect of any matter referred to in the proposed resolution or any business to be conducted at such general meeting. The number of shareholders necessary for such a requisition is either: (i) any number of shareholders representing not less than 5% of the total voting rights of all shareholders entitled to vote at the meeting to which the requisition relates; or (ii) not less than 100 shareholders.
7) Dividend rights
Under Bermuda law, a company may not declare or pay a dividend or make a distribution out of the contributed surplus, if there are reasonable grounds for believing that: (i) the Company is, or would after the payment be, unable to pay its liabilities as they become due; or (ii) that the realizable value of its assets would thereby be less than its liabilities. Under the Bye-Laws, each common share is entitled to dividends if, as and when dividends are declared by the Board of Directors, subject to any preferred dividend right of the holders of any preference shares.
Any cash dividend payable to holders of the shares listed on the NYSE will be paid to Computershare, the Company's transfer agent in the United States for disbursement to those holders. Any cash dividends payable to holders of the Shares listed on Oslo Børs will be paid to Nordea, the Company's transfer agent in Norway for disbursement to those holders.
Pursuant to the Bye-Laws, any dividends, distributions or proceeds of share repurchases which remain unclaimed for three years from the date of declaration of such dividend, distribution or proceeds of share repurchases will be forfeited and revert to the Company.
8) Transfer of Shares
The Bye-Laws provide that the Board of Directors may decline to register, and may require any registrar appointed by the Company to decline to register, a transfer of a Share or any interest therein held through the VPS if such transfer would be likely, in the opinion of the Board of Directors, to result in 50% or more of the issued share capital (or of the votes attaching all issued shares in the Company) being held or owned directly or indirectly by persons resident for tax purposes in Norway. A failure to notify the Company of such correction or change can lead to the Shareholder's entitlement to vote, exercise other rights attaching to the Shares or interests therein being sold at the best price reasonably obtainable in all the circumstances. Furthermore, if such holding of 50% or more by individuals or legal persons resident for tax purposes in Norway or connected to a Norwegian business activity, the Bye-Laws require the Board of Directors to make an announcement through the Oslo Stock Exchange, and the Board of Directors and the registrar appointed by the Company are then entitled to dispose of Shares or interests therein to bring such holding by an individual or legal person resident for tax purposes in Norway or connected to a Norwegian business below 50% - the Shares or interests therein to be sold being firstly those held by holders who failed to comply with the above notification requirement, and thereafter those that were acquired most recently by the Shareholders.
Notwithstanding anything else to the contrary in the Bye-Laws, shares that are listed or admitted to trading on an Appointed Stock Exchange may be transferred in accordance with the rules and regulations of such exchange. All transfers of uncertificated Shares shall be made in accordance with and be subject to the facilities and requirements of the transfer of title to Shares in that class by means of the VPS or any other relevant system concerned and, subject thereto, in accordance with any arrangements made by the Board of Directors in accordance with the Bye-Laws. The Board of Directors may in its absolute discretion, refuse to register the transfer of a Share that is not fully paid. The Board of Directors may also refuse to recognize an instrument of transfer of a Share unless it is accompanied by the relevant Share certificate (if one has been issued) and such other evidence of the transferor's right to make the transfer as the Board of Directors shall reasonably require. Pursuant to the Bye-Laws, if the Board of Directors is of the opinion that a transfer may breach any law or requirement of any authority or any stock exchange or quotation system upon which any of the Company's common Shares are listed (from time to time), then registration of the transfer shall be declined until the Board of Directors receives satisfactory evidence that no such breach would occur. Subject to these restrictions and any other restrictions in the Bye-Laws and to the Bermuda Companies Act and applicable United States laws (including, without limitation, the U.S. Securities Act and related regulations), a holder of Shares may transfer the title to all or any of his Shares by completing an instrument of transfer in the usual common form or in such other form as the Board of Directors may approve. The instrument of transfer must be signed by the transferor and, in the case of a Share that is not fully paid, the transferee. The Board of Directors may also implement arrangements in relation to the evidencing of title to and the transfer of uncertified shares.
In accordance with Bermuda law, share certificates are only issued in the names of companies, partnerships or individuals. In the case of a shareholder acting in a special capacity (for example as a trustee), certificates may, at the request of the shareholder, record the capacity in which the shareholder is acting. Notwithstanding such recording of any special capacity, the Company is not bound to investigate or see to the execution of any such trust. The Company will take no notice of any trust applicable to any of the Shares, whether or not the Company has been notified of such trust.
9) Disclosure of material interest
The Bye-Laws provide that, where the requirements of the Oslo Stock Exchange require any person acquiring or disposing of an interest in the Shares to give notification of such change in interest, such person must immediately notify the registrar appointed by the Company of the acquisition or disposal and of its resulting interest, following which, the registrar appointed by the Company will notify the Oslo Stock Exchange. If a person fails to provide such notification, the Board of Directors shall require the registrar appointed by the Company to serve the person with notice, requiring compliance with the notification requirements and inform him or her that pending such compliance the registered holder of the Shares shall have suspended its entitlement to vote, exercise other rights attaching to the Shares and receive payment of income or capital.
10) Amalgamations and mergers
The amalgamation or merger of a Bermuda company with another company or corporation (other than certain affiliated companies) requires the amalgamation or merger agreement to be approved by the company's board of directors and by its shareholders. Unless the bye-laws provide

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otherwise, the approval of 75% of the shareholders voting at such meeting is required to approve the amalgamation or merger agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. The Bye-Laws provide that any such amalgamation or merger must be approved by the affirmative vote of at least a majority of the votes cast at a general meeting of the Company at which the quorum shall be two shareholders present in person or by proxy and entitled to vote (whatever the number of shares held by them).
Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value has been offered for such shareholder's shares may, within one month of notice of the relevant general meeting of shareholders, apply to the Supreme Court of Bermuda to appraise the fair value of those shares.
11) Shareholder suits
Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or is illegal, or would result in the violation of the company's memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or, for instance, where an act requires the approval of a greater percentage of the company's shareholders than that which actually approved it.
When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company's affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company.
The Bye-Laws contain a provision by virtue of which the Shareholders waive any claim or right of action that they have, both individually and on the Company's behalf, against any director or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of such director or officer.
12) Capitalization of profits and reserves
Pursuant to the Bye-Laws, the Board of Directors may (i) capitalize any amount for the time being standing to the credit of the Company's share premium or other reserve accounts or any amount credited to the Company's profit and loss account or otherwise available for distribution by applying such sum in paying up unissued shares to be allotted as fully paid bonus shares pro-rata to the shareholders; or (ii) capitalize any amount for the time being standing to the credit of a reserve account or amounts otherwise available for dividend or distribution by applying such amounts in full, partly paid or nil paid shares of those shareholders who would have been entitled to such sums if they were distributed by way of dividend or distribution.
13) Access to books and records and dissemination of information
Members of the general public have the right to inspect the public documents of a company available at the office of the Bermuda Registrar of Companies. These documents include the Company's memorandum of association (including its objects and powers) and certain alterations to the Company's memorandum of association. The members of the Company have the additional right to inspect the Bye-Laws, minutes of general meetings and the Company's audited financial statements (unless such requirement is waived in accordance with the Bye-Laws and the Bermuda Companies Act), which must be presented to the annual general meeting. The register of members of the Company is also open to inspection by Shareholders and by members of the general public without charge. Except when the register of members is closed under the provisions of the Bermuda Companies Act, the register of members of a company shall during business hours (subject to such reasonable restrictions as the company may impose so that not less than two hours in each day be allowed for inspection) be open for inspection by members of the general public without charge. A company may on giving notice by advertisement in an appointed newspaper close the register of members for any time or times not exceeding in the whole thirty days in a year.
Subject to the provisions of the Bermuda Companies Act, a company is required to maintain its register of members in Bermuda. A company with its shares listed on an Appointed Stock Exchange or which has had its shares offered to the public pursuant to a prospectus filed in accordance with the Bermuda Companies Act, or which is subject to the rules or regulations of a competent regulatory authority, may keep in any place outside Bermuda, one or more branch registers after giving written notice to the Bermuda Registrar of Companies of the place where each such register is to be kept. Any branch register of members established by the aforementioned is subject to the same rights of inspection as the register of members of the company in Bermuda. Any member of the public may require a copy of the register of members or any part thereof which must be provided within 14 days of a request on payment of the appropriate fee prescribed in the Bermuda Companies Act.
A company is required to keep a register of directors and officers at its registered office and such register must during business hours (subject to such reasonable restrictions as the company may impose, so that not less than two hours in each day be allowed for inspection) be open for inspection by members of the public without charge. Any member of the public may require a copy of the register of directors and officers, or any part of it, on payment of the appropriate fee prescribed in the Bermuda Companies Act. A company is also required to file with the Bermuda Registrar of Companies a list of its directors to be maintained on a register, which register will be available for public inspection subject to such conditions as the Bermuda Registrar of Companies may impose and on payment of such fee as may be prescribed.
Where a company, the shares of which are listed on an Appointed Stock Exchange, sends its summarized financial statements to its members pursuant to section 87A of the Bermuda Companies Act, a copy of the full financial statements (as well as the summarized financial statements)

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must be made available for inspection by the public at the company's registered office. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records.
In addition, the Bye-Laws require that the Company provide each of the Investors (as defined in the Bye-Laws) certain financial reports and other information, unless such Investor notifies the Company otherwise, and provide certain investors with certain additional inspection rights and access to Management.
14) Winding-up
A company may be wound up by the Bermuda court on application presented by the company itself, its creditors (including contingent or prospective creditors) or its contributories. The Bermuda court has authority to order winding up in a number of specified circumstances including where it is, in the opinion of the Bermuda court, just and equitable to do so.
A company may be wound up voluntarily when the members so resolve in general meeting, or, in the case of a limited duration company, when the period fixed for the duration of the company by its memorandum expires, or the event occurs on the occurrence of which the memorandum provides that the company is to be dissolved. In the case of a voluntary winding up, the company shall, from the commencement of the winding up, cease to carry on its business, except so far as may be required for the beneficial winding up thereof.
Where, on a voluntary winding up, a majority of directors make a statutory declaration of solvency, the winding up will be deemed a "members' voluntary winding up". In any case where such declaration has not been made, the winding up will be deemed a "creditors' voluntary winding up".
In the case of a members' voluntary winding up of a company, the company in general meeting must appoint one or more liquidators within the period prescribed by the Bermuda Companies Act for the purpose of winding up the affairs of the company and distributing its assets. If the liquidator is at any time of the opinion that the company will not be able to pay its debts in full in the period stated in the directors' declaration of solvency, he is obliged to summon a meeting of creditors and lay before the meeting a statement of the assets and liabilities of the company.
As soon as the affairs of the company are fully wound up via a members' voluntary winding up, the liquidator must make up an account of the winding up, showing how the winding up has been conducted and the property of the company has been disposed of, and thereupon call a general meeting of the company for the purposes of laying before it the account, and giving any explanation thereof. This final general meeting shall be called by advertisement in an appointed newspaper, published at least one month before the meeting. Within one week after the meeting the liquidator shall notify the Bermuda Registrar of Companies that the company has been dissolved and the Registrar shall record that fact in accordance with the Bermuda Companies Act.
In the case of a creditors' voluntary winding up of a company, the company must call a meeting of the creditors of the company to be summoned for the day, or the next day following the day, on which the meeting of the members at which the resolution for voluntary winding up is to be proposed is held. Notice of such meeting of creditors must be sent at the same time as notice is sent to members. In addition, the company must cause a notice to appear in an appointed newspaper on at least two occasions.
The creditors and the members at their respective meetings may nominate a person to be liquidator for the purposes of winding up the affairs of the company and distributing the assets of the company, provided that if the creditors and the members nominate different persons, the person nominated by the creditors shall be the liquidator. If no person is nominated by the creditors, the person (if any) nominated by the members shall be liquidator. The creditors at the creditors' meeting may also appoint a committee of inspection consisting of not more than five persons.
If a creditors' voluntary winding up continues for more than one year, the liquidator is required to summon a general meeting of the company and a meeting of the creditors at the end of each year and must lay before such meetings an account of his acts and dealings and of the conduct of the winding up during the preceding year.
As soon as the affairs of the company are fully wound up via a creditors' voluntary winding up, the liquidator must make up an account of the winding up, showing how the winding up has been conducted and the property of the company has been disposed of, and thereupon call a general meeting of the company and a meeting of the creditors for the purposes of laying the account before the meetings, and giving any explanation thereof. Each such meeting shall be called by advertisement in an appointed newspaper, published at least one month before the meeting. Within one week after the date of the meetings, or if the meetings are not held on the same date, after the date of the later meeting, the liquidator is required to send to the Bermuda Registrar of Companies a copy of the account and make a return to him in accordance with the Bermuda Companies Act. The company will be deemed to be dissolved on the expiration of three months from the registration by the Bermuda Registrar of Companies of the account and the return. However, a Bermuda court may, on the application of the liquidator or of some other person who appears to the court to be interested, make an order deferring the date at which the dissolution of the company is to take effect for such time as the court thinks fit.
15) Indemnification of Directors and officers
Section 98 of the Bermuda Companies Act provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust, except in cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in relation to the company. Section 98 further provides that a Bermuda company may indemnify its directors, officers and auditors against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in their favor or in which they are acquitted or granted relief by the Supreme Court of Bermuda pursuant to section 281 of the Bermuda Companies Act.

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The Company has adopted provisions in the Bye-Laws that provide that the Company shall indemnify its officers and directors of their actions and omissions to the fullest extent permitted by Bermuda law. The Bye-Laws provide that the Shareholders shall waive all claims or rights of action that they might have, individually or in right of the Company, against any of the Company's directors or officers for any act or failure to act in the performance of such director's or officer's duties, except in respect of any fraud or dishonesty of such director or officer. Section 98A of the Bermuda Companies Act permits the Company to purchase and maintain insurance for the benefit of any officer or director in respect of any loss or liability attaching to him in respect of any negligence, default, breach of duty or breach of trust, whether or not the Company may otherwise indemnify such officer or director.
16) Compulsory acquisition of shares held by minority Shareholders
An acquiring party is generally able to acquire compulsorily the common shares of a minority shareholder of a Bermuda company in the following ways:
By procedure under the Bermuda Companies Act known as a "scheme of arrangement". A scheme of arrangement could be affected by obtaining the agreement of the company and of holders of common shares, representing in the aggregate a majority in number and at least 75% in value of the common shareholders present and voting at a court ordered meeting held to consider the scheme of arrangement. The scheme of arrangement must then be sanctioned by the Bermuda Supreme Court. If a scheme of arrangement receives all necessary agreements and sanctions, upon the filing of the court order with the Bermuda Registrar of Companies, all holders of common shares could be compelled to sell their common shares under the terms of the scheme of arrangement.
If the acquiring party is a company it may compulsory acquire all the shares of the target company, by acquiring pursuant to a tender offer 90% of the shares or class of shares not already owned by, or by a nominee for, the acquiring party (the offeror), or any of its subsidiaries. If an offeror has, within four months after the making of an offer for all the shares or class of shares not owned by, or by a nominee for, the offeror, or any of its subsidiaries, obtained the approval of the holders of 90% or more of all the shares to which the offer relates, the offeror may, at any time within two months beginning with the date on which the approval was obtained, required by notice any non-tendering shareholder to transfer its shares on the same terms as the original offer. In those circumstances, non-tendering shareholders will be compelled to sell their shares unless the Supreme Court of Bermuda (on application made within a one-month period from the date of the offeror's notice of its intention to acquire such shares) orders otherwise.
Where the acquiring party or parties hold not less than 95% of the shares or class of shares of the company, such holder(s) may, pursuant to a notice given to the remaining shareholders or class of shareholders, acquire the shares of such remaining shareholders or class of shareholders. When this notice is given, the acquiring party is entitled and bound to acquire the shares of the remaining shareholders on the terms set out in the notice, unless a remaining shareholder, within one month of receiving such notice, applies to the Supreme Court of Bermuda for an appraisal of the value of their shares. This provision only applies where the acquiring party offers the same terms to all holders of shares whose shares are being acquired.
17) Certain provisions of Bermuda law
The Company has been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows the Company to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on its ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of its common shares. The Bermuda Monetary Authority has given its consent for the issue and free transferability of all its common shares from and/or to non-residents and residents of Bermuda for exchange control purposes, provided its shares remain listed on an Appointed Stock Exchange, which includes the NYSE and the Oslo Stock Exchange. Approvals or permissions given by the Bermuda Monetary Authority do not constitute a guarantee by the Bermuda Monetary Authority as to the Company's performance or creditworthiness. Accordingly, in giving such consent or permissions, the Bermuda Monetary Authority shall not be liable for the financial soundness, performance or default of the Company's business or for the correctness of any opinions or statements expressed in this report. Certain issues and transfers of common shares involving persons deemed resident in Bermuda for exchange control purposes require the specific consent of the Bermuda Monetary Authority.
In accordance with Bermuda law, share certificates are only issued in the names of companies, partnerships or individuals. In the case of a shareholder acting in a special capacity (for example as a trustee), certificates may, at the request of the shareholder and if the Board of Directors so determines, record the capacity in which the shareholder is acting. Notwithstanding such recording of any special capacity, the Company is not bound to investigate or see to the execution of any such trust. Except as ordered by a court of competent jurisdiction or as required by law or the Bye-Laws, the Company will take no notice of any trust applicable to any of its common shares, whether or not it has been notified of such trust.

C.
MATERIAL CONTRACTS

Attached as exhibits to this annual report are the contracts we consider to be both material and not in the ordinary course of business. Other than these contracts, we have no material contracts other than those entered in the ordinary course of business. 


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D.
EXCHANGE CONTROLS
 
The Bermuda Monetary Authority, or the BMA, must give permission for all issuances and transfers of securities of a Bermuda exempted company like ours, unless the proposed transaction is exempted by the BMA’s written general permissions. We have received general permission from the BMA to issue any unissued common shares and for the free transferability of our common shares as long as our common shares are listed on an “appointed stock exchange.” Our common shares are listed on the OSE and the NYSE, each of which is an “appointed stock exchange.” Our common shares may therefore be freely transferred among persons who are residents and non-residents of Bermuda.
Although we are incorporated in Bermuda, we are classified as a non-resident of Bermuda for exchange control purposes by the BMA. Other than transferring Bermuda Dollars out of Bermuda, there are no restrictions on our ability to transfer funds into and out of Bermuda or to pay dividends to U.S. residents who are holders of Common Shares or other non-residents of Bermuda who are holders of our common shares in currency other than Bermuda Dollars.
 In accordance with Bermuda law, share certificates may be issued only in the names of corporations, individuals or legal persons. In the case of an applicant acting in a special capacity (for example, as an executor or trustee), certificates may, at the request of the applicant, record the capacity in which the applicant is acting. Notwithstanding the recording of any such special capacity, we are not bound to investigate or incur any responsibility in respect of the proper administration of any such estate or trust.
 We will take no notice of any trust applicable to any of our shares or other securities whether or not we had notice of such trust.
As an “exempted company,” we are exempt from Bermuda laws which restrict the percentage of share capital that may be held by non-Bermudians, but as an exempted company, we may not participate in certain business transactions including: (i) the acquisition or holding of land in Bermuda (except that required for its business and held by way of lease or tenancy for terms of not more than 21 years ) without the express authorization of the Bermuda legislature; (ii) the taking of mortgages on land in Bermuda to secure an amount in excess of $50,000 without the consent of the Minister of Economic Development of Bermuda; (iii) the acquisition of any bonds or debentures secured on any land in Bermuda except bonds or debentures issued by the Government of Bermuda or by a public authority in Bermuda; or (iv) the carrying on of business of any kind in Bermuda, except in so far as may be necessary for the carrying on of its business outside Bermuda or under a license granted by the Minister of Economic Development of Bermuda.
 The Bermuda government actively encourages foreign investment in “exempted” entities like us that are based in Bermuda but do not operate in competition with local business. In addition to having no restrictions on the degree of foreign ownership, we are subject neither to taxes on our income or dividends nor to any exchange controls in Bermuda. In addition, there is no capital gains tax in Bermuda, and profits can be accumulated by us, as required, without limitation. There is no income tax treaty between the United States and Bermuda pertaining to the taxation of income other than applicable to insurance enterprises.

E.
TAXATION
 
The following is a discussion of the material Bermuda, United States federal income and other tax considerations with respect to us and holders of common stock. This discussion does not purport to deal with the tax consequences of owning common stock to all categories of investors, some of which, such as dealers in securities, investors whose functional currency is not the United States Dollar and investors that own, actually or under applicable constructive ownership rules, 10% or more of our common stock, may be subject to special rules. This discussion deals only with holders who hold the common stock as a capital asset, generally for investment purposes. Shareholders are encouraged to consult their own tax advisors concerning the overall tax consequences arising in their own particular situation under United States federal, state, local or foreign law of the ownership of common stock.
If an entity or arrangement treated as a partnership for U.S. federal income tax purposes holds common stock, the U.S. federal income tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership.  Partners of partnerships holding the common stock are encouraged to consult their own tax advisers.
Bermuda and Other Non-U.S. Tax Considerations
 As at the date of this annual report, whilst Seadrill is resident in Bermuda, we are not subject to taxation under the laws of Bermuda. Distributions we receive from our subsidiaries also are not subject to any Bermuda tax. As at the date of this annual report, there is no Bermuda income, corporation or profits tax, withholding tax, capital gains tax, capital transfer tax, or estate duty or inheritance tax payable by non-residents of Bermuda in respect of capital gains realized on a disposition of our common stock or in respect of distributions they receive from us with respect to our common stock. This discussion does not, however, apply to the taxation of persons ordinarily resident in Bermuda. Bermuda shareholders should consult their own tax advisors regarding possible Bermuda taxes with respect to dispositions of, and distributions on, our common stock.
We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, the imposition of any such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035. This assurance is subject to the proviso that it is not to be construed to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967.  The assurance does not exempt us from paying import duty on goods imported into Bermuda.  In addition, all entities

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employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government.  We and our subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda government.
Bermuda currently has no tax treaties in place with other countries in relation to double-taxation or for the withholding of tax for foreign tax authorities.
Dividends distributed by Seadrill Limited out of Bermuda
Currently, there is no withholding tax payable in Bermuda on dividends distributed from Seadrill Limited to its shareholders.
Taxation of rig owning entities
A number of our drilling rigs are owned in tax-free jurisdictions such as Bermuda or Liberia. There is no taxation of the rig owners’ income in these jurisdictions. The remaining drilling rigs are owned in jurisdictions with income or tonnage taxation of the rig owners’ income, being Hungary, Norway and Singapore. There may also be income tax in certain other jurisdictions where rigs are owned by, or allocated to, local branches.
Please also see the section below entitled “Taxation in country of drilling operations.”
Taxation in country of drilling operations
Income derived from drilling operations is generally taxed in the country where these operations take place. The taxation of income derived from drilling operations could be based on net income, deemed income, withholding taxes and/or other bases, depending upon the applicable tax legislation in each country of operation.  Some countries levy withholding taxes on bareboat charter payments (internal rig rent), branch profits, crew, dividends, interest and management fees.
Drilling operations can be carried out by locally incorporated companies, foreign branches of operating companies or foreign branches of the rig owning entities. We elect the appropriate structure with due regard to the applicable legislation of each country where the drilling operations occur.
Taxation may also extend to the rig owning entity in some of the countries where the drilling operations are performed. Some countries have introduced new laws and rules since the commencement of certain drilling contracts, which may affect, or have affected, the position of the group, potentially leading to additional tax on rig owners. The group considers the applicability of these to individual companies and contracts based on the relevant facts and circumstances.
Net income
Net income corresponds to gross income derived from the drilling operations less tax-deductible costs (i.e. operating costs, crew, insurance, management fees and capital costs (internal bareboat fee; tax depreciation; interest costs) incurred in relation to those operations).  In addition to net income tax, withholding tax on branch profits, dividends, internal bareboat fees, among other items, may also be levied.
Net income taxation for an international drilling contractor is complex, and pricing of internal transactions (e.g., rig sales; bareboat fees; services) will allocate overall taxable income between the relevant countries. We apply Organization for Economic Cooperation and Development, or OECD, Transfer Pricing Guidelines as a basis to arrive at pricing for internal transactions. OECD Transfer Pricing Guidelines describe various methods to price internal services on terms believed by us to be no less favorable than are available from unaffiliated third parties. However, some tax authorities could disagree with our transfer pricing methods and disputes may arise regarding the correct pricing.
Deemed income
Deemed income tax is normally calculated based on gross turnover, which can include or exclude reimbursables and often reflects an assumed profit ratio, multiplied by the applicable corporate tax rate. Some countries will also levy withholding taxes on the distribution of dividend and/or branch profits at the deemed tax rate.
Withholding and other taxes
Some countries base their taxation solely on withholding tax on gross turnover.  In addition, some countries levy stamp duties, training taxes or similar taxes on the gross turnover.
Customs duties
Customs duties are generally payable on the importation of drilling rigs, equipment and spare parts into the country of operation, although several countries provide exemption from such duties for the temporary importation of drilling rigs. Such exemption may also apply to the temporary importation of equipment.
Taxation of other income
Other income related to crewing, management fees and technical services will generally be taxed in the country where the service provider is resident, although withholding tax and/or income tax may also be imposed in the country where the drilling operations take place.
Dividends and other investment income will be taxable in accordance with the legislation of the country where the company holding the investment is resident. For companies resident in Bermuda, there is currently no tax on these types of income.

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Some countries levy withholding taxes on outbound dividends and interest payments.
Capital gains taxation
In respect of drilling rigs located in Bermuda, Liberia, Singapore and Hungary, no capital gains tax is payable in these countries upon the sale or disposition of a rig. However, some countries may impose a capital gains tax or a claw-back of tax depreciation (on a full or partial basis) upon the sale of a rig during or attributable to such time as the rig is operating within such country, or within a certain time after completion of such drilling operations, or when the rig is exported after completion of such drilling operations.
Other taxes
Our operations may be subject to sales taxes, value added taxes, or other similar taxes in various countries.
Taxation of shareholders
Taxation of shareholders will depend upon the jurisdiction where the shareholder is a tax resident. Shareholders should seek advice from their tax adviser to determine the taxation to which they may be subject based on the shareholder’s circumstances.
United States Federal Income Tax Considerations
The following are the material United States federal income tax consequences to us of our activities and to U.S. Holders and Non-U.S. Holders, each as defined below, of the ownership of our common stock.  This discussion does not purport to deal with the tax consequences of owning common stock to all categories of investors, some of which, such as dealers in securities, banks, financial institutions, tax-exempt entities, insurance companies, pension funds, US expatriates, real estate investment trusts, regulated investment companies, investors holding common stock as part of a straddle, hedging or conversion transaction, investors subject to the alternative minimum tax, investors who acquired their common stock pursuant to the exercise of employee stock options or otherwise as compensation, investors whose functional currency is not the United States Dollar and investors that own, actually or under applicable constructive ownership rules, 10% or more of our common stock, may be subject to special rules.  The following discussion of United States federal income tax matters is based on the United States Internal Revenue Code of 1986, as amended, or the Code, judicial decisions, administrative pronouncements, and existing and proposed regulations issued by the United States Department of the Treasury, or the Treasury Regulations, all of which are subject to change, possibly with retroactive effect.  The discussion below is based, in part, on the description of our business in this annual report and assumes that we conduct our business as described.
United States Federal Income Taxation of U.S. Holders
As used herein, the term “U.S. Holder” means a beneficial owner of common stock that is (1) a U.S. citizen or resident for U.S. federal income tax purposes, (2) U.S. corporation or other U.S. entity taxable as a corporation, (3) an estate the income of which is subject to U.S. federal income taxation regardless of its source or (4) a trust if a court within the United States is able to exercise primary jurisdiction over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust.
If an entity or arrangement treated as a partnership holds our common stock, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. If you are a partner in a partnership holding our common stock, you are encouraged to consult your tax adviser.
Distributions
Subject to the discussion of PFICs below, any distributions made by us with respect to our common stock to a U.S. Holder will generally constitute dividends, which may be taxable as ordinary income or “qualified dividend income” as described in more detail below, to the extent of our current or accumulated earnings and profits, as determined under United States federal income tax principles. Distributions in excess of our earnings and profits will be treated first as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in his common stock on a dollar-for-dollar basis and thereafter as capital gain. Because we are not a United States corporation, U.S. Holders that are corporations will not be entitled to claim a dividend received deduction with respect to any distributions they receive from us. Dividends paid with respect to our common stock will generally be treated as “passive category income” or, in the case of certain types of U.S. Holders, “general category income” for purposes of computing allowable foreign tax credits for United States foreign tax credit purposes.
Dividends paid on our common stock to a U.S. Holder who is an individual, trust or estate, or a “U.S. Individual Holder” will generally be treated as “qualified dividend income” that is taxable to such U.S. Individual Holders at preferential tax rates provided that (1) the common stock is readily tradable on an established securities market in the United States (such as the NYSE, on which our common stock is traded); (2) we are not a PFIC for the taxable year during which the dividend is paid or the immediately preceding taxable year (which, as discussed below, we are not and do not anticipate being in the future); (3) the U.S. Individual Holder has owned the common stock for more than 60 days in the 121 -day period beginning 60 days before the date on which the common stock becomes ex-dividend; and (4) the U.S. Individual Holder is not under an obligation to make related payments with respect to positions in substantially similar or related property. There is no assurance that any dividends paid on our common stock will be eligible for these preferential rates in the hands of a U.S. Individual Holder. Any dividends paid by us which are not eligible for these preferential rates will be taxed as ordinary income to a U.S. Individual Holder.
Special rules may apply to any “extraordinary dividend,” generally, a dividend paid by us in an amount which is equal to or in excess of 10% of a shareholder’s adjusted tax basis (or fair market value in certain circumstances) in a share of common stock. If we pay an “extraordinary dividend” on our common stock that is treated as “qualified dividend income,” then any loss derived by a U.S. Individual Holder from the sale or exchange of such common stock will be treated as long-term capital loss to the extent of such dividend.

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Sale, Exchange or other Taxable Disposition of Common Stock
Assuming we do not constitute a PFIC for any taxable year, a U.S. Holder generally will recognize taxable gain or loss upon a sale, exchange or other taxable disposition of our common stock in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other taxable disposition and the U.S. Holder’s tax basis in such stock. Such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition. Such capital gain or loss will generally be treated as United States source income or loss, as applicable, for United States foreign tax credit purposes. A U.S. Holder’s ability to deduct capital losses is subject to certain limitations.
3.8% Tax on Net Investment Income
Certain U.S. Holders, including individuals, estates, or, in certain cases, trusts, will generally be subject to a 3.8% tax on the lesser of (1) the U.S. Holder’s net investment income for the taxable year and (2) the excess of the U.S. Holder’s modified adjusted gross income for the taxable year over a certain threshold (which in the case of individuals is between $125,000 and $250,000 ). A U.S. Holder’s net investment income will generally include distributions made by us which constitute a dividend for U.S. federal income tax purposes and gain realized from the sale, exchange or other taxable disposition of our common stock. This tax is in addition to any income taxes due on such investment income.
If you are a U.S. Holder that is an individual, estate or trust, you are encouraged to consult your tax advisors regarding the applicability of the 3.8% tax on net investment income to the ownership and disposition of our common stock.
Passive Foreign Investment Company Status and Significant Tax Consequences
Special United States federal income tax rules apply to a U.S. Holder that holds stock in a foreign corporation classified as a PFIC for United States federal income tax purposes. In general, a foreign corporation will be treated as a PFIC with respect to a United States shareholder, if, for any taxable year in which such shareholder holds stock in such foreign corporation, either:
•
at least 75% of the corporation’s gross income for such taxable year consists of passive income (e.g. dividends, interest, capital gains and rents derived other than in the active conduct of a rental business); or
•
at least 50% of the average value of the assets held by the corporation during such taxable year produce, or are held for the production of, passive income.
For purposes of determining whether a foreign corporation is a PFIC, it will be treated as earning and owning its proportionate share of the income and assets, respectively, of any of its subsidiary corporations in which it owns, directly or indirectly, at least 25% of the value of the subsidiary’s stock.
Income earned by a foreign corporation in connection with the performance of services would not constitute passive income. By contrast, rental income would generally constitute “passive income” unless the foreign corporation is treated under specific rules as deriving its rental income in the active conduct of a trade or business or is received from a related party.
Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we intend to take the position that we will not be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. Our position is based on valuations and projections regarding our assets and income. While we believe these valuations and projections to be accurate, such valuations and projections may not continue to be accurate. Moreover, as we have not sought a ruling from the Internal Revenue Service, or IRS, on this matter, the IRS or a court could disagree with our position. In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, the nature of our operations may change in the future, and if so, we may not be able to avoid PFIC status in the future.
As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different United States federal income taxation rules depending on whether the U.S. Holder makes an election to treat us as a “Qualified Electing Fund,” which election we refer to as a “QEF election.” As an alternative to making a QEF election, a U.S. Holder should be able to make a “mark-to-market” election with respect to our common stock, as discussed below. In addition, if we were to be treated as a PFIC for any taxable year a U.S. Holder would be required to file an annual report with the United States Internal Revenue Service, or the IRS, for that year with respect to such U.S. Holder’s common stock.
Taxation of U.S. Holders Making a Timely QEF Election
If a U.S. Holder makes a timely QEF election, which U.S. Holder we refer to as an “Electing Holder,” the Electing Holder must report each year for United States federal income tax purposes his pro rata share of our ordinary earnings and our net capital gain, if any, for our taxable year that ends with or within the taxable year of the Electing Holder, regardless of whether or not distributions were received from us by the Electing Holder. The Electing Holder’s adjusted tax basis in the common stock would be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that had been previously taxed would result in a corresponding reduction in the adjusted tax basis in the common stock and would not be taxed again once distributed. An Electing Holder would generally recognize capital gain or loss on the sale, exchange or other disposition of our common stock. A U.S. Holder would make a QEF election with respect to any taxable year during which we are a PFIC by filing a valid IRS Form 8621 with his United States federal income tax return. If we were aware that we or any of our subsidiaries were to be treated as a PFIC for any taxable year, we would, if possible, provide each U.S. Holder with all necessary information in order to make the QEF election described above.  If we were to be treated as a PFIC, a U.S. Holder would be treated as owning his proportionate share

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of stock in each of our subsidiaries which is treated as a PFIC and a separate QEF election would be necessary with respect to each subsidiary.  It should be noted that we may not be able to provide such information if we did not become aware of our status as a PFIC in a timely manner.
Taxation of U.S. Holders Making a “Mark-to-Market” Election
Alternatively, if we were to be treated as a PFIC for any taxable year and, as we anticipate, our stock is treated as “marketable stock,” a U.S. Holder would be allowed to make a “mark-to-market” election with respect to our common stock, provided the U.S. Holder completes and files a valid IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. The “mark-to-market” election will not be available for any of our subsidiaries. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the common stock at the end of the taxable year over such holder’s adjusted tax basis in the common stock. The U.S. Holder would also be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the common stock over its fair market value at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S. Holder’s tax basis in his common stock would be adjusted to reflect any such income or loss amount. Gain realized on the sale, exchange or other disposition of our common stock would be treated as ordinary income, and any loss realized on the sale, exchange or other disposition of the common stock would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included as ordinary income by the U.S. Holder. It should be noted that the mark-to-market election would likely not be available for any of our subsidiaries which are treated as PFICs.
Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election
Finally, if we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a “mark-to-market” election for that year, whom we refer to as a “Non-Electing Holder,” would be subject to special rules with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common stock in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the Non-Electing Holder’s holding period for the common stock), and (2) any gain realized on the sale, exchange or other disposition of our common stock. Under these special rules:
•
the excess distribution or gain would be allocated ratably over the Non-Electing Holders’ aggregate holding period for the common stock;
•
the amount allocated to the current taxable year and any taxable year before we became a PFIC would be taxed as ordinary income; and
•
the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.
These penalties would not apply to a pension or profit sharing trust or other tax-exempt organization that did not borrow funds or otherwise utilize leverage in connection with its acquisition of our common stock. If a Non-Electing Holder, who is an individual, dies while owning our common stock, such Non-Electing Holder’s successor generally would not receive a step-up in tax basis with respect to such common stock.
United States Federal Income Taxation of “Non-U.S. Holders”
A beneficial owner of our common stock that is not a U.S. Holder or partnership is referred to herein as a “Non-U.S. Holder.”
Dividends on Common Stock
Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on dividends received from us with respect to our common stock, unless that income is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of a United States income tax treaty with respect to those dividends, that income is subject to United States federal income tax only if it is attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States.
Sale, Exchange or Other Disposition of Common Stock
Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on any gain realized upon the sale, exchange or other taxable disposition of our common stock, unless:
•
the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of a United States income tax treaty with respect to that gain, that gain is subject to United States Federal Income tax only if it is attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States; or
•
the Non-U.S. Holder is an individual who is present in the United States for 183 days or more during the taxable year of disposition and other conditions are met.

If a Non-U.S. Holder is engaged in a United States trade or business for United States federal income tax purposes, the income from the common stock, including dividends and the gain from the sale, exchange or other taxable disposition of the common stock that is effectively connected with the conduct of that United States trade or business will generally be subject to United States federal income tax in the same manner as discussed in the previous section relating to the United States federal income taxation of U.S. Holders. In addition, if the Non-U.S. Holder is a corporation, the Non-U.S. Holder’s earnings and profits that are attributable to the effectively connected income, subject to certain adjustments, may be subject to an additional United States federal branch profits tax at a rate of 30% , or at a lower rate as may be specified by an applicable United States income tax treaty.

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Backup Withholding and Information Reporting
In general, dividend payments, and other taxable distributions, made by us to you within the United States will be subject to information reporting requirements. Such payments will also be subject to backup withholding if paid to a U.S. Individual Holder who:
•
fails to provide an accurate taxpayer identification number;
•
is notified by the IRS that he has failed to report all interest or dividends required to be shown on his United States federal income tax returns; or
•
in certain circumstances, fails to comply with applicable certification requirements.
Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding by certifying their status on an applicable IRS Form W-8.
If a Non-U.S. Holder sells his common stock to or through a United States office of a broker, the payment of the proceeds is subject to both United States backup withholding and information reporting unless the Non-U.S. Holder certifies that he is a non-United States person, under penalties of perjury, or otherwise establishes an exemption. If a Non-U.S. Holder sells his common stock through a non-United States office of a non-United States broker and the sales proceeds are paid to the Non-U.S. Holder outside the United States, then information reporting and backup withholding generally will not apply to that payment. However, United States information reporting requirements, but not backup withholding, will apply to a payment of sales proceeds, even if that payment is made to a Non-U.S. Holder outside the United States, if the Non-U.S. Holder sells his common stock through a non-United States office of a broker that is a United States person or has some other connection to the United States.
Backup withholding is not an additional tax. Rather, a taxpayer generally may obtain a refund of any amounts withheld under backup withholding rules that exceed the taxpayer’s United States federal income tax liability by properly filing a refund claim with the IRS.
Individuals who are U.S. Holders (and to the extent specified in the applicable Treasury Regulations, certain individuals who are non-U.S. Holders and certain U.S. entities) who hold “specified foreign financial assets” (as defined in section 6038D of the Code and the applicable Treasury Regulations) are required to file IRS Form 8938 (Statement of Specified Foreign Financial Assets) with information relating to each such asset for each taxable year in which the aggregate value of all such assets exceeds $75,000 at any time during the taxable year or $50,000 on the last day of the taxable year.  Specified foreign financial assets would include, among other assets, our common stock, unless the common stock were held through an account maintained with certain financial institutions.  Substantial penalties apply to any failure to timely file IRS Form 8938, unless the failure is shown to be due to reasonable cause and not due to willful neglect.  Additionally, the statute of limitations on the assessment and collection of U.S. federal income tax with respect to a taxable year for which the filing of IRS Form 8938 is required may not close until three years after the date on which IRS Form 8938 is filed.  U.S. Holders and Non-U.S. Holders are encouraged to consult their own tax advisers regarding their reporting obligations under section 6038D of the Code.
Other Tax Considerations
In addition to the tax consequences discussed above, we may be subject to tax in one or more other jurisdictions where we conduct activities.  The amount of any such tax imposed upon our operations may be material. 

F.
DIVIDENDS AND PAYING AGENTS

Not applicable. 

G.
STATEMENT BY EXPERTS

Not applicable.

H.
DOCUMENTS ON DISPLAY

We are subject to the informational requirements of the Exchange Act. In accordance with these requirements we file reports and other information with the Commission. These materials, including this annual report on Form 20-F and the accompanying exhibits, may be inspected and copied at the public reference facilities maintained by the Commission at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling 1 (800) SEC-0330, and you may obtain copies at prescribed rates from the Public Reference Section of the Commission at its principal office in Washington, D.C. The Commission maintains a website (http://www.sec.gov.) that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission. In addition, documents referred to in this annual report on Form 20-F may be inspected at our principle executive offices at Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda and at the offices of Seadrill Management Ltd., at Building 11, Chiswick Park, 566 Chiswick High Road, London, W4 5YA, United Kingdom.


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I.
SUBSIDIARY INFORMATION

Not applicable.

ITEM 11.     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 interest rate swap agreements, currency option contracts and foreign currency contracts 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 also a concentration of credit risk with respect to cash and cash equivalents to the extent that most of the amounts are carried with Citibank, Nordea Bank Finland Plc, Danske Bank A/S, BNP Paribas and ING Bank N.V. We consider these risks to be remote. For details on the customers with greater than 10% of contract revenues, refer to Note 6 - Segment information.  

Foreign exchange risk

As is customary in the oil and gas industry, a majority 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.

Before we entered Chapter 11, we had unsecured bonds denominated in Norwegian Krone and Swedish Krona. These bonds were extinguished on emergence from Chapter 11. Our remaining foreign exchange exposures primarily relate to foreign denominated cash and working capital balances. We do not expect these remaining 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 December 31, 2018 (Successor) in the below table.

(In $ millions)
 
Principal outstanding

 
Hedging instruments - see below

 
Net exposure

 
Impact of 1% increase in rates

Senior Credit Facilities
 
5,662

 
4,500

 
1,162

 
15

Debt contained within VIEs
 
655

 
—

 
655

 
6

Total floating rate debt obligations
 
6,317

 
4,500

 
1,817

 
21

New Secured Notes
 
769

 
—

 
—

 
—

Less: Cash and Restricted Cash
 
(2,003
)
 
—

 
(2,003
)
 
(20
)
Net debt
 
5,083

 
4,500

 
(186
)
 
1


At December 31, 2017 we were in Chapter 11 and did not make interest payments on our Senior Credit Facilities. Our exposure to interest rate risk was therefore limited to loans contained within VIEs. The net exposure on those debt obligations was not materially different to the amount shown in the above table.


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On May 11, 2018, we purchased an interest rate cap for $68 million to mitigate our exposure to future increases in LIBOR on our Senior Credit Facility debt. The interest rate cap is not designated as a hedge and therefore does 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 December 31, 2018 was 2.81%. Therefore, the interest cap would mitigate the impact of 94% 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

 
(42
)
 
3

Senior Credit Facility debt - not hedged
 
1,162

 
12

 
—

 
12

Total Senior Credit Facility Debt
 
5,662

 
57

 
(42
)
 
15


One of the Ship Finance subsidiaries that we consolidate as a VIE (refer to Note 35 "Variable Interest Entities") 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 (Successor).


ITEM 12.
DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A.
DEBT SECURITIES
 
Not applicable.


B.
WARRANTS AND RIGHTS
 
Not applicable.


C.
OTHER SECURITIES
 
Not applicable.


D.
AMERICAN DEPOSITARY SHARES
 
Not applicable.

 
PART II
 
ITEM 13.      DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

 
ITEM 14.      MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

 
ITEM 15.      CONTROLS AND PROCEDURES
 
A.      Disclosure Controls and Procedures
Our Management, with participation from the Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 and Rule 15a-15 of the Exchange Act as of December 31, 2018 . Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the evaluation date.

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B.     Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) promulgated under the Exchange Act.
Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers and effected by the Board, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
Provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with generally accepted accounting principles, and that the Company's receipts and expenditures are being made only in accordance with authorizations of Company's management and directors; and
•
Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our Management, with the participation of the Chief Executive Officer and the Chief Financial Officer, assessed the effectiveness of the design and operation of our internal control over financial reporting pursuant to Rule 13a-15 of the Exchange Act as of December 31, 2018 .
Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Management reviewed the results of its assessment with the Audit Committee of our Board of Directors. On the basis of this evaluation, Management concluded that, as of December 31, 2018, the Company’s internal control over financial reporting was effective.
C.      Attestation Report of the Registered Public Accounting Firm
The independent registered public accounting firm that audited the Consolidated Financial Statements, PricewaterhouseCoopers LLP, has issued an attestation report on the effectiveness of our internal control over financial reporting as at December 31, 2018 , appearing under Item 18 "Financial Statements", and such report is incorporated herein by reference.
D.      Changes in Internal Control over Financial Reporting
There were no changes in these internal controls during the period covered by this annual report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 16.      RESERVED


ITEM 16A.      AUDIT COMMITTEE FINANCIAL EXPERT
 
Our Board of Directors has determined that Birgitte Vartdal, is an independent Director as defined by the NYSE and is an audit committee financial expert as defined by the SEC. See Item 6A - "Directors and Senior Management" for a description of Birgitte Vartdal's relevant experience.

 
ITEM 16B.      CODE OF ETHICS
 
We have adopted a Code of Ethics that applies to all entities controlled by us and its employees, directors, officers and agents of ours. We will provide any person, free of charge, a copy of our Code of Ethics upon written request to our registered office.



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ITEM 16C.      PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our principal accountant for the fiscal years ended December 31, 2018 and 2017 was PricewaterhouseCoopers LLP in the United Kingdom. The following table sets forth the fees related to audit and other services provided by the principal accountants and their affiliates.
 
 
Successor

 
Predecessor
( in $)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

December 31, 2017

Audit fees (1)
4,035,949

 
1,484,600

5,036,510

Audit-related fees (2)
252,108

 
—

25,000

Taxation fees (3)
—

 
—

10,000

All other fees (4)
—

 
—

—

Total
4,288,057

 
1,484,600

5,071,510


(1)  
Audit fees represent professional services rendered for the audit of our annual Consolidated Financial Statements and services provided by the principal accountant in connection with statutory and regulatory filings or engagements.
 
(2)  
Audit-related fees consist of assurance and related services rendered by the principal accountant related to the performance of the audit or review of our Consolidated Financial Statements which have not been reported under Audit fees above.
 
(3)  
Taxation fees represent fees for professional services rendered by the principal accountant for tax compliance, tax advice and tax planning.

(4)
All other fees include services other than audit fees, audit-related fees and taxation fees set forth above, primarily including information security and network penetration testing services.
 
Audit Committee’s Pre-Approval Policies and Procedures
 
Our Board has adopted pre-approval policies and procedures in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X that require the Board to approve the appointment of our independent auditor before such auditor is engaged and approve each of the audit and non-audit-related services to be provided by such auditor under such engagement by us. All services provided by the principal auditor in 2018 , 2017 and 2016 were approved by the Board pursuant to the pre-approval policy.

 
ITEM 16D.      EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
 
Not applicable.

 
ITEM 16E.     PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
 
None.


ITEM 16F.      CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

 
ITEM 16G.     CORPORATE GOVERNANCE
 
U.S. companies listed on the NYSE are subject to the "NYSE Corporate Governance: A Practical Guide" which has been published by the NYSE and is available at nyse.com/cgguide. As a foreign private issuer, we are exempt from certain requirements of the NYSE that are applicable to U.S. listed companies, including certain corporate governance practices. Set out below is a list of the significant differences between our corporate governance practices and the NYSE standards applicable to listed U.S. companies.
i.
Independence of Directors

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The NYSE requires that a U.S. listed company maintain a majority of independent directors. Under Bermuda law, we are not required to have a board of directors comprised of a majority of directors meeting the independence standards described in NYSE rules. However, our Board of Directors currently has a majority of independent directors, with five of the seven members being independent under the NYSE's standards for independence applicable to a foreign private issuer.
ii.
Executive Sessions
The NYSE requires that non-management directors meet regularly in executive sessions without management. The NYSE also requires that all independent directors meet in an executive session at least once a year. Historically, non-management directors regularly held executive sessions without management. We expect this to continue in the future.
iii.
Nominating/Corporate Governance Committee.
The NYSE requires that a listed U.S. company have a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Bermuda law, we do not currently have a nominating or corporate governance committee.
iv.
Corporate Governance Guidelines.
The NYSE requires that a listed U.S. company adopts and discloses corporate governance guidelines. The guidelines must address, among other things, director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. We are not required to adopt such guidelines under Bermuda law, however our current bye-laws include certain matters concerning corporate governance.
Additional Information Concerning Corporate Governance Required by the Oslo Stock Exchange Continuing Obligations as of January 2019
i.
Internal Control and Risk Management
Information concerning the main elements of our internal control and risk management systems associated with the financial reporting process has been provided in "Item 15. Controls and Procedures".
ii.
Board of Directors and Board Committees
The composition of our Board of Directors is set out in "Item 6. Directors, Senior Management and Employees", as is information pertaining to our Audit Committee, Compensation Committee and Conflicts Committee.
iii.
Appointment of Board Members
Our current bye-laws regulate the process of appointing Board Members. Reference is made to "Item 6. Directors, Senior Management and Employees", subsection "C. Board Practices" for information on specific rights concerning Terms of Office, the number of Board Members required in the Board of Directors and appointment procedures. Our current bye-laws have been included under "Item 10. Additional Information", subsection "B. Memorandum of Association and Bye-laws", and set out the full regulation of the procedures for the appointment of Board Members.
iv.
Authorization to Acquire Treasury Shares
Pursuant to our current bye-laws, the Company has the power to purchase own shares (treasury shares) for cancellation, as well as to hold such shares as treasury shares. The Board of Directors may exercise all powers of the Company to purchase or acquire its own shares, whether for cancellation or to be held as treasury shares in accordance with Bermuda law.
ITEM 16H.      MINE SAFETY DISCLOSURE
 
Not applicable.


PART III
 
ITEM 17.                   FINANCIAL STATEMENTS
 
See “Item 18. Financial Statements” below.

 
ITEM 18.      FINANCIAL STATEMENTS

Our Consolidated Financial Statements, together with the reports from PricewaterhouseCoopers LLP thereon, are filed as a part of this Annual Report, beginning on page F-1.

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Table of Contents

Pursuant to Rule 3-09, the Consolidated Financial Statements and the Management ICFR Report of Seadrill Partners LLC have been filed as a part of this Annual Report, beginning on page A-1.


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ITEM 19.    EXHIBITS
Exhibit
Number
Description
1.1



1.2
1.3

1.4

2.1

2.2

2.3

2.4

2.5
2.6

4.1

8.1
11.1
12.1
12.2
13.1
13.2
15.1
15.2
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema 
101.CAL
XBRL Taxonomy Extension Schema Calculation Linkbase
101.DEF
XBRL Taxonomy Extension Definition Linkbase
101.LAB
XBRL Taxonomy Extension Label Linkbase
101.PRE
XBRL Taxonomy Extension Presentation Linkbase

Seadrill agrees to furnish to the SEC upon request any instrument with respect to long-term debt that Seadrill has not filed as an exhibit pursuant to the exemption provided by instruction 2(b)(i) to Item 19 of Form 20-F.

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SIGNATURES

The registrant hereby certifies that it meets all the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.

Seadrill Limited
(Registrant)


Date: March 28, 2019

 
By:
 
 
Name:
Anton Dibowitz
 
Title:
Chief Executive Officer of Seadrill Management Ltd
(Principal Executive Officer of Seadrill Limited)



RESPONSIBILITY STATEMENT
 
We confirm, to the best of our knowledge, that the Consolidated Financial Statements for the year ended December 31, 2018, 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 Company and the Group taken as a whole.
 
We also confirm that, to the best of our knowledge, this Annual Report includes a true and fair review of the development and performance of the business and the position of the Company and the Group, together with a description of the principal risks. For further details on risks related to our business and uncertainties facing the Company and the Group, please see "Item 3. Key Information" subsection "D. Risk Factors".
 
 
Date: March 28, 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


Table of Contents

Seadrill Limited
Index to Consolidated Financial Statements

Consolidated Financial Statements of Seadrill Limited
 

F-1
Table of Contents



Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Seadrill Limited

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying Consolidated Balance Sheet of Seadrill Limited and its subsidiaries (Successor) (the “Company”) as of December 31, 2018, and the related Consolidated Statements of Operations, of Comprehensive (loss)/income, of Changes in Shareholders’ Equity and of Cash Flows for the period from July 2, 2018 to December 31, 2018, including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018, and the results of its operations and its cash flows for the period from July 2, 2018 to December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis of Accounting

As discussed in Note 1 to the Consolidated Financial Statements, the United States Bankruptcy Court for the Southern District of Texas Victoria Division confirmed the Company's Second Amended Joint Chapter 11 Plan of Reorganization (the "plan") on April 17, 2018. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before September 12, 2017 and substantially alters or terminates rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on July 2, 2018 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of July 2, 2018.

Basis for Opinions

The Company's management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under item 15. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audit of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.


F-2
Table of Contents

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.




/s/ PricewaterhouseCoopers LLP
Uxbridge, United Kingdom
March 28, 2019
We have served as the Company’s or its predecessor auditor since 2013.






F-3
Table of Contents



Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Seadrill Limited

Opinion on the Financial Statements

We have audited the accompanying Consolidated Balance Sheet of Seadrill Limited and its subsidiaries (Predecessor) (the “Company”) as of December 31, 2017 and the related Consolidated Statements of Operations, of Comprehensive (loss)/income, of Changes in Shareholders’ Equity and of Cash Flows for the period from January 1, 2018 to July 1, 2018, and for each of the two years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidated financial statements”).

In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and its cash flows for the period from January 1, 2018 to July 1, 2018, and for each of the two years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America.

Basis of Accounting

As discussed in Note 1 to the Consolidated Financial Statements, the Company filed a petition on September 12, 2017 with the United States Bankruptcy Court for the Southern District of Texas Victoria Division for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Second Amended Joint Chapter 11 Plan of Reorganization was substantially consummated on July 2, 2018 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting.

Basis for Opinion

These Consolidated Financial Statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s Consolidated Financial Statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these Consolidated Financial Statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements. We believe that our audits provide a reasonable basis for our opinion.



/s/ PricewaterhouseCoopers LLP
Uxbridge, United Kingdom
March 28, 2019
We have served as the Company’s or its predecessor auditor since 2013.



F-4
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF OPERATIONS
for the period from July 2, 2018 through December 31, 2018 (Successor), the period from January 1, 2018 through July 1, 2018 (Predecessor) and the years ended December 31, 2017 (Predecessor) and 2016 (Predecessor)
(In $ millions, except per share data)
 
 
Successor
 
Predecessor
 
Notes
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Twelve Months Ended 
 December 31, 2017

 
Twelve Months Ended 
 December 31, 2016

Operating revenues
 
 
 
 
 
 
 
 
Contract revenues
 
469

 
619

 
1,888

 
2,850

Reimbursable revenues
 
26

 
21

 
38

 
66

Other revenues
8 *
46

 
72

 
162

 
253

Total operating revenues
 
541

 
712

 
2,088

 
3,169

 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
Vessel and rig operating expenses
*
(357
)
 
(407
)
 
(792
)
 
(1,015
)
Reimbursable expenses
 
(24
)
 
(20
)
 
(35
)
 
(61
)
Depreciation
 
(236
)
 
(391
)
 
(798
)
 
(810
)
Amortization of intangibles
 
(58
)
 
—

 
—

 
—

General and administrative expenses
*
(62
)
 
(100
)
 
(277
)
 
(234
)
Total operating expenses
 
(737
)
 
(918
)
 
(1,902
)
 
(2,120
)
 
 
 
 
 
 
 
 
 
Other operating items
 
 
 
 
 
 
 
 
Impairment of long lived assets
 
—


(414
)

(696
)
 
(44
)
Loss on disposals
9 *
—


—


(245
)
 
—

Other operating income
*
21

 
7

 
27

 
21

Total other operating items
 
21

 
(407
)
 
(914
)
 
(23
)
 
 
 
 
 
 
 
 
 
Operating (loss)/income
 
(175
)
 
(613
)
 
(728
)
 
1,026

 
 
 
 
 
 
 
 
 
Financial and other non-operating items
 
 
 
 
 
 

 
 
Interest income
*
40

 
19

 
60

 
66

Interest expense
10 *
(261
)
 
(38
)
 
(285
)
 
(412
)
Loss on impairment of investments
11
—


—


(841
)
 
(895
)
Share in results from associated companies (net of tax)
18
(90
)
 
149

 
174

 
283

(Loss)/gain on derivative financial instruments
31 *
(31
)

(4
)

11

 
(74
)
Gain on debt extinguishment
 
—

 
—

 
19

 
47

Foreign exchange (loss)/gain
 
(4
)
 
—

 
(65
)
 
18

Loss on marketable securities
15
(64
)

(3
)

—

 
—

Reorganization items, net
4
(9
)

(3,365
)

(1,337
)
 
—

Other financial and non-operating items
*
(3
)
 
—

 
(44
)
 
(15
)
Total financial and other non-operating items
 
(422
)
 
(3,242
)
 
(2,308
)
 
(982
)
 
 
 
 
 
 
 
 
 
(Loss)/income before income taxes
 
(597
)
 
(3,855
)
 
(3,036
)
 
44

 
 
 
 
 
 
 
 
 
Income tax expense
12
(8
)
 
(30
)
 
(66
)
 
(199
)
Net loss
 
(605
)
 
(3,885
)
 
(3,102
)
 
(155
)
 
 
 
 
 
 
 
 
 
Net loss attributable to the parent
 
(602
)
 
(3,881
)
 
(2,973
)
 
(181
)
Net (loss)/gain attributable to the non-controlling interest
 
(2
)
 
(6
)
 
(129
)
 
26

Net (loss)/gain attributable to the redeemable non-controlling interest
 
(1
)
 
2

 
—

 
—

 
 
 
 
 
 
 
 
 
Basic loss per share (U.S. dollar)
 
(6.02
)
 
(7.71
)
 
(5.89
)
 
(0.36
)
Diluted loss per share (U.S. dollar)
 
(6.02
)
 
(7.71
)
 
(5.89
)
 
(0.36
)
* Includes transactions with related parties. Refer to Note 30 "Related party transactions".
See accompanying notes that are an integral part of these Consolidated Financial Statements.

F-5
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) / INCOME
for the period from July 2, 2018 through December 31, 2018 (Successor), the period from January 1, 2018 through July 1, 2018 (Predecessor) and the years ended December 31, 2017 (Predecessor) and 2016 (Predecessor)
(In $ millions)
 
 
Successor
 
Predecessor
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Twelve months ended December 31, 2017

 
Twelve months ended December 31, 2016

Net loss
(605
)
 
(3,885
)
 
(3,102
)
 
(155
)
 
 
 
 
 
 
 
 
Other comprehensive income/(loss), net of tax:
 

 
 
 
 

 
 

Unrealized gain on marketable securities
—

 
—

 
14

 
17

Change in fair value of debt component of Archer convertible bond
(3
)
 
—

 
—

 
—

Other than temporary impairment of marketable securities,
reclassification to Statement of Operations
—

 
—

 
—

 
153

Actuarial gain/(loss) relating to pensions
1

 
—

 
(3
)
 
22

Unrealized gain on interest rate swaps in VIEs and subsidiaries
—

 
—

 
2

 
1

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

 
(8
)
 
10

Other comprehensive (loss)/income:
(7
)
 
—

 
5

 
203

 
 
 
 
 
 
 
 
Total comprehensive (loss)/income for the period
(612
)
 
(3,885
)
 
(3,097
)
 
48

 
 
 
 
 
 
 
 
Comprehensive (loss)/income attributable to the parent
(609
)
 
(3,881
)
 
(2,976
)
 
14

Comprehensive (loss)/income attributable to the non-controlling interest
(2
)
 
(6
)
 
(121
)
 
34

Comprehensive (loss)/income attributable to the redeemable non-controlling interest
(1
)
 
2

 
—

 
—

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





F-6
Table of Contents

Seadrill Limited
CONSOLIDATED BALANCE SHEETS
As at December 31, 2018 (Successor) and 2017 (Predecessor)
(In $ millions)
 
 
Successor

 
Predecessor

 
Notes
2018


2017

ASSETS

 



Current assets

 

 
Cash and cash equivalents

1,542


1,255

Restricted cash
14
461


104

Marketable securities
15
57


124

Accounts receivables, net
16
208


295

Amount due from related parties - current
30
177


217

Other current assets
17
322


257

Total current assets

2,767


2,252

Non-current assets

 

 
Investment in associated companies
18
800


1,473

Newbuildings
19
—


248

Drilling units
20
6,659


13,216

Deferred tax assets
12
18


10

Equipment
21
29


29

Amount due from related parties - non-current
30
539


547

Assets held for sale
36
—


126

Other non-current assets
17
36


81

Total non-current assets

8,081


15,730

Total assets

10,848


17,982

LIABILITIES, REDEEMABLE NON-CONTROLLING INTEREST AND EQUITY

 

 
Current liabilities

 

 
Debt due within one year
22
33


509

Trade accounts payable

82


72

Amounts due to related parties - current
30
39


10

Other current liabilities
23
310


268

Total current liabilities

464


859

Liabilities subject to compromise
5
—


9,191

Non-current liabilities

 

 
Long-term debt
22
6,881


485

Long-term debt due to related parties
30
222


314

Deferred tax liabilities
12
87


107

Other non-current liabilities
23
121


67

Total non-current liabilities

7,311


973

Commitments and contingencies (see note 32)



 


Redeemable non-controlling interest
26
38


—

Equity

 

 
Common shares of par value US$0.10 per share: 111,000,000 shares authorized and 100,000,000 issued at December 31, 2018 (Successor) (Common shares of par value US$2.00 per share: 800,000,000 shares authorized and 504,518,940 issued at December 31, 2017 (Predecessor)
24
10


1,008

Additional paid in capital

3,491


3,313

Contributed surplus

—


1,956

Accumulated other comprehensive (loss)/income

(7
)

58

Retained (loss)/earnings

(611
)

225

Total Shareholder's equity

2,883


6,560

Non-controlling interest
25
152


399

Total equity

3,035


6,959

Total liabilities, redeemable non-controlling interest and equity

10,848


17,982

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

F-7
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the period from July 2, 2018 through December 31, 2018 (Successor), the period from January 1, 2018 through July 1, 2018 (Predecessor) and the years ended December 31, 2017 (Predecessor) and 2016 (Predecessor)
(In $ millions)
 
 
Successor
 
Predecessor
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

 
Year ended December 31, 2016

Cash Flows from Operating Activities
 
 
 
 
 
 
 
Net loss
(605
)
 
(3,885
)
 
(3,102
)
 
(155
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 
 
 
 
Depreciation
236

 
391

 
798

 
810

Amortization of deferred loan charges
—

 
—

 
27

 
45

Amortization of unfavorable and favorable contracts
58

 
(21
)
 
(43
)
 
(65
)
Share of results from associated companies
90

 
(149
)
 
(174
)
 
(283
)
Share-based compensation expense
—

 
3

 
7

 
8

Loss on disposals
—

 
—

 
245

 
—

Contingent consideration realized
—

 
(7
)
 
(27
)
 
(21
)
Interest unwind on contingent consideration assets
(1
)
 
—

 
—

 
—

Unrealized loss/(gain) related to derivative financial instruments
31

 
4

 
(76
)
 
(67
)
Loss on impairment of long-lived assets
—

 
414

 
696

 
44

Loss on impairment of investments
—

 
—

 
841

 
895

Deferred tax (benefit)/expense
(22
)
 
—

 
7

 
73

Unrealized foreign exchange loss/(gain) on long-term debt
—

 
—

 
59

 
(5
)
Amortization of discount on debt
23

 
—

 
—

 
—

Gain on derecognition of investment in associated company
—

 
—

 
(10
)
 
—

Gain on debt extinguishment
—

 
—

 
(19
)
 
(47
)
Unrealized loss on marketable securities
64

 
3

 
—

 
—

Non-cash gain on liabilities subject to compromise
—

 
(2,977
)
 
—

 
—

Fresh start valuation adjustments
—

 
6,142

 
—

 
—

Other re-organization items
—


6

 
1,274


—

Other
(2
)
 
(1
)
 
(2
)
 
(2
)
Other cash movements in operating activities
 
 
 
 
 
 
 
Distributions received from associated companies
32

 
17

 
39

 
55

Payments for long-term maintenance
(71
)
 
(78
)
 
(58
)
 
(95
)
Changes in operating assets and liabilities, net of effect of acquisitions and disposals
 
 
 
 
 
 
 
Trade accounts receivable
64

 
29

 
167

 
256

Trade accounts payable
(31
)
 
4

 
(9
)
 
(55
)
Prepaid expenses/accrued revenue
12

 
42

 
(66
)
 
15

Deferred revenue
21

 
(23
)
 
(107
)
 
(168
)
Related party receivables
7

 
(13
)
 
(42
)
 
2

Related party payables
54

 
(42
)
 
(44
)
 
(35
)
Other assets
(20
)
 
(62
)
 
93

 
55

Other liabilities
34

 
(10
)
 
(75
)
 
(76
)
Net cash (used in)/provided by operating activities
(26
)
 
(213
)
 
399

 
1,184



F-8
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
for the period from July 2, 2018 through December 31, 2018 , (Successor) the period from January 1, 2018 through July 1, 2018 (Predecessor) and the years ended December 31, 2017 (Predecessor) and 2016 (Predecessor)
(In $ millions)
 
 
Successor
 
Predecessor
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

 
Year ended December 31, 2016

Cash Flows from Investing Activities
 
 
 
 
 
 
 
Additions to newbuildings
—

 
(1
)
 
(33
)
 
(52
)
Additions to drilling units and equipment
(27
)
 
(48
)
 
(59
)
 
(84
)
Refund of yard installments
—

 
—

 
25

 
53

Contingent consideration received
65

 
48

 
95

 
95

Settlement of West Mira
—

 
—

 
170

 
—

Sale of rigs and equipment
—

 
126

 
122

 
—

Buyout of guarantee
—

 
—

 
(28
)
 
—

Investment in associated companies
—

 
—

 
—

 
(16
)
Payments received from loans granted to related parties
23

 
24

 
66

 
283

Loans granted to related parties
—

 
—

 
—

 
(120
)
Proceeds from disposal of marketable securities
—

 
—

 
—

 
195

Net cash provided by investing activities
61

 
149

 
358

 
354

 
 
 
 
 
 
 
 
Cash Flows from Financing Activities
 
 
 
 
 
 
 
Proceeds from debt
—

 
875

 
—

 
—

Repayments of debt
(83
)
 
(153
)
 
(754
)
 
(1,253
)
Mandatory redemption of New Secured Notes
(121
)
 
—

 
—

 
—

Debt fees paid
(4
)
 
(35
)
 
(53
)
 
(31
)
Repayments of debt to related party
—

 
—

 
(39
)
 
(103
)
Dividends paid to non-controlling interests
—

 
—

 
—

 
(7
)
Purchase of treasury shares
—

 
—

 
—

 
(10
)
Cash settlement of restricted stock units
—


—

 
—


(1
)
Proceeds from issuance of shares
—

 
200

 
—

 
—

Net cash (used in)/provided by financing activities
(208
)
 
887

 
(846
)
 
(1,405
)
 
 
 
 
 
 
 
 
Effect of exchange rate changes on cash and cash equivalents
(1
)
 
(5
)
 
5

 
18

 
 
 
 
 
 
 
 
Net (decrease)/increase in cash and cash equivalents, including restricted cash
(174
)
 
818

 
(84
)
 
151

Cash and cash equivalents, including restricted cash, at beginning of the year
2,177

 
1,359

 
1,443

 
1,292

Cash and cash equivalents, including restricted cash, at the end of year
2,003

 
2,177

 
1,359

 
1,443

 
 
 
 
 
 
 
 
Supplementary disclosure of cash flow information
 
 
 
 
 
 
 
Interest paid, net of capitalized interest
(178
)
 
(38
)
 
(264
)
 
(400
)
Taxes paid
(16
)
 
(22
)
 
(119
)
 
(123
)

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


F-9
Table of Contents

Seadrill Limited
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
for the period from July 2, 2018 through December 31, 2018 (Successor), the period from January 1, 2018 through July 1, 2018 (Predecessor) and the years ended December 31, 2017 (Predecessor) and 2016 (Predecessor)
(In $ millions)

 
 
Common shares

 
Additional paid in capital

 
Contributed surplus

 
Accumulated other comprehensive income/(loss)

 
Retained Earnings

 
Total equity before NCI

 
Non-controlling interest

 
Total equity

Balance at December 31, 2015 (Predecessor)
 
985

 
3,275

 
1,956

 
(142
)
 
3,379

 
9,453

 
615

 
10,068

Purchase of treasury shares
 
(8
)
 
(2
)
 
—

 
—

 
—

 
(10
)
 
—

 
(10
)
Share-based compensation charge
 
—

 
7

 
—

 
—

 
—

 
7

 
—

 
7

Cash settlement of vested restricted stock units
 
—

 
(1
)
 
—

 
—

 
—

 
(1
)
 
—

 
(1
)
Conversion of convertible bond
 
31

 
27

 
—

 
—

 
—

 
58

 
—

 
58

Recognition of non-controlling interest
 
—

 
—

 
—

 
—

 
—

 
—

 
6

 
6

Other comprehensive income
 
—

 
—

 
—

 
195

 
—

 
195

 
8

 
203

Distribu tions to Non-controlling interests
 
—

 
—

 
—

 
—

 
—

 
—

 
(113
)
 
(113
)
Net loss
 
—

 
—

 
—

 
—

 
(181
)
 
(181
)
 
26

 
(155
)
Balance at December 31, 2016 (Predecessor)
 
1,008

 
3,306

 
1,956

 
53

 
3,198

 
9,521

 
542

 
10,063

Share-based compensation charge
 
—

 
7

 
—

 
—

 
—

 
7

 
—

 
7

Other comprehensive income
 
—

 
—

 
—

 
5

 
—

 
5

 
—

 
5

Distributions to non-controlling interests
 
—

 
—

 
—

 
—

 
—

 
—

 
(14
)
 
(14
)
Net loss
 
—

 
—

 
—

 
—

 
(2,973
)
 
(2,973
)
 
(129
)
 
(3,102
)
Balance at December 31, 2017 (Predecessor)
 
1,008

 
3,313

 
1,956

 
58

 
225

 
6,560

 
399

 
6,959

ASU 2016-01 - Financial Instruments

—


—


—


(31
)

31


—


—


—

ASU 2016-16 - Income Taxes

—


—


—


—


(59
)

(59
)

(25
)

(84
)
ASU 2016-09 - Revenue from contracts

—


—


—


—


7


7


—


7

Share-based compensation charge
 
—

 
9

 
—

 
—

 
—

 
9

 
—

 
9

Reclassification of non-controlling interest
 
—

 
—

 
—

 
—

 
(43
)
 
(43
)
 
43

 
—

Revaluation of redeemable non-controlling interest
 
—

 
—

 
—

 
—

 
127

 
127

 
(150
)
 
(23
)
Net loss
 
—

 
—

 
—

 
—

 
(3,881
)
 
(3,881
)
 
(6
)
 
(3,887
)
Balance at July 1, 2018 (Predecessor)
 
1,008


3,322


1,956


27


(3,593
)

2,720


261


2,981

Cancellation of Predecessor equity
 
(1,008
)

(3,322
)

(1,956
)

(27
)

3,593


(2,720
)

(107
)

(2,827
)
Balance at July 1, 2018 (Predecessor)
 
—


—


—


—


—


—


154


154

Issuance of Successor common stock

10


3,491


—


—


—


3,501


—


3,501

Balance at July 2, 2018 (Successor)
 
10


3,491


—


—


—


3,501


154


3,655

Revaluation of redeemable non-controlling interest

—


—


—


—


(9
)

(9
)

—


(9
)
Net Loss

—


—


—


—


(602
)

(602
)

(2
)

(604
)
Other comprehensive loss

—


—


—


(7
)

—


(7
)

—


(7
)
Balance at December 31, 2018 (Successor)
 
10


3,491


—


(7
)

(611
)

2,883


152


3,035

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




F-10
Table of Contents

Seadrill Limited
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – General information
 
Seadrill Limited is incorporated in Bermuda and is a publicly listed company on the New York Stock Exchange and the Oslo Stock Exchange. We provide offshore drilling services to the oil and gas industry. As at December 31, 2018 we owned and operated 35 offshore drilling units and an option to acquire on semi-submersible rig. Our fleet consists of drillships, jack-up rigs and semi-submersible rigs for operations in shallow and deepwater areas, as well as benign and harsh environments. We also provide management services to our related parties Seadrill Partners, Northern Drilling and SeaMex.

As used herein, the term "Predecessor" refers to the financial position and results of operations of Seadrill Limited prior to, and including, July 1, 2018. This is also applicable to terms "we", "our", "Group" or "Company" in context of events prior to, and including, July 1, 2018. As used herein, the term "Successor" refers to the financial position and results of operations of Seadrill Limited (previously "New Seadrill") after July 1, 2018. This is also applicable to terms "Seadrill Limited", "we", "our", "Group" or "Company" in context of events after July 1, 2018.

The use herein of such terms as "Group", "organization", "we", "us", "our" and "its", or references to specific entities, is not intended to be a precise description of corporate relationships.

Basis of presentation
 
The Consolidated Financial Statements are presented in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). The amounts are presented in United States dollar ("U.S. dollar" or "US$") rounded to the nearest million, unless otherwise stated.
 
The accompanying Consolidated Financial Statements present the financial position of Seadrill Limited, the consolidated subsidiaries and the group’s interest in associated entities. Investments in companies in which we control, or directly or indirectly holds more than 50% of the voting control are consolidated in the Consolidated Financial Statements, as well as certain variable interest entities of which we are deemed to be the primary beneficiary.

Basis of consolidation
 
The Consolidated Financial Statements include our assets and liabilities, our majority owned and controlled subsidiaries and certain variable interest entities, (“VIE”s) in which we are deemed to be the primary beneficiary. All intercompany balances and transactions have been eliminated on consolidation.
 
A VIE is defined as a legal entity where either (a) the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated support; (b) equity interest holders as a group lack either (i) the power to direct the activities of the entity that most significantly impact on its economic success, (ii) the obligation to absorb the expected losses of the entity, or (iii) the right to receive the expected residual returns of the entity; or (c) the voting rights of some investors in the entity are not proportional to their economic interests and the activities of the entity involve or are conducted on behalf of an investor with a disproportionately small voting interest. U.S. GAAP requires a VIE to be consolidated by its primary beneficiary, being the interest holder, if any, which has both (1) the power to direct the activities of the entity which most significantly impact on the entity’s economic performance, and (2) the right to receive benefits or the obligation to absorb losses from the entity which could potentially be significant to the entity. We evaluate our subsidiaries, and any other entities in which we hold a variable interest, in order to determine whether we are the primary beneficiary of the entity, and where it is determined that we are the primary beneficiary we consolidate the entity.
 
We have certain investments in the common stock or in-substance common stock of associated companies. Refer to Note 2 – Accounting policies for further information on our equity investments.

Bankruptcy accounting

As set out in Note 4 - Chapter 11 Proceedings, we operated as a debtor-in-possession from September 12, 2017 to July 2, 2018. During this period, we prepared our Consolidated Financial Statements under Accounting Standards Codification 852, Reorganizations ("ASC 852"). ASC 852 required that the financial statements distinguished transactions and events that were directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred in the bankruptcy proceedings were recorded in “Reorganization items" on our Consolidated Statements of Operations. In addition, ASC 852 required changes in the accounting and presentation of significant items on the Consolidated Balance Sheets, particularly liabilities. Pre-petition obligations that may have been impacted by the Chapter 11 reorganization process were classified on the Consolidated Balance Sheets within "Liabilities subject to compromise". 


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Fresh Start Reporting

Upon emergence from bankruptcy on July 2, 2018 (the "Effective Date"), in accordance with ASC 852 related to fresh start reporting, Seadrill Limited became a new entity for financial reporting purposes. Upon adoption of fresh start reporting, our assets and liabilities were recorded at their fair values. We elected to apply fresh start reporting effective July 2, 2018 (the “Convenience Date”) to coincide with the timing of our normal third quarter reporting period. We evaluated and concluded that events between July 1, 2018 and July 2, 2018 were immaterial and use of an accounting convenience date was appropriate. The fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in the Predecessor historical Consolidated Balance Sheets. The effects of the Plan and the application of fresh start accounting were applied as of July 2, 2018 and the new basis of our assets and liabilities are reflected in our Consolidated Balance Sheet as of December 31, 2018 and the related adjustments thereto were recorded in the Consolidated Statement of Operations of the Predecessor as "Reorganization items", with the related predominantly deferred tax effects through "Income tax expense", during the period from January 1, 2018 through July 1, 2018.

Accordingly, our Consolidated Financial Statements subsequent to July 2, 2018 are not and will not be comparable to the Predecessor Consolidated Financial Statements prior to the Convenience Date. Our Consolidated Financial Statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on July 2, 2018 and dates prior. Our financial results for future periods following the application of fresh start accounting will be different from historical trends and the differences may be material.

Going concern

In our Form 20-F covering our annual report for the fiscal year ended December 31, 2017, issued on April 12, 2018, we reported that uncertainties linked to our Chapter 11 Re-organization gave rise to a substantial doubt over our ability to continue as a going concern for a period of at least twelve months after the date the financial statements were issued.

As set out in Note 4 - Chapter 11 Proceedings, we emerged from the Chapter 11 and completed our plan of reorganization on July 2, 2018. This addressed our liquidity concerns as it provided for $1.08 billion of new capital, extinguished approximately $2.4 billion in unsecured bond obligations and approximately $250 million in unsecured interest rate and currency swaps, eliminated near-term amortization obligations and extended maturities on debt. We emerged from Chapter 11 with $2.2 billion of post emergence cash and $7.6 billion of outstanding debt principal. We believe that cash on hand, liquid investments, contract and other revenues will generate sufficient cash flow to fund our anticipated debt service and working capital requirements for the next twelve months. Therefore, there is no longer a substantial doubt over our ability to continue as a going concern for at least the twelve months after the date the financial statements are issued.

Out of period adjustment

The financial statements for the period from January 1, 2018 through July 1, 2018 (Predecessor) include an income tax expense of $18 million due to an adjustment in the income tax charge for a subsidiary related to prior years. We considered the effect of this prior period correction not to be material in the context of the overall results for the period from January 1, 2018 through July 1, 2018 (Predecessor), the year ended December 31, 2017 (Predecessor), or to any previously reported quarterly or annual financial statements.


Note 2 – Accounting policies
 
The accounting policies set out below have been applied consistently to all periods in these Consolidated Financial Statements, unless otherwise noted.

Use of estimates

Preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Foreign currencies
 
The majority of our revenues and expenses are denominated in U.S. dollars and therefore the majority of our subsidiaries use U.S. dollars as their functional currency. Our reporting currency is also U.S. dollars. For subsidiaries that maintain their accounts in currencies other than U.S. dollars, we use the current method of translation whereby the Statement of Operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year-end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in shareholders' equity.

Transactions in foreign currencies are translated into U.S. dollars at the rates of exchange in effect at the date of the transaction. Foreign currency assets and liabilities are translated using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the Consolidated Statements of Operations.

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Related parties
 
Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence. Refer to Note 30 – Related Party Transactions.

Revenue from contracts with customers

The activities that primarily drive the revenue earned from our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services as a single performance obligation that is (i) satisfied over time and (ii) comprised of a series of distinct time increments.

We recognize consideration for activities that correspond to a distinct time increment within the contract term in the period when the services are performed. We recognize consideration for activities that are (i) not distinct within the context of our contracts and (ii) do not correspond to a distinct time increment, ratably over the estimated contract term.

We determine the total transaction price for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. The amount estimated for variable consideration may be constrained and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, we consider whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. We re-assess these estimates each reporting period as required. Refer to Note 7 - Revenue from Contracts with Customers.

Dayrate Drilling Revenue - Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.

Mobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the expected term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract.

Demobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the demobilization of our rigs. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized over the term of the contract. In most of our contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, the amount may vary dependent upon whether or not the rig has additional contracted work following the contract. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.

Revenues Related to Reimbursable Expenses - We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, at a point in time, as “Reimbursable revenues” in our Consolidated Statements of Operations.

Contract Balances - Accounts receivable is recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Contract asset balances consist primarily of demobilization revenues which have been recognized during the period but are contingent on future demobilization activities. Contract liabilities include payments received for mobilization as well as rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.

Local Taxes - In some countries, the local government or taxing authority may assess taxes on our revenues. Such taxes may include sales taxes, use taxes, value-added taxes, gross receipts taxes and excise taxes. We generally record tax-assessed revenue transactions on a net basis.

Deferred Contract Costs - Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract.


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Other revenues

Other revenues consist of related party revenues, external management fees, and early termination fees. Refer to Note 8 – Other revenues.

Related party revenues - Related party revenues relate to management support and administrative services provided to Seadrill Partners, Northern Drilling and SeaMex. External management fees relate to the operational, administrative and support services provided to third parties.

External management fees - External management fees relate to the operational, administrative and support services that we previously provided to Sapura Energy as part of the agreement that we entered into when we sold majority of the tender rig business.

Early termination fees - Other revenues also include amounts recognized as early termination fees under drilling contracts which have been terminated prior to the contract end date. Contract termination fees are recognized daily as and when any contingencies or uncertainties are resolved.

Vessel and Rig Operating Expenses

Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked and include the remuneration of offshore crews and related costs, rig supplies, insurance costs, expenses for repairs and maintenance and costs for onshore support personnel. We expense such costs as incurred.

On emergence, we classified certain costs as "vessel and rig operating expenses" that are directly attributable to rig activities and had previously been classified as "general and administrative expenses" in our Consolidated Statements of Operations.

Mobilization and demobilization expenses
  
We incur costs to prepare a drilling unit for a new customer contract and to move the rig to a new contract location. We capitalize the mobilization and preparation costs for a rig's first contract as a part of the rig value and recognize them as depreciation expense over the expected useful life of the rig (i.e. 30 years). For subsequent contracts, we defer these costs over the expected contract term (see deferred contract costs above), unless we don't expect the costs to be recoverable, in which case we expense them as incurred.

We incur costs to transfer a drilling unit to a safe harbor or different geographic area at the end of a contract. We expense such demobilization costs as incurred. We also expense any costs incurred to relocate drilling units that are not under contract. 

Repairs, maintenance and periodic surveys
 
Costs related to periodic overhauls of drilling units are capitalized and amortized over the anticipated period between overhauls, which is generally five years. Related costs are primarily yard costs and the cost of employees directly involved in the work. We include amortization costs for periodic overhauls in depreciation expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and are expensed as incurred.

Income taxes
 
Seadrill is a Bermuda company that has subsidiaries and affiliates in various jurisdictions. Currently, Seadrill and our Bermudan subsidiaries and affiliates are not required to pay taxes in Bermuda on ordinary income or capital gains as they qualify as exempt companies. Seadrill and our subsidiaries and affiliates have received written assurance from the Minister of Finance in Bermuda that we will be exempt from taxation until March 2035. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income and statutory tax rates 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 operations are conducted and income is earned. Refer to Note 12 – Taxation.

The determination and evaluation of our annual group income tax provision involves interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amounts, timing and character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are more likely than not sustainable, based solely on the technical merits and considerations of the relevant taxing authorities widely understood administrative practices and precedence. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments.

Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. We recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the Consolidated Statement of Operations as income tax expense (or benefit) in the period of sale or transfer occurs.


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

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. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

Earnings per share
 
Basic earnings per share (“EPS”) is calculated based on the income/(loss) for the period available to common stockholders divided by the weighted average number of shares outstanding for basic EPS for the period. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments such as our restricted stock units. The determination of dilutive earnings per share may require us to make adjustments to net income and the weighted average shares outstanding. Refer to Note 13 – Loss per share.

Current and non-current classification
 
Generally, assets and liabilities (excluding deferred taxes and liabilities subject to compromise) are classified as current assets and liabilities respectively if their maturity is within one year of the balance sheet date. In addition, we classify any derivative financial instruments whose fair value is a net liability as current.

Generally, assets and liabilities are classified as non-current assets and liabilities respectively if their maturity is beyond one year of the balance sheet date. In addition, we classify loan fees based on the classification of the associated debt principal and we classify any derivatives financial instruments whose fair value is a net asset as non-current.
 
Cash and cash equivalents
 
Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with maturities of three months or less.
 
Restricted cash
 
Restricted cash consists of bank deposits which are subject to restrictions due to legislation, regulation or contractual arrangements. Restricted cash amounts with maturities longer than one year are classified as non-current assets. Refer to Note 14 – Restricted cash .

Receivables
 
Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount less an allowance for doubtful accounts. We establish reserves for doubtful accounts on a case-by-case basis when it is unlikely that required payments of specific amounts will occur. In establishing these reserves, we consider the financial condition of the customer as well as specific circumstances related to the receivable such as customer disputes. Receivable amounts determined as being unrecoverable are written off. Interest income on receivables is recognized as earned. Refer to Note 16 – Accounts receivable.
 
Equity investments

Investments in common stock are accounted for using the equity method of accounting if the investment gives us the ability to exercise significant influence, but not control over, the investee. Significant influence is generally deemed to exist if our ownership interest in the voting stock of the investee is between 20% and 50%, although other factors such as representation on the investee’s Board of Directors and the nature of commercial arrangements are also considered. We classify our other equity investments either as "Marketable Securities" or "Investments in Associated Companies" depending on their nature. We classify our share of earnings or losses from our equity method investments in the Consolidated Statements of Operations as “Share in results from associated companies". We record gains or losses on investments held fair value as "Gains / (losses) on Marketable Securities". Refer to Note 15 – Marketable securities and Note 18 – Investment in associated companies.
 
We analyze our equity method investments for impairment at each reporting period to evaluate whether an event or change in circumstances has occurred in that period that may have a significant adverse effect on the value of the investment. We record an impairment charge for other-than-temporary declines in value when the value is not anticipated to recover above the cost within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required. If an impairment charge is recorded, subsequent recoveries in value are not reflected in earnings until sale of the equity method investee occurs.

All other equity investments, which consist of investments that do not gives us the ability to exercise significant influence as well as investments in equity instruments other than common stock, are accounted for at fair value, if readily determinable. If we can’t readily ascertain the fair value, we record the investment at cost less impairment.  We perform a qualitative impairment analysis for our equity investments recorded at

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cost at each reporting period to evaluate whether an event or change in circumstances has occurred in that period that indicates that the investment's is impaired. If an event or change in circumstances has occurred in that period that indicates that the investment's is impaired, then we record an impairment charge for the difference between the estimated fair value of the investment and its carrying amount.

For periods before we adopted ASU 2016-01, we reviewed our marketable securities for other-than-temporary impairment at each reporting date. Refer to Note 11 - Impairment loss on marketable securities and investments in associated companies for details.

Newbuildings
 
Generally, the carrying value of drilling units under construction (“Newbuildings”) represents the accumulated costs at the balance sheet date. Cost components usually include payments for yard installments and variation orders, construction supervision, equipment, spare parts, capitalized interest, costs related to first time mobilization and commissioning costs. During construction, capitalized interest of newbuildings is based on accumulated expenditures for the applicable project at our current rate of borrowing. The amount of interest expense capitalized in an accounting period is determined by applying the interest rate (“the capitalization rate”) to the average amount of accumulated expenditures for the asset during the period. We don't capitalize amounts beyond the actual interest expense incurred in the period.
 
We ceased capitalization of interest on newbuildings when we operated as a debtor-in-possession as interest payments made during bankruptcy proceedings were treated as adequate protection payments. On emergence from Chapter 11, the Newbuildings carrying value was adjusted to a fair value of nil. In addition, we have not capitalized interest since emergence as work on our Newbuild projects had substantially ceased. Refer to Note 5 – Fresh Start Accounting and Note 19 – Newbuildings.

Drilling units
 
Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated residual value is taken to be offset by any decommissioning costs that may be incurred. The estimated economic useful life of our floaters and, jack-up rigs, when new, is 30 years. Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset’s value for its remaining useful life are capitalized and depreciated over the remaining life of the asset. Refer to Note 20 – Drilling units.

Drilling units recognized through a business combination or through the application of fresh start accounting are measured at fair value as of the date of acquisition or the date of emergence, respectively.

Cost of property and equipment sold or retired, with the related accumulated depreciation and write-downs are removed from the Consolidated Balance Sheet, and resulting gains or losses are included in the Consolidated Statement of Operations.

Assets held for sale

Assets are classified as held for sale when all of the following criteria are met: Management, having the authority to approve the action, commits to a plan to sell the asset (disposal group), the asset is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets, an active program to locate a buyer and other actions required to complete the plan to sell the asset (disposal group) have been initiated, the sale of the asset is probable, and transfer of the asset is expected to qualify for recognition as a completed sale, within 1 year. The term probable refers to a future sale that is likely to occur, the asset is being actively marketed for sale at a price that is reasonable in relation to its current fair value and actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

On emergence from Chapter 11, we no longer had any assets classified as held for sale. Refer to Note 36 – Assets held for sale.

Equipment
 
Equipment is recorded at historical cost less accumulated depreciation and is depreciated over its estimated remaining useful life. The estimated economic useful life of equipment, when new, is between 3 and 5 years depending on the type of asset. Refer to Note 21 – Equipment.
 
Impairment of long-lived assets
 
We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We first assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposal. If the undiscounted future net cash flows are less than the carrying value of the asset, then we compare the carrying value of the asset with the discounted future net cash flows, using a relevant weighted-average cost of capital. The impairment loss to be recognized during the period, will be the amount which the carrying value of the asset exceeds the discounted future net cash flows. Refer to Note 20 – Drilling units.

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Other intangible assets and liabilities
 
Intangible assets and liabilities were recorded at fair value on the date of emergence less accumulated amortization. The amounts of these assets and liabilities less the estimated residual value, if any, is generally amortized on a straight-line basis over the estimated remaining economic useful life or contractual period. For periods after emergence we have applied a new accounting policy to classify amortization of these intangible assets and liabilities within operating expenses. Our intangible assets include favorable and unfavorable drilling contracts and management services contracts. Refer to Note 17 – Other assets. Our intangible liabilities include unfavorable drilling contracts and unfavorable leasehold improvements. Refer to Note 23 – Other liabilities.

Prior to emergence, we classified the amortization of these intangible assets or liabilities within other revenues.

Derivative financial instruments and hedging activities
 
On emergence from Chapter 11, we have an interest-rate cap financial instrument that has not been formally designated as a hedge and is recorded at fair value. Changes in the fair value are recorded as a gain or loss as a separate line item within "financial items" in the Consolidated Statements of Operations. Refer to Note 31 – Financial instruments and risk management and Note 32 - Fair values of financial instruments .

Trade payables

Trade payables are recorded in the balance sheet to recognize a liability to a supplier for a good or service they have provided us.

Deferred charges
 
Loan related costs, including debt issuance, arrangement fees and legal expenses, are capitalized and presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, amortized over the term of the related loan and the amortization is included in interest expense. On emergence from Chapter 11, our loan costs were reduced to nil and we recorded a discount against our debt to reduce its carrying value to equal its fair value. The debt discount will be unwound over the remaining terms of the debt facilities. Refer to Note 5 – Fresh Start Accounting and Note 10 – Interest expense.

Debt

We have financed a significant proportion of the cost of acquiring our fleet of drilling units through the issue of debt instruments. At the inception of a term debt arrangement, or whenever we make the initial drawdown on a revolving debt arrangement, we will incur a liability for the principal to be repaid. On emergence from Chapter 11, we issued new debt instruments and the carrying values of our third-party debt liabilities were adjusted to fair value. Refer to Note 5 – Fresh start accounting and Note 22 – Debt for more information on our debt instruments.

Pension benefits
 
We have several defined benefit pension plans, defined contribution pension plans and other post-employment benefit obligations which provide retirement, death and early termination benefits. We record the service cost, as “Vessel and rig operating expenses” or as "General and administrative expenses" in our Consolidated Statements of Operations depending on the whether or not the related employee's role is directly attributable to rig activities. We record the actuarial gains and losses in the Consolidated Statements of Operations when the net cumulative unrecognized actuarial gains or losses for each individual plan at the end of the previous reporting year exceed 10 percent of the higher of the present value of the defined benefit obligation and the fair value of plan assets at that date. These actuarial gains and losses are recognized over the expected remaining working lives of the employees participating in the plans. Otherwise, recognition of actuarial gains and losses is included in other comprehensive income.   Refer to Note 29 - Pension benefits for more information on the accounting for these pension benefits / pension expense.

Loss contingencies

We recognize a loss contingency in the Consolidated Balance Sheet where we have a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Refer to Note 33 – Commitments and contingencies.

Treasury shares
 
Treasury shares are recognized at cost as a component of equity. We record the nominal value of treasury shares purchased as a reduction in share capital. The amount paid in excess of the nominal value is treated as a reduction of additional paid-in capital. On emergence from Chapter 11, we no longer have any treasury shares.
 

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Share-based compensation
 
On emergence from Chapter 11, we had one Restricted Stock Unit (“RSU”) plan where the holder of an award is entitled to receive shares if still employed at the end of the three -year vesting period. There is no requirement for the holder to pay for the share on grant or vesting of the award. The fair value of the RSU award is calculated as the market share price on grant date. The fair value of the awards expected to vest is recognized as compensation cost straight-line over the vesting period. We have made the election to account for forfeitures on an actual basis as they occur. Refer to Note 28 – Share Based Compensation.
 

Note 3 - Recent Accounting Standards

We adopted the following accounting standard updates ("ASUs") in the year:

ASU 2014-09 - Revenue from contracts with customers

In May 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition. Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services and in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services.

We adopted ASU 2014-09 and its related amendments, or collectively Topic 606, effective January 1, 2018 using the modified retrospective method. Accordingly, we have applied the five-step method outlined in Topic 606 for determining when and how revenue is recognized to all contracts that were not completed as of the date of adoption. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance. For contracts that were modified before the effective date, we have considered the modification guidance within the new standard and determined that the revenue recognized and contract balances recorded prior to adoption for such contracts were not impacted. While Topic 606 requires additional disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, its adoption has not had a material impact on the measurement or recognition of our revenues.

As we have transitioned to the new standard under the modified retrospective method, we have recorded the cumulative impact of applying the new guidance as an adjustment to opening retained earnings on January 1, 2018. The total adjustment was $7 million which represented the earned portion of demobilization revenue expected to be received for contracts not completed as of December 31, 2017, which was not previously recognized until demobilization occurred.

See Note 7 - Revenue from contracts for further information.
 
ASU 2016-01 Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which made targeted improvements to the recognition and measurement of financial assets and financial liabilities.

The update changes how entities measure equity investments that do not result in consolidation and are not accounted for under the equity method and how they present changes in the fair value of financial liabilities measured under the fair value option that are attributable to their own credit. The new guidance also changes certain disclosure requirements and other aspects of current U.S. GAAP. The standard does not change the guidance for classifying and measuring investments in debt securities.

After adopting ASU 2016-01 we continue to record equity investments that do not result in consolidation and are not accounted for under the equity method at fair value (unless the fair value is not readily ascertainable). However, we will record changes in fair value directly to net income whereas previously we recorded such changes to other comprehensive income until realized. We have made the election available under ASC 321-10-35-2 to record equity investments with no readily ascertainable fair value at cost less impairment.

We transitioned to the new standard using the modified retrospective approach. Accordingly, we recorded the cumulative effect of adopting the update at the date of adoption. We reclassified $31 million of previously recognized fair value gains from accumulated other comprehensive income to retained earnings on January 1, 2018.

ASU 2016-16 Income Taxes - Income taxes intra-entity transfers of assets other than inventory

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Income taxes Intra-Entity Transfers of Assets other than Inventory, which requires companies to recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the Consolidated Statement of Operations as income tax expense (or benefit) in the period that the sale or transfer occurs. The exception to recognizing the income tax effects of intercompany sales or transfers of assets remains in place for intercompany inventory sales and transfers, i.e. companies will still be required to defer the income tax effects of intercompany inventory transactions.


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We adopted the new standard effective January 1, 2018 under the modified retrospective approach. As a result of the modified retrospective application, “Other Assets” was reduced in our Condensed Consolidated Balance Sheet with a cumulative adjustment to retained earnings of $59 million and non-controlling interests of $25 million .
 
ASU 2016-18 Statement of Cash Flows - Restricted Cash

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, to address classification of activity related to restricted cash and restricted cash equivalents in the cash flows. The standard eliminates the presentation of transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents and restricted cash equivalents are presented in more than one line item on the balance sheet, a reconciliation of the totals in the cash flows to the related captions in the balance sheet are required, either on the face of the cash flow or in the notes to the Consolidated Financial Statements. Additional disclosures are required for the nature of the restricted cash and restricted cash equivalents.

The standard is effective for fiscal years beginning after 15 December 2017. We have adopted the new standard effective January 1, 2018 under the retrospective approach. The result of this adoption was a classification adjustment on our Consolidated Statement of Cash Flows for each of the years presented.

Other ASUs

We adopted the following ASUs in the year, none of which had any impact on our Consolidated Financial Statements and related disclosures:

•
ASU 2016-15 Statement of Cash Flows (Topic 230) — Classification of Certain Cash Receipts and Cash Payments
•
ASU 2017-01 Business Combinations (Topic 805)— Clarifying the Definition of a Business
•
ASU 2017-03 Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Ventures (Topic 323)
•
ASU 2017-04 Intangibles (Topic 350)— Simplifying the Test for Goodwill Impairment
•
ASU 2017-05 Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20)
•
ASU 2017-07 Compensation - Retirement Benefits (Topic 715)
•
ASU 2017-09 Compensation - Stock Compensation (Topic 718)
ASU 2018-02 Income Statement—Reporting Comprehensive Income (Topic 220)
•
ASU 2018-03 Technical Corrections and Improvements to Financial Instruments—Overall (Subtopic 825-10)
•
ASU 2018-04 Investments—Debt Securities (Topic 320) and Regulated Operations (Topic 980)
•
ASU 2018-05 Income Taxes (Topic 740)
•
ASU 2018-06 Codification Improvements to (Topic 942)
•
ASU 2018-19 Codification Improvements to (Topic 326)
 
Recently Issued Accounting Standards

The FASB have issued the following ASUs that we have not yet adopted but which could affect our Consolidated Financial Statements and related disclosures in future periods.

•
ASU 2016-02 Leases (Topic 842) (also 2018-01, 2018-10, 2018-11. 2018-20)
•
ASU 2016-13 Financial Instruments — Credit Losses (Topic 326)
•
ASU 2018-07 Compensation-Stock Compensation (Topic 718)
•
ASU 2018-13 Fair Value Measurement (Topic 820)
•
ASU 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans (Subtopic 715-20)
•
ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40)
•
ASU 2018-16 Derivatives and Hedging (Topic 815)
•
ASU 2018-17 Consolidation (Topic 810)

ASU 2016-02 - Leases (also 2018-01, 2018-10, 2018-11. 2018-20)

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update required an entity to recognize right-of-use assets and lease
liabilities on its balance sheet and disclose key information about leasing arrangements. It also offered specific accounting guidance for a lessee, a lessor and sale and leaseback transactions. Lessees and lessors are required to disclose qualitative and quantitative information about leasing arrangements to enable a user of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal year, using a modified retrospective application.

Effective January 1, 2019, we will adopt Topic 842 using the modified retrospective application through a cumulative-effect adjustment to retained earnings at January 1, 2019. We have elected the following transition practical expedients, which will be applied consistently to all leases that commenced before January 1, 2019:

1.
We will not reassess whether any expired or existing contracts are or contain leases.
2.
We will not reassess the lease classification for any expired or existing leases.

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3.
We will not reassess initial direct costs for any existing leases.
4.
We will use hindsight in determining the lease term and in assessing impairment of the right-of-use assets.

We have determined that our drilling contracts contain a lease component, however, we have elected not to separate the drilling contract lease and non-lease components. We have determined that the non-lease component in our drilling contracts is the predominant component. As such, we will continue to account for our drilling contracts under the guidance in Topic 606. We do not expect our pattern of revenue recognition to change significantly compared to current accounting standards.

We have determined that adoption of this standard will result in increased disclosure of our leasing arrangements. Additionally, we will recognize lease liabilities and corresponding right-of-use assets for leasing arrangements where we are a lessee. We expect to recognize an aggregate lease liability of between $20 million to $40 million on adoption. We have provided a summary of our commitments under operating leases at December 31, 2018 in Note 34 - Operating leases.

ASU 2016-13 - Financial Instruments - Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which revises guidance for the accounting for credit losses on financial instruments within its scope. The new standard introduces an approach, based on expected losses, to estimate credit losses on certain types of financial instruments and modifies the impairment model for available-for-sale debt securities. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted only from January 1, 2019. Entities are required to apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as at the beginning of the first reporting period in which the guidance is adopted.

We are in the early stage of evaluating the impact of this standard update. Our customers are international oil companies, national oil companies and large independent oil companies. Our financial assets are primarily held with counter parties with high credit standing and we have historically had a low incidence of bad debt expense. Therefore, we do not currently expect this guidance to significantly affect our Consolidated Financial Statements and related disclosures when we adopt it.

ASU 2018-07 Compensation - Stock Compensation

In June 2018, the FASB issued ASU 2018-07, Stock Compensation (Topic 718): Improvements to non-employee share-based payment accounting, which intended to reduce cost and complexity and to improve financial reporting for share-based payments issued to non-employees. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted.

We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.

ASU 2018-13 Fair Value Measurement - Changes to the Disclosure Requirements for Fair Value Measurement

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The update is intended to improve the effectiveness of disclosures in the notes to financial statements by facilitating clear communication of the US GAAP information requirements that are most important to users of an entity’s financial statements. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted.

We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.

ASU 2018-14 Compensation - Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued ASU 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans- General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans. The update is intended to improve the effectiveness of disclosures in the notes to financial statements by facilitating clear communication of the US GAAP information requirements that are most important to users of an entity’s financial statements. The guidance will be effective for annual and interim periods beginning after December 15, 2020, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.

ASU 2018-15 Intangibles

In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force). The update is intended to provide additional guidance on the accounting for costs of implementation activities performed in a cloud computing arrangement that is a service contract. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.


F-20
Table of Contents

ASU 2018-16 Derivatives and Hedging

In October 2018, the FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes. The update is intended to permit use of the OIS rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815 in addition to the direct Treasury obligations of the U.S. government, the LIBOR swap rate, the OIS rate based on the Fed Funds Effective Rate, and the Securities Industry and Financial Markets Association Municipal Swap Rate. The guidance will be effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted if an entity has already adopted ASU 2017-12. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.

ASU 2018-17 Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities

In October 2018, the FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities. The update is intended to improve general purpose financial reporting by considering indirect interests held through related parties in common control arrangements on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted.

Effective January 1, 2019, we will adopt ASU 2018-17 on a prospective basis and apply the amendments in the update to qualifying new or redesignated hedging relationships entered into on or after January 1, 2019. We do not expect this to have a material impact on our Consolidated Financial Statements and related disclosures.

Other accounting standard updates issued by the FASB

As of March 28, 2019 , the FASB have issued several further updates not included above. We do not currently expect any of these updates to affect our Consolidated Financial Statements and related disclosures either on transition or in future periods.

Note 4 - Chapter 11 Proceedings

In this note we have provided an overview of our Chapter 11 Reorganization and related transactions.

Overview

Prior to the filing of Chapter 11 Proceedings (as defined below), we were engaged in extensive discussions with our secured lenders, certain holders of our unsecured bonds and potential new money investors regarding the terms of a comprehensive restructuring. The objectives of the restructuring were to build a bridge to a recovery and achieve a sustainable capital structure. To achieve this, we had proposed an extension to our bank maturities, reduced debt amortization payments, amendments to financial covenants and raising of new capital.

On September 12, 2017, Old Seadrill Limited, certain of its subsidiaries (together "the Company Parties ") and certain Ship Finance companies entered into a restructuring support and lock-up agreement (" RSA ") with a group of bank lenders, bondholders, certain other stakeholders, and new-money providers. In connection with the RSA, the Company Parties entered into an " Investment Agreement " under which Hemen Investments Limited, an affiliate of Old Seadrill Limited's largest shareholder Hemen Holding Ltd. and certain other commitment parties, committed to provide $1.06 billion in new cash commitments, subject to certain terms and conditions (the " Capital Commitment ").

On September 12, 2017, to implement the transactions contemplated by the RSA and Investment Agreement, Old Seadrill Limited and certain of its subsidiaries (the " Debtors ") commenced prearranged reorganization proceedings (the " Chapter 11 Proceedings ") under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas Victoria Division. During the bankruptcy proceedings, the Debtors continued to operate the business as debtors in possession.

After September 12, 2017, the Debtors negotiated with their various creditors and on February 26, 2018 announced a " Global Settlement" , following which there were amendments to the RSA and Investment Agreement. These amendments provided for, amongst other things, the inclusion of certain other creditors as Commitment Parties, an increase of the Capital Commitment to $1.08 billion , increased recoveries for general unsecured creditors under the Plan and an agreement regarding allowed claims from certain newbuild shipyards.

On February 26, 2018, the Debtors filed a proposed Second Amended Joint Chapter 11 Plan of Reorganization (the " Plan ") with the Bankruptcy Court. The Plan was confirmed by the Bankruptcy Court on April 17, 2018. The Plan became effective and the Debtors emerged from Chapter 11 Proceedings on July 2, 2018 (the " Effective Date ").

The Plan extinguished approximately $2.4 billion in unsecured bond obligations, more than $1.0 billion in contingent newbuild obligations, substantial unliquidated guarantee obligations, and approximately $250 million in unsecured interest rate and currency swap claims, while extending near term debt maturities, providing Seadrill with over $1.0 billion in new capital and leaving employee, customer and ordinary trade claims largely unimpaired.





F-21
Table of Contents

Key terms of the Plan of Reorganization

As set out above, the Plan was confirmed by the Bankruptcy Court on April 17, 2018 and became effective when the Debtors emerged from Chapter 11 Proceedings on July 2, 2018. The Plan provided for, among other things, that:

◦
There was a corporate reorganization whereby Seadrill Limited became the ultimate parent holding company of Old Seadrill Limited's subsidiaries.
◦
The Commitment Parties and subscribers to an equity rights offering subscribed for a total 23,750,000 shares in Seadrill Limited for aggregate consideration of $200 million .
◦
The Commitment Parties and subscribers to a notes rights offering subscribers purchased a total $880 million principal amount of New Secured Notes and were issued 54,625,000 shares in Seadrill Limited for an aggregate consideration of $880 million .
◦
The holders of general unsecured claim were issued 14,250,000 shares in Seadrill Limited.
◦
The former holders of Old Seadrill Limited Equity and certain other claimants were issued 1,900,000 shares in Seadrill Limited.
◦
Certain Commitment Parties received a fee of 475,000 shares in Seadrill Limited and Hemen received a fee of 5,000,000 shares in Seadrill Limited.
◦
An employee incentive plan was implemented (the “Employee Incentive Plan”) which reserved an aggregate of 10% of the Seadrill Limited Shares, for grants to be made from time to time to Seadrill employees and other parties.

This is summarized in the below table:
 
 
 
 
Percentage
Recipient of Common Shares
 
Number of shares

 
Prior to dilution by Primary Structuring Fee and the shares reserved under the Employee Incentive Plan

 
Prior to dilution by the shares reserved under the Employee Incentive Plan

 
Fully diluted

Commitment Parties (in exchange for cash paid pursuant to the Investment Agreement) and Equity Rights Offering Subscribers
 
23,750,000

 
25.00
%
 
23.75
%
 
21.38
%
Recipients of New Secured Notes (including Commitment Parties and Notes Rights Offering Subscribers)
 
54,625,000

 
57.50
%
 
54.63
%
 
49.16
%
Holders of General Unsecured Claims
 
14,250,000

 
15.00
%
 
14.25
%
 
12.82
%
Former Holders of Old Seadrill Limited Equity and Seadrill Limited 510(b) Claimants
 
1,900,000

 
2.00
%
 
1.90
%
 
1.71
%
Fees to Select Commitment Parties
 
475,000

 
0.50
%
 
0.47
%
 
0.43
%
All creditors, excluding Primary Structuring Fee
 
95,000,000

 
100.00
%
 
95.00
%
 
85.50
%
Hemen (on account of Primary Structuring Fee)
 
5,000,000

 
-

 
5.00
%
 
4.50
%
Total, prior to dilution by shares reserved under the Employee Incentive Plan
 
100,000,000

 
-

 
100.00
%
 
90.00
%
Reserved for the Employee Incentive Plan
 
11,111,111

 
-

 
-

 
10.00
%
Total, fully diluted
 
111,111,111

 
-

 
-

 
100.00
%

Reorganization items

Expenses and income directly associated with the Chapter 11 cases are reported separately in the Consolidated Statement of Operations as "Reorganization items" as required by ASC 852, Reorganizations . This category was used to reflect the net expenses and gains and losses that are the result of the reorganization of the business.

The following table summarizes the components included within reorganization items:

F-22
Table of Contents

 
 
Successor
 
Predecessor
(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
December 31, 2017

 
December 31, 2016

Professional and advisory fees
 
(9
)
 
(187
)
 
(66
)
 
—

New investor commitment fees
 
—

 
—

 
(53
)
 
—

Loss on Newbuilding global settlement claim
 
—

 
—

 
(1,064
)
 
—

Loss on other pre-petition allowed claims
 
—

 
—

 
(3
)
 
 
Gain on liabilities subject to compromise
 
—

 
2,958

 
—

 
—

Fresh start valuation adjustments
 
—

 
(6,142
)
 
—

 
—

Write-off of debt issuance costs
 
—

 
—

 
(66
)
 
—

Reversal of credit risk on derivatives
 
—

 
—

 
(89
)
 
—

Interest income on surplus cash invested
 
—

 
6

 
4

 
—

Total reorganization items, net
 
(9
)
 
(3,365
)
 
(1,337
)
 
—


Advisory and professional fees - Professional and advisory fees incurred for post-petition Chapter 11 expenses. Professional and advisory expenses have been incurred post-emergence but relate to our Chapter 11 filing.

New investor commitment fees - Commitment fee of 5% of the committed funds agreed under the terms of the investment agreement.

Loss on Newbuilding global settlement claim - Under the Bankruptcy Code, the Debtors had the right to reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. As part of the Global Settlement Agreement, it was agreed that the Debtors would reject and terminate the newbuild contracts for the drillships West Dorado , West Libra , West Aquila and West Libra . In return the newbuild shipyards Samsung and DSME received an allowed claim for $1,064 million . In addition to the re-organization expense shown above, we also recorded a non-cash impairment charge against these Newbuild assets of $696 million at December 31, 2017 . Refer to Note 19 - Newbuildings for further details.

Gain on liabilities subject to compromise - On emergence from Chapter 11 we settled our liabilities subject to compromise in accordance with the Plan. This includes settlement on our unsecured bonds, Newbuild global settlement claim (see above) and interest rate and cross-currency interest rate swaps. Refer to Note 5 – Fresh Start Accounting for further information.

Fresh start valuation adjustments - On emergence from Chapter 11, our assets and liabilities were recorded at fair value in accordance with ASC 852 related to fresh start reporting. The effects of the application of fresh start accounting were applied as of July 2, 2018 and the new basis of our assets and liabilities are reflected in the Consolidated Balance Sheet as of December 31, 2018 and the related adjustments thereto were recorded in the Consolidated Statement of Operations in the Predecessor. Refer to Note 5 – Fresh Start Accounting for further information.

Write-off of debt issuance costs - On filing for Chapter 11, $66 million of unamortized debt issuance costs on the impaired secured credit facilities and unsecured bonds were expensed.

Reversal of credit risk on derivatives - The filing for Chapter 11 triggered an event of default under our derivative agreements, and therefore our interest rate and cross-currency interest rate swaps were held at a terminated value. As such, any credit risk adjustment on these arrangements was taken to the Consolidated Statement of Operations.

Interest income on surplus cash invested - Interest income recognized on cash held within entities that had filed for Chapter 11.

Note 5 – Fresh Start Accounting

Fresh Start Accounting

Upon emergence from bankruptcy, we applied fresh start accounting to our financial statements in accordance with the provision set forth in ASC852 as (i) the holders of existing voting shares of the Company prior to emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the plan of reorganization was less than the post-petition liabilities and allowed claims.


F-23
Table of Contents

We elected to apply fresh start accounting effective July 2, 2018 (the "Convenience Date"), to coincide with the timing of the normal third quarter reporting period, which resulted in Seadrill becoming a new entity for financial reporting purposes. We evaluated and concluded that events between July 1, 2018 and July 2, 2018 were immaterial and that the use of an accounting Convenience Date of July 1, 2018 was appropriate. The effects of the Plan and the application of fresh start accounting were applied as of July 2, 2018 and the new basis of our assets and liabilities are reflected in our Consolidated Balance Sheet as of December 31, 2018 and the related adjustments thereto were recorded in the Consolidated Statement of Operations of the Predecessor as "Reorganization items" during the period from January 1, 2018 through July 1, 2018. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the Consolidated Financial Statements for the period after July 2, 2018 (the “Successor”) will not be comparable with the Consolidated Financial Statements prior to that date.

Reorganization Value

Reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate to the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh start accounting, we are required to allocate the reorganization value to individual assets based on their estimated fair values.

The Plan presented on February 26, 2018 , and confirmed by the Bankruptcy Court on April 17, 2018 , estimated a range of distributable value for the Successor Company of between $10.2 billion and $11.8 billion . We derived the reorganization value based on the mid-point of this range of estimated distributable values. This was approximately $11.0 billion . Fair values are inherently subject to significant uncertainties and contingencies beyond our control. Accordingly, there can be no assurance that the estimates, assumptions, valuations, and financial projections will be realized, and actual results could vary materially.

Valuation of Drilling Units

Our principal assets comprise our fleet of drilling units. With the assistance of valuation experts, we determined a fair value of these drilling units based primarily on an income approach utilizing a discounted cash flow analysis. We established an estimate of future cash flows for the period ranging from emergence to the end of life for each rig and discounted the estimated future cash flows to present value. The expected cash flows used in the discounted cash flows were derived from earnings forecasts and assumptions regarding growth and margin projections.

A discount rate of 11.4% was estimated based on an after-tax weighted average cost of capital ("WACC") reflecting the rate of return that would be expected by a market participant. The WACC also takes into consideration a company specific risk premium reflecting the risk associated with the overall uncertainty of the financial projects used to estimate future cash flows. We used a replacement cost approach to value capital spares and other property plant, and equipment.

Valuation of Equity Method Investments

The fair value of equity method investments was derived using an income approach, which discounts future free cash flows. The estimated future free cash flows associated with the investments were primarily based on expectations around applicable day rates, drilling unit utilization, operating costs, capital and long-term maintenance expenditures, applicable tax rates and industry conditions. The cash flows were estimated over the remaining useful economic lives of the underlying assets but no longer than 30 years in total, and discounted using an estimated market participant WACC as follows:
Investment
WACC

Seadrill Capricorn Holdings LLC
11.4
%
Seadrill Operating LP
12.0
%
Seadrill Deepwater Drillship Ltd
12.0
%
Seabras Sapura Holding
14.3
%
Seabras Sapura Participacoes
13.7
%
SeaMex
12.7
%

The discounted cash flow model derived an enterprise value of the investments, after which associated net debt was subtracted to provide equity values. The implied valuation of the direct ownership interests in Seadrill Partners derived from the discounted cash flow model was crosschecked against the market price of Seadrill Partners’ common units. Due to the significant influence we have on Seadrill Partners, there is an implied significant influence premium, which represents the additional value we would place over and above the market price of Seadrill Partners in order to maintain this significant influence. This is similar in thought to an implied control premium. We have evaluated the difference by reviewing the implied control premium as compared to other market transactions within the industry. We deem the implied control premium to be reasonable in the context of the data considered.

Valuation of debt

We recorded third party and related party debt obligations at a fair value of  $7.3 billion  which we determined using an income approach. We are amortizing the difference between the  $7.6 billion  face amount and the fair value recorded in fresh start accounting over the life of the debt. We estimated the fair value of the debt using Level 2 inputs.


F-24
Table of Contents

Reconciliation of distributable value to fair value of Successor common stock

The following table reconciles the distributable value to the estimated fair value of Successor common stock as at the Effective Date:
(In $ millions)
As at July 2, 2018

Distributable value
11,056

Less: non-controlling interest
(154
)
Less: fair value of debt
(7,301
)
Less: fair value of other non-operating liabilities
(108
)
Add: fair value of tax attributes
8

Fair value of Successor common stock issued upon emergence
3,501

 


Shares issued and outstanding on July 2, 2018
100.0

Per share value
35.01


Reorganization value and distributable value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumption will be realized.

The following table reconciles the distributable value to the estimated reorganization value as at the Effective Date: 
(In $ millions)
As at July 2, 2018

Distributable value
11,056

Add: other working capital liabilities
478

Add: other non-current operating liabilities
57

Add: fair value of tax attributes
8

Add: redeemable non-controlling interest
30

Total reorganization value
11,629


Consolidated Balance Sheet

The adjustments included in the following Consolidated Balance Sheet reflect the effects of the consummation of the transactions contemplated by the Reorganization Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions or inputs.
 
As of July 1, 2018
(In $ millions)
Predecessor Company

 
Reorganization Adjustments

 
Fresh Start Adjustments

 
Successor Company

ASSETS
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
Cash and cash equivalents
809

 
790

(a)
—

 
1,599

Restricted cash
409

 
169

(a)
—

 
578

Marketable securities
121

 
—

 
—

 
121

Accounts receivable, net
272

 
—

 
—

 
272

Amount due from related parties - current
181

 
—

 
14

(l)
195

Other current assets
247

 
—

 
181

(m)
428

Total current assets
2,039

 
959

 
195

 
3,193

Investment in associated companies
1,615

 
—

 
(687
)
(n)
928

Newbuildings
249

 
—

 
(249
)
(o)
—

Drilling units
12,531

 
—

 
(5,734
)
(p)
6,797

Deferred tax assets
8

 
—

 
—

 
8

Equipment
35

 
—

 
(6
)
(q)
29

Amount due from related parties - non-current
565

 
—

 
11

(r)
576


F-25
Table of Contents

 
As of July 1, 2018
(In $ millions)
Predecessor Company

 
Reorganization Adjustments

 
Fresh Start Adjustments

 
Successor Company

Assets held for sale - non-current
—

 
—

 
—

 
—

Other non-current assets
3

 
—

 
95

(s)
98

Total assets
17,045

 
959

 
(6,375
)
 
11,629

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
Debt due within one year
90


—


(33
)
(t)
57

Trade accounts payable
96


17

(b)
—


113

Amounts due to related parties - current
4


4

(c)
—


8

Other current liabilities
229


100

(d)
32

(u)
361

Total current liabilities
419


121


(1
)

539

Liabilities subject to compromise
9,050


(9,050
)
(e)
—


—

Long-term debt
856


6,292

(f)
(104
)
(t)
7,044

Long-term debt due to related parties
294


—


(94
)
(v)
200

Deferred tax liabilities
105


—


(6
)
(w)
99

Other non-current liabilities
57


3

(b)
2

(x)
62

Total non-current liabilities
1,312


6,295


(202
)

7,405

 
 
 
 
 
 
 
 
Redeemable non-controlling interest
25


—


5

(y)
30

 
 
 
 
 
 
 
 
Equity
 
 
 
 
 
 
 
Predecessor common shares
1,008


(1,008
)
(g)
—


—

Predecessor additional paid-in capital
3,316


(3,322
)
(g)
—


—

 


6

(h)



Predecessor contributed surplus
1,956


(1,956
)
(g)
—


—

Predecessor accumulated other comprehensive income
41


—


(41
)
(z)
—

Predecessor (loss)/retained earnings
(146
)

7,110

(i)
(6,964
)
(z)
—

Successor common shares
—


10

(j)
—


10

Successor contributed surplus
—


2,860

(j)
631

(aa)
3,491

Total Shareholders' equity
6,175


3,700


(6,374
)

3,501

Non-controlling interest
64


(107
)
(k)
197

(bb)
154

Total equity
6,239


3,593


(6,177
)

3,655

Total liabilities and equity
17,045


959


(6,375
)

11,629


Reorganization Adjustments:

(a)
Adjustments to cash and cash equivalents including the following:
Cash and Cash Equivalents
 
(In $ millions)
 
Proceeds from debt commitment  (1)
875

Proceeds from equity commitment
200

Payment to newbuild counterparty members
(18
)
Amendment consent fees to senior secured creditors
(26
)
Funding of the escrow account for NSN collateral
(227
)
Payment of closing fees for the debt commitment
(9
)
Payment new commitment parties fee
(1
)
Payment to the bank coordinating committee
(4
)
Change in cash and cash equivalents
790


F-26
Table of Contents

(1) Pursuant to the Investment Agreement, on the Effective Date we received cash of $875 million for the issuance of New Secured Notes, consisting of $880 million par value notes net of $5 million pre-issuance accrued interest.
Restricted Cash
 
(In $ millions)
 
Funding of the escrow account per terms of NSN
227

Payment of post confirmation accrued professional fees in connection with emergence
(31
)
Payment of success fees incurred upon emergence
(22
)
Distribution from the cash pool to general unsecured claims
(2
)
Payment of unsecured creditor committee advisor fees
(3
)
Change in restricted cash
169

(b)
Reflects the reinstatement of trade accounts payable and other non-current liabilities included as part of liabilities subject to compromise
(c)
Reflects the reinstatement of amounts due to related party included as part of liabilities subject to compromise.
(d)
Reflects the adjustment to other current liabilities upon emergence:
Other current liabilities upon emergence
 
(In $ millions)
 
Success fees accrued upon emergence
28

Undistributed cash pool balance for general unsecured claims on emergence
35

Cash payment made for post confirmation accrued professional fees in connection with emergence
(31
)
Reinstatement of other current liabilities as part of liabilities subject to compromise
64

Amendment fees on SFL loans accrued upon emergence
4

Change in other liabilities
100

(e)    Liabilities subject to compromise were settled as follows in accordance with the Plan:
Gain on liabilities subject to compromise
 
(In $ millions)
 
Senior undersecured or impaired external debt
5,266

Unsecured bonds
2,334

Newbuild claims
1,064

Accrued interest payable
49

Derivatives previously recorded at fair value
249

Accounts payable and other liabilities
84

Amount due to related party
4

Liabilities subject to compromise
9,050

Less: Distribution from cash pool to holders of general unsecured claims on emergence
(2
)
Less: Undistributed cash pool balance for holders of general unsecured claims on emergence
(35
)
Less: Payment to newbuild counterparty members
(17
)
Less: Fair value of equity issued to holders of general unsecured claims
(498
)
Less: Reinstatement of amount due to related party
(4
)
Less: Reinstatement of trade accounts payable
(84
)
Less: Reinstatement of senior undersecured or impaired external debt
(5,266
)
Less: Recognition of adequate protection payments on senior undersecured or impaired external debt
(186
)
Gain on settlement of liabilities subject to compromise
2,958

(f)
Increase in long-term debt includes reinstatement of certain liabilities subject to compromise as well as the issuance of New Secured Notes. The net increase reflects the following:

F-27
Table of Contents

(In $ millions)
 
Reinstated Senior undersecured or impaired external debt
5,266

Recognition of adequate protection payments
186

Lender consent fee
(26
)
Total reinstated senior secured credit facilities
5,426

Issuance of New Secured Notes
880

Capitalized pre-issuance interest for New Secured Notes for 8% paid-in kind
10

Debt issuance cost in related to the issuance of the New Secured Notes
(9
)
Discount on New Secured Notes for the pre-issuance interest paid upon emergence (4% cash interest of $5 million and 8% paid-in kind interest of $10 million)
(15
)
Net increase in long-term debt
6,292

(g)
Reflects the cancellation of Predecessor Company common stock, contributed surplus, and additional paid in capital to retained earnings
(h)
Represents the unamortized stock compensation recognized upon cancellation of the Predecessor Company common stock, contributed surplus, and additional paid in capital.
(i)
Reflects the change in predecessor retained (loss)/earnings
(In $ millions)
 
Gain on settlement of liabilities subject to compromise
2,958

Cancellation of predecessor common stock, contributed surplus, and additional paid in capital
6,286

Recognition of unamortized stock compensation expense upon cancellation of the Predecessor Company common stock, contributed surplus, and additional paid in capital
(6
)
Fair value of Successor Common Shares issued upon emergence
(2,176
)
Success fees incurred upon emergence
(51
)
New Commitment Parties, bank coordinating committee, and unsecured creditor committee advisor fees
(8
)
Elimination of NADL and Sevan non-controlling interest
107

Total change in predecessor retained (loss)/earnings
7,110

(j)
Reflects the issuance of 24 million shares of common stock at a per share price of $8.42 in connection with the equity commitment, 55 million shares of common stock with estimated fair value of $35.01 per share issued in connection with the debt commitment, 14 million shares of common stock issued to the holders of general unsecured claims at an estimated fair value of $35.01 per share, 2 million shares of common stock issued to former holders of Predecessor equity at an estimated fair value of $35.01 per share, and 5 million shares of common stock issued for structuring fees to the select commitment parties and Hemen at an estimated fair value of $35.01 per share.
(k)
As determined in the Plan, NADL and Sevan became wholly owned subsidiaries and the non-controlling interests of NADL and Sevan were eliminated.

Fresh Start Adjustments
(l)
Adjustment to record the current portion of the contingent consideration receivable from Seadrill Partners related to the West Vela with the fair value of $14 million .
(m)
Adjustment to write-off $9 million of current deferred mobilization costs to fair value, which is offset by recording the fair value of certain favorable drilling contracts of $190 million . The value was based on the contracted rates compared to the prevailing market rates.
(n)
Adjustment to decrease the carrying value of the investments in associated companies to their estimated fair values determined using a discounted cash flow analysis utilizing the assumption noted above the Valuation of Equity Method Investments.
(o)
Adjustment to record the newbuildings at fair value based on the value derived from an income approach compared to the current contractual obligations remaining to be paid.
(p) Adjustment to the drilling units to record the fair value of the rigs and capital spares utilizing a combination of income-based and market-based approaches. The discount rate of 11.4% was used for the discounted cash flow analysis under the income-based approach. A cost-based approach was utilized to determine the fair value for the capital spares.
(q)
Adjustment to record equipment at fair value based on a cost approach.
(r)
Adjustment to record the non-current portion of the contingent consideration receivable from Seadrill Partners related to the West Vela and West Polaris with the fair value of $17 million . This amount is offset with a $3 million reduction on the recoverability of the receivable due from Seabras Participacoes and $2 million adjustment to record the embedded conversion option component of the Archer convertible debt instrument at the emergence date fair value.
(s)
Adjustment to write-off $2 million of deferred mobilization cost and $1 million of unamortized favorable contracts to fair value. These are offset by recording the fair value of certain favorable drilling and management service contracts of $98 million . The value was based on the contracted rates compared to the prevailing market rates.
(t)
Fair value adjustment to record discount of $188 million on the senior secured credit facilities and Ship Finance loans. This reduction is offset by a $51 million write-off of discounts on the New Secured Notes, unamortized debt issuance cost and lender consent fees.

F-28
Table of Contents

(In $ millions)
 
 
 
 
As at July 2, 2018
 New Secured Notes

 Senior Secured Credit Facilities

 Ship Finance Loans

 Total

Carrying value after reorganization adjustments
866

5,636

736

7,238

Adjustments to record debt at fair value:



—

Write-off of unamortized debt issuance costs
9

26

1

36

Write-off of discounts for pre-issuance accrued interest settled upon issuance of NSNs (4% cash interest of $5 million and 8% paid-in kind interest of $10 million)
15

—

—

15

Fair value adjustment to record discount on the senior secured credit facilities and Ship Finance Loans
—

(155
)
(33
)
(188
)
Estimated fair value of debt at emergence
890

5,507

704

7,101


(u)
Adjustment to write-off $27 million , primarily related to deferred mobilization revenue, for which we have determined to have no future performance obligations. These are offset by recording the fair value of certain unfavorable drilling contracts of $59 million . The value was based on the contracted rates compared to the prevailing market rates.
(v)
Adjustment to reflect a fair value discount on the loans due to related parties. The value was based on an income approach using level 2 inputs.
(w)
Adjustments to the deferred tax liabilities as a result of applying fresh start accounting.
(x)
Adjustment to write-off $7 million of deferred mobilization revenue, for which we have determined to have no future performance obligations, offset by the fair value of certain unfavorable drilling contracts of $9 million . The value was based on the contracted rates compared to prevailing market rates.
(y)
Adjustment to record redeemable non-controlling interest to the emergence date fair value.
(z)
Reflects the fresh start accounting adjustment to reset retained (loss) earnings and accumulated other comprehensive income.
(aa)
Reflects the increase in fair value of the 24 million shares of common stock issued in connection with the equity commitment from $8.42 to $35.01 per share.
(bb)
Adjustment to record the non-controlling interest in the Ship Finance VIEs and Seadrill Nigeria Operations Limited to fair value.

Note 6 – Segment information
 
Operating segments
 
We provide drilling and related services to the offshore oil and gas industry. We have been organized into three operating segments:

1.
Floaters : Services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to semi-submersible rigs and drillships for harsh and benign environments in mid-, deep- and ultra-deep waters;

2.
Jack-up rigs : Services encompassing drilling, completion and maintenance of offshore exploration and production wells. The drilling contracts relate to jack-up rigs for operations in harsh and benign environments; and

3.
Other : Operations including management services to third parties and related parties. Income and expenses from these management services are classified under this segment.

Segment results are evaluated on the basis of operating income and the information given below is based on information used for internal management reporting.
 
Revenues

Operating revenues by operating segment are as follows:
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Floaters
322

 
482

 
1,387

 
2,212

Jack-up rigs
167

 
193

 
617

 
865

Other
52

 
37

 
84

 
92

Total
541

 
712

 
2,088

 
3,169



F-29
Table of Contents

Depreciation and amortization

Depreciation and amortization by operating segment are as follows:
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Floaters
190

 
298

 
601

 
600

Jack-up rigs
46

 
93

 
197

 
210

Total
236

 
391

 
798

 
810


Operating (loss)/income - net (loss)/income

Operating (loss)/income and (loss)/income by operating segment is as follows:
 
Successor

Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018


Year ended December 31,
2017


Year ended December 31,
2016

Floaters
(161
)
 
(446
)
 
(622
)
 
759

Jack-up Rigs
(16
)
 
(167
)
 
(112
)
 
267

Other
2

 
—

 
6

 
—

Operating (loss)/income
(175
)
 
(613
)
 
(728
)
 
1,026

Unallocated items:
 

 
 
 
 

 
 

Total financial items and other
(422
)
 
(3,242
)
 
(2,308
)
 
(982
)
(Loss)/income before income taxes
(597
)
 
(3,855
)
 
(3,036
)
 
44


Total assets

Total assets by operating segment are as follows:
 
Successor

 
Predecessor

(In $ millions)
December 31, 2018

 
December 31, 2017

Floaters
5,508

 
9,956

Jack-up Rigs
1,151

 
3,508

Total Drilling Units and Newbuildings
6,659

 
13,464

Assets held for sale
—

 
126

Investments in Associated companies
800

 
1,473

Marketable securities
57

 
124

Cash and restricted cash
2,003

 
1,359

Other assets
1,329

 
1,436

Total
10,848

 
17,982


F-30
Table of Contents


  Capital expenditures – fixed assets 1  

Capital expenditure by operating segment are as follows:
 
Successor

Predecessor
 
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018


December 31, 2017


December 31, 2016

(In $ millions)
 
 
 
 
 
 
 
Floaters
74

 
93

 
128

 
192

Jack-up Rigs
24

 
24

 
22

 
35

Total
98

 
117

 
150

 
227

1 The successor period includes additions to equipment

Geographic segment data
 
Revenues are attributed to geographical segments based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents our revenues and fixed assets by geographic area:

Revenues

Revenues by geographic area are as follows:
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Norway
117

 
82

 
219

 
475

Nigeria
108

 
105

 
193

 
431

Brazil
91

 
188

 
358

 
491

Saudi Arabia
78

 
79

 
159

 
200

United States
34

 
30

 
291

 
370

Angola
29

 
100

 
482

 
419

Others (1)
84

 
128

 
386

 
783

Total Revenue
541

 
712

 
2,088

 
3,169


(1)
Other countries represent countries in which we operate that individually had revenues representing less than 10% of total revenues earned for any of the periods presented.


Fixed assets – drilling units (1)

Drilling unit fixed assets by geographic area are as follows:
 
Successor

 
Predecessor

(In $ millions)
December 31, 2018

 
December 31, 2017

Norway
1,326

 
2,258

Malaysia
1,070

 
1,809

Spain
875

 
2,016

Brazil
688

 
1,816

USA
658

 
1,266

Others  (2)
2,042

 
4,051

Total
6,659

 
13,216



F-31
Table of Contents

(1)
The fixed assets referred to in the table above exclude assets under construction. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.
(2)
Other countries represent countries in which we operate that individually had fixed assets representing less than 10% of total fixed assets for any of the periods presented.

Major customers
In the period from July 2, 2018 through December 31, 2018 (Successor), the period from January 1, 2018 through July 1, 2018 (Predecessor) and the years ended December 31, 2017 (Predecessor) and 2016 (Predecessor), we had the following customers with contract revenues greater than 10% in any of the years presented:

 
 
Successor

 
Predecessor
 
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Total
 
27
%
 
20
%
 
25
%
 
18
%
Saudi Aramco

17
%

12
%

8
%

7
%
ConocoPhillips

14
%

9
%

6
%

5
%
Petrobras

11
%

27
%

19
%

17
%
Equinor
 
12
%
 
6
%
 
4
%
 
10
%
LLOG

6
%

5
%

15
%

13
%
ExxonMobil
 
—
%
 
11
%
 
7
%
 
13
%


Note 7 - Revenue from Contracts with Customers
 
The following table provides information about receivables, contract assets and contract liabilities from our contracts with customers:
 
 
Successor
 
Predecessor
(In $ millions)
 
December 31, 2018

 
December 31, 2017

Accounts receivable, net
 
208

 
295

Current contract assets (1)
 
1

 
7

Non-current contract assets (1)
 
—

 
—

Current contract liabilities (deferred revenues) (1)
 
(12
)
 
(37
)
Non-current contract liabilities (deferred revenues) (1)
 
(9
)
 
(18
)
(1)   Current contract assets and liabilities balances are included in “ Other current assets ” and “ Other current liabilities ,” respectively in our Consolidated Balance Sheets as of December 31, 2018 (Successor).


F-32
Table of Contents

Significant changes in the contract assets and the contract liabilities balances during the period from January 1, 2018 through July 1, 2018 (Predecessor) and period from July 2, 2018 through December 31, 2018 (Successor) are as follows:
(In $ millions)
 
Net Contract
Balances

Contract assets at January 1, 2018 (Predecessor)
 
7

Contract liabilities at January 1, 2018 (Predecessor)
 
(55
)
Net contract liability at January 1, 2018 (Predecessor)
 
(48
)
Decrease due to amortization of revenue that was included in the beginning contract liability balance
 
25

Increase due to cash received, excluding amounts recognized as revenue
 
(9
)
Decrease due to recognized during the period but contingent on future performance
 
9

Fresh start adjustment
 
32

Net contract asset at July 1, 2018 (Predecessor)
 
9

Contract assets at July 1, 2018 (Predecessor)
 
9

Contract liabilities at July 1, 2018 (Predecessor)
 
—

 
 
 
 
 
 
Contract assets at July 2, 2018 (Successor)
 
9

Contract liabilities at July 2, 2018 (Successor)
 
—

Net contract asset at July 2, 2018 (Successor)
 
9

Decrease due to amortization of revenue that was included in the beginning contract liability balance
 
—

Increase due to cash received against contract assets recognized at July 2, 2018 (Successor)
 
(9
)
Increase due to cash received, excluding amounts recognized as revenue
 
(21
)
Decrease due to recognized during the period but contingent on future performance
 
1

Fresh start adjustment
 
—

Net contract liability at December 31, 2018 (Successor)
 
(20
)
Contract assets at December 31, 2018 (Successor)
 
1

Contract liabilities at December 31, 2018 (Successor)
 
(21
)

Certain direct and incremental costs that are expected to be recovered, relate directly to a contract, and enhance resources that will be used in satisfying our performance obligations in the future. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Deferred contract costs during the period from January 1, 2018 through July 1, 2018 (Predecessor) and period from July 2, 2018 through December 31, 2018 (Successor) are as follows:

(In $ millions)
 
Net deferred contract costs

Opening deferred contract costs at January 1, 2018 (Predecessor)
 
20

Additional deferred contract costs
 
6

Amortization of deferred contract costs
 
(15
)
Fresh start adjustment (1)
 
(11
)
Closing deferred contract costs at July 1, 2018 (Predecessor)
 
—

 
 
 
 
 
 
Additional deferred contract costs
 
22

Amortization of deferred contract costs
 
(7
)
Closing deferred contract costs at December 31, 2018 (Successor)
 
15

(1) Refer to Note 5 – Fresh Start Accounting for further information.

Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling and other property and equipment and depreciated over the estimated useful life of the improvement. Refer to Note 20 – Drilling units for more information.


F-33
Table of Contents

Deferred revenue - The deferred revenue balance of $12 million reported in " Other current liabilities " at December 31, 2018 (Successor) is expected to be realized within the next twelve months and $9 million reported in " Other non-current liabilities " is expected to be realized within the following next twelve months. The deferred revenue included above consists primarily of mobilization and upgrade revenue for both wholly and partially unsatisfied performance obligations as well as expected variable mobilization and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the entire corresponding performance obligations. The amounts are derived from the specific terms within drilling contracts that contain such provisions, and the expected timing for recognition of such revenue is based on the estimated start date and duration of each respective contract based on information known at December 31, 2018 . The actual timing of recognition of such amounts may vary due to factors outside of our control.

Practical expedient - We have applied the disclosure practical expedient in ASC 606-10-50-14A(b) and have not included estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue. The duration of our performance obligations varies by contract.
 
Impact of Topic 606 on Financial Statement Line Items - Adopting Topic 606 did not have a material effect on the Consolidated Statement of Operations, or Consolidated Statement of Cash Flows for the period from January 1, 2018 through July 1, 2018 (Predecessor) and period from July 2, 2018 through December 31, 2018 (Successor) or the Consolidated Balance Sheets as of December 31, 2018 (Successor). Refer to Note 2 – Accounting policies for more information on the recently adopted accounting pronouncements.

Note 8 – Other revenues
 
Other revenues consist of the following:
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018


Year ended December 31,
2017


Year ended December 31,
2016

Related party revenues
46

 
43

 
110

 
100

Amortization of unfavorable contracts
—

 
21

 
43

 
65

External management fees with third parties
—

 
—

 
1

 
19

Early termination fees
—

 
8

 
8

 
69

Total
46

 
72

 
162

 
253

 
Related party revenues - Related party revenue relate to management support and administrative services provided during the year to Seadrill Partners, SeaMex and Northern Drilling. Refer to Note 30 - Related party transactions for more information.

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 and the application of fresh start accounting, we classified the amortization of these intangible assets or liabilities within other revenues. For the periods after emergence from Chapter 11 and the application of fresh start accounting, we have applied a new accounting policy, which is to classify amortization of these intangible assets and liabilities within operating expenses. The unfavorable contract values in the Predecessor periods arose from our acquisition of Sevan Drilling Limited.

External management fees - External management fees relate to the operational, administrative and support services that we provide to Sapura Energy as part of the agreement that Seadrill entered into when we sold majority of the tender rig business. As the associated rigs were not operational from April 2017 no further management fees were recognized after this date.

Early termination fees - Other revenues for the period from January 1, 2018 through July 1, 2018 and the year ended December 31, 2017 and December 31, 2016 included early termination fee revenue. The termination fee revenue in the period from January 1, 2018 through July 1, 2018 relates to the fees recognized for the West Pegasus , the termination revenue in 2017 relates to the West Hercules and in 2016 to the West Hercules and West Epsilon . The total termination fee for the West Hercules was $66 million , with $58 million of revenue recognized in 2016 and remaining $8 million recognized in 2017 .


F-34
Table of Contents

Note 9 – Loss on disposals
 
We have recognized the following loss on disposals:
(In $ millions)
 
Net proceeds/recoverable amount

 
Book value on
disposal

 
Loss

Period from July 2, 2018 through December 31, 2018 (Successor):
 
 
 
 
 
Total for period ended December 31, 2018
—

 
—

—

—

 
 
 
 
 
 
Period from January 1, 2018 through July 1, 2018 (Predecessor):
 
 
 
 
 
Total for period ended July 1, 2018
—

 
—

 
—

 
 
 
 
 
 
Year ended December 31, 2017 (Predecessor):


 


 


Sale of West Triton
75

 
109

 
(34
)
Sale of West Mischief
75

 
146

 
(71
)
Sale of West Resolute
75

 
136

 
(61
)
Disposal of Sevan Developer  contract
—

 
75

 
(75
)
Sale of West Rigel
126

 
128

 
(2
)
Other
—


2



(2
)
Total for year ended December 31, 2017
351

 
596

 
(245
)
 
 
 
 
 
 
Year ended December 31, 2016 (Predecessor):


 


 


Total for year ended December 31, 2016
—

 
—

 
—


Loss on disposals in 2017 (Predecessor)

Sale of West Triton, West Mischief and West Resolute

On April 29, 2017 we reached an agreement with Shelf Drilling to sell the West Triton, West Mischief and West Resolute for a total consideration of $225 million . The West Triton and West Resolute were delivered in May 2017, whilst the West Mischief was delivered in September 2017. The sale resulted in a loss on disposal of $166 million .

Disposal of Sevan Developer contract
In October 2014, Sevan entered an agreement with Cosco to defer the delivery date of the Sevan Developer for twelve months with four subsequent options to extend the date for further periods of six months , until October 2017. On October 30, 2015, April 15, 2016 and October 15, 2016 three of the options were enacted, with $26.3 million , or 5% of the contract price, plus associated costs, refunded to Sevan on each occasion.
On April 27, 2017, the final delivery deferral agreement for the Sevan Developer was deferred to May 31, 2017 to finalize negotiations. As an agreement was not reached, the remaining installment of $26.3 million was refunded to Sevan, taking the delivery installment back to the $526.0 million contract price.

In July 2017, Sevan and Cosco agreed to defer the Sevan Developer delivery period until June 30, 2020. The contract amendment included a contract termination clause for Cosco and therefore it was deemed that Sevan had lost control of the asset and therefore derecognized the newbuild asset, which was held at $620 million , construction obligation held at $526 million , and accrued interest and other liabilities held at $19 million , resulting in a net loss on disposal of $75 million .

West Rigel settlement agreement

On April 5, 2018, we entered into a settlement and release agreement, subject to Bankruptcy Court approval, with Jurong in respect of the West Rigel whereby we agreed that the share of sale proceeds from the sale of the West Rigel by Jurong would be $126 million . We recognized a $2 million loss on disposal in the year ended December 31, 2017, reflecting the share of sales proceeds as the value of the asset held for sale.

On May 9, 2018 the West Rigel was sold by Jurong and we received a share of proceeds totaling $126 million .


F-35
Table of Contents

Note 10 – Interest expense

Interest expense consists of the following:
 
Successor
 
Predecessor
  (In $ millions)
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018


Year ended December 31, 2017


Year ended December 31, 2016

Cash and payment-in-kind interest on debt facilities
(237
)
 
(37
)
 
(286
)
 
(408
)
Unwind of discount debt
(24
)
 
—

 
—

 
—

Loan fee amortization
—

 
(1
)
 
(27
)
 
(43
)
Capitalized interest
—

 
—

 
28

 
39

Interest expense
(261
)
 
(38
)
 
(285
)
 
(412
)

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
  (In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

 
Year ended December 31, 2016

Senior credit facilities and unsecured bonds
(162
)
 
(116
)
 
(320
)
 
(360
)
Less: adequate protection payments
—

 
104

 
81

 
—

New secured notes
(50
)
 
—

 
—

 
—

Debt of consolidated variable interest entities
(25
)
 
(25
)
 
(47
)
 
(48
)
Cash and payment-in-kind interest
(237
)
 
(37
)
 
(286
)
 
(408
)
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, under the terms of the Plan. There has also been an increase in LIBOR rates over the second half of 2018. Both factors increased the effective interest rate on our senior credit facilities.
During the period we were in Chapter 11 (September 12, 2017 to July 1, 2018), 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 (classified under reorganization items - see section 5 below).
On emergence from Chapter 11 we issued $880 million of New Secured Notes. We incur 4% cash interest and 8% payment-in-kind interest on these notes.
Our Consolidated Balance Sheet includes approximately $1 billion of debt facilities held by subsidiaries of Ship Finance that we consolidate as variable interest entities. Our interest expense includes the interest incurred by these entities on those facilities .
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. We expensed capitalized loan issuance costs for debt subject to compromise when we filed for Chapter 11 on September 12, 2017. Loan fee amortization expense is therefore not comparable between these periods.
iv.
Capitalized interest
We capitalize the interest cost incurred to finance Newbuilds. We ceased capitalization of interest on Newbuilds when we filed for Chapter 11 on September 12, 2017.


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Note 11 – Impairment loss on marketable securities and investments in associated companies

We have recognized the following impairments on our marketable securities and investments in associated companies:
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018*

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Impairments of Marketable securities (refer to Note 15)
 
 
 
 
 
 
 
Seadrill Partners - Common Units
—

 
—

 
—

 
153

Total impairment of marketable securities investments (reclassification from OCI)
—

 
—

 
—

 
153

 
 
 
 
 
 
 
 
Impairments of Investment in associated companies and joint ventures (refer to Note 18)
 
 
 
 
 
 
 
Seadrill Partners - Total direct ownership investments
—

 
—

 
723

 
400

Seadrill Partners - Subordinated units
—

 
—

 
82

 
180

Seadrill Partners - Seadrill member interest and IDRs
—

 
—

 
—

 
73

SeaMex Limited
—

 
—

 
36

 
76

Itaunas Drilling, Camburi Drilling, and Sahy Drilling
—

 
—

 
—

 
13

Total impairment of investments in associated companies and joint ventures
—

 
—

 
841

 
742




 
 



Total impairment of investments
—

 
—

 
841

 
895

*On emergence from Chapter 11, the carrying value of our investments in associated companies and joint ventures were adjusted to fair value resulting in a loss recognized in the Consolidated Statement of Operations in "Reorganization items" for the period from January 1, 2018 through July 1, 2018 (Predecessor). For further information, refer to Note 5 - Fresh start accounting .

Impairment loss recognized for the year ended December 31, 2017 (Predecessor)

Seadrill Partners - Subordinated units and direct ownership interests - Impairment of Equity Method Investment
Whilst the investments in Seadrill Partners held under the equity method are not publicly traded, the value of the publicly traded units remained lower than the carrying value ascribed to the equity method investments using managements assumptions for a sustained period. We determined this to be representative of an indicator of other than temporary impairment and performed a test of impairment at December 31, 2017.

As at December 31, 2017, the carrying value of the subordinated units was found to exceed the fair value by $82 million , and the carrying value of the direct ownership interests was found to exceed the fair value by $723 million . We recognized this impairment of the investments within “Loss on impairment of investments” in the Consolidated Statement of Operations.

The fair value of these investments were derived using an income approach, which discounts future free cash flows (“DCF model”). The estimated future free cash flows associated with the investments are primarily based on expectations around applicable day rates, drilling unit utilization, operating costs, capital and long-term maintenance expenditures, applicable tax rates and industry conditions. The cash flows were estimated over the remaining useful economic lives of the underlying assets but no longer than 30 years in total and discounted using an estimated market participant weighted average cost of capital of 9.75% . The DCF model derived an enterprise value of the investments, after which associated debt was subtracted to provide equity values. The implied valuation of Seadrill Partners derived from the DCF model was crosschecked against the market price of Seadrill Partners’ common units. Due to the significant influence we have on Seadrill Partners, there is in implied significant influence premium, which represents the additional value we would place over and above the market price of Seadrill Partners in order to maintain this significant influence. This is similar in thought to an implied control premium. We have evaluated the difference by reviewing the implied control premium as compared to other market transactions within the industry. We deem the implied control premium to be reasonable in the context of the data considered.

The assumptions used in the DCF model were derived from significant unobservable inputs (representative of Level 3 inputs for Fair Value Measurement) and are based on management’s judgments and assumptions available at the time of performing the impairment test. We employ significant judgment in developing these estimates and assumptions including the following:
•
forecast dayrates for our drilling contracts;
•
utilization rates;
•
operating costs and overheads;

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•
estimated annual capital expenditure, cost of rig replacement and/or enhancement programs;
•
estimated maintenance, inspections or other costs associated with a rig after completion/termination of the contract;
•
remaining useful life of each rig; and
•
estimated tax rates.

The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios were developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs, are estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment. Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment.

SeaMex Limited - Impairment of investment in Joint Venture
The deteriorating market conditions in the oil and gas industry and supply and demand conditions in the offshore drilling sector in which SeaMex operates is considered to be an indicator of impairment. We determined the length and severity of the deterioration of market conditions to be representative of an other than temporary impairment. As such we measured and recognized an other than temporary impairment of the investment in SeaMex as at December 31, 2017.

The fair value was derived using an income approach, which discounts future free cash flows (“DCF model”). The estimated future free cash flows associated with the investment were primarily based on expectations around applicable day rates, drilling unit utilization, operating costs, capital and long-term maintenance expenditures and applicable tax rates. The cash flows were estimated over the remaining useful economic lives of the underlying assets but no longer than 30 years in total and discounted using an estimated market participant weighted average cost of capital of 10.25% . The DCF model derived an enterprise value of the investments, after which associated debt was subtracted to provide equity values.

The carrying value of the investment was found to exceed the fair value by $36 million . We have recognized this impairment of the investments within “Loss on impairment of investments” in the Consolidated Statement of Operations.

The assumptions used in the DCF model were derived from unobservable inputs (level 3) and are based on management’s judgments and assumptions available at the time of performing the impairment test. The use of different assumptions, particularly with regard to the most sensitive assumptions concerning estimated future dayrates and utilization and the assumed market participant discount rate, would have a material impact on the impairment charge recognized and our Consolidated Statement of Operations. In addition, if actual events differ from management’s estimates, or to the extent that these estimates are adjusted in the future, our financial condition and results of operations could be affected in the period of any such change of estimate.

Impairment loss recognized for the year ended December 31, 2016 (Predecessor)

Seadrill Partners - Common Units - Impairment of marketable securities
During the period between September 30, 2015 and September 30, 2016 , Seadrill Partners’ unit price fell by approximately 62% , on both a spot price and trailing three-month average basis. Management determined that the investment in Seadrill Partners’ common units was other than temporarily impaired due to the length and severity of the reduction in value below historic cost. As a result, we impaired the investment, recognizing an impairment charge of $153 million within "Loss on impairment of investments". This impairment charge includes a reclassification of losses previously recognized within Other Comprehensive Income.

Seadrill Partners - Subordinated units and direct ownership interests - Impairment of Equity Method Investment
As at September 30, 2016 , the carrying value of the subordinated units was found to exceed the fair value by $180 million , and the carrying value of the direct ownership interests was found to exceed the fair value by $400 million . We recognized this impairment of the investments within “Loss on impairment of Investments” in the Consolidated Statement of Operations. In the period from September 30, 2016 to December 31, 2016 no additional impairment was recognized due to the increase in the value of the traded units.

The assumptions used in the DCF model were derived from unobservable inputs (classified as level 3) and are based on management’s judgments and assumptions available at the time of performing the impairment test.

Seadrill Partners - Member interest - Impairment of Cost method investments
As at September 30, 2016, the reduction in value of the Seadrill Partners common units was determined to be an indicator of impairment of the Seadrill member interest. The fair value was determined using the Monte Carlo model, updated for applicable assumptions as at September 30, 2016. The carrying value of the investment was found to exceed the fair value by $73 million . We recognized this impairment within “Loss on impairment of Investments” in the Consolidated Statement of Operations.

The assumptions used in the Monte Carlo model were derived from both observable and unobservable inputs (classified as level 3) and are based on management’s judgments and assumptions available at the time of performing the impairment test.

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SeaMex Limited - Impairment of investment in Joint Venture
As at September 30, 2016 , the deteriorating market conditions in the oil and gas industry and supply and demand conditions in the offshore drilling sector in which SeaMex operates is considered to be an indicator of impairment. We have determined the length and severity of the deterioration of market conditions to be representative of an other than temporary impairment. As such we measured and recognized an other than temporary impairment of the investment.

The fair value was derived using an income approach, which discounts future free cash flows (“DCF model”). The estimated future free cash flows associated with the investment were primarily based on expectations around applicable day rates, drilling unit utilization, operating costs, capital and long-term maintenance expenditures and applicable tax rates. The cash flows were estimated over the remaining useful economic lives of the underlying assets but no longer than 30 years in total and discounted using an estimated market participant weighted average cost of capital of 11% . The DCF model derived an enterprise value of the investments, after which associated debt was subtracted to provide equity values.

The carrying value of the investment was found to exceed the fair value by $76 million . We recognized this impairment of the investments within “Loss on impairment of investments” in the Consolidated Statement of Operations.

Itaunas Drilling, Camburi Drilling, and Sahy Drilling - Impairment of investment in Joint Venture
Itaunas Drilling BV, Camburi Drilling BV and Sahy Drilling BV are joint ventures which each have a contract to construct one drillship. The joint ventures are owned 70% by Sete International (a subsidiary of Sete Brasil Participacoes SA) and 30% by us.

During the year ended December 31, 2016, due to the deteriorating market conditions in the offshore drilling industry, the uncertainty around the financial condition of Sete Brasil Participacoes SA, and the uncertainty around the recoverability of the investments, we recognized an other than temporary impairment of $13 million to write down the value of these investments to nil. We recognized this impairment within “Loss on impairment of investments” in the Consolidated Statement of Operations.

Note 12 – Taxation
 
Income taxes consist of the following:

 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Current tax expense:
 
 
 
 
 
 
 
Bermuda
—

 
—

 
—

 
—

Foreign
30

 
34

 
56

 
151

Deferred tax expense:
 

 
 
 
 

 
 

Bermuda
—

 
—

 
—

 
—

Foreign
(22
)
 
(4
)
 
10

 
48

Total tax expense
8

 
30

 
66

 
199

Effective tax rate
(1.3
)%
 
(0.8
)%
 
(2.2
)%
 
452.3
%
 
The effective tax rate for the period from July 2, 2018 through December 31, 2018 (Successor) and the period from January 1, 2018 through July 1, 2018 (Predecessor) was (1.3)% and (0.8)% respectively. For the years ended December 31, 2017 (Predecessor) and December 31, 2016 (Predecessor) the rate was (2.2)% and 452.3% .

The rate reflects no tax relief on the majority of the following items within the Statement of Operations, due to these items largely falling within the zero tax rate Bermudan companies:

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Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Loss on marketable securities
(64
)
 
(3
)
 
—

 
—

(Loss)/gain on derivative financial instruments
(31
)
 
(4
)
 
11

 
(74
)
Reorganization items, net
(9
)
 
(3,365
)
 
(1,337
)
 
—

Loss on impairment of investments
—

 
—

 
(841
)
 
(895
)
Loss on disposals
—

 
—

 
(245
)
 
—


There was additionally no tax relief on the $696 million impairment of newbuildings recognized within 'Impairment of long lived assets' on the Statement of Operations in the year ended December 31, 2017 (Predecessor).

We are incorporated in Bermuda, where a tax exemption has been granted until 2035. Other jurisdictions in which we and our subsidiaries operate are taxable based on rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction. Thus, we may pay tax within some jurisdictions even though it might have losses in others.

The income taxes for the period from July 2, 2018 through December 31, 2018 (Successor), the period from January 1, 2018 through July 1, 2018 (Predecessor) and the years ended December 31, 2017 (Predecessor) and 2016 (Predecessor) differed from the amount computed by applying the Bermudan statutory income tax rate of 0% as follows:
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Income taxes at statutory rate
—

 
—

 
—

 
—

Effect of change on uncertain tax positions relating to prior year 
49

 
12

 
(5
)
 
28

Effect of unremitted earnings of subsidiaries
(10
)
 
—

 
3

 
(4
)
Effect of taxable income in various countries
(31
)
 
18

 
68

 
175

Total tax expense
8

 
30

 
66

 
199


During the year ended December 31, 2015, we reviewed our assertion of indefinite reinvestment of unremitted earnings of subsidiaries and determined that we no longer consider such earnings to be indefinitely reinvested. As at December 31, 2018 (Successor) we have recognized a deferred tax liability balance of $27 million ( December 31, 2017 (Predecessor): $37 million ).

Deferred income taxes
 
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The net deferred tax assets/(liabilities) consist of the following:
 
Deferred tax assets:
 
Successor

 
Predecessor

(In $ millions)
December 31,
2018

 
December 31,
2017

Pensions and stock options
4

 
4

Provisions
28

 
49

Net operating losses carried forward
263

 
255

Other
—

 
—

Gross deferred tax assets
295

 
308

Valuation allowance
(254
)
 
(230
)
Deferred tax assets, net of valuation allowance
41

 
78



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Deferred tax liabilities:
 
Successor

 
Predecessor

(In $ millions)
December 31,
2018

 
December 31,
2017

Property, plant and equipment
49

 
138

Unremitted Earnings of Subsidiaries
27

 
37

Intangibles
34

 
—

Gross deferred tax liabilities
110

 
175

Net deferred tax (liability)/asset
(69
)
 
(97
)
 
As at December 31, 2018 (Successor), deferred tax assets related to net operating loss (“NOL”) carry forwards was $263 million ( December 31, 2017 (Predecessor): $255 million ), which can be used to offset future taxable income. NOL carry forwards which were generated in various jurisdictions, include $257 million ( December 31, 2017 (Predecessor): $248 million ) that will not expire and $6 million ( December 31, 2017 (Predecessor): $7 million ) that will expire between 2018 and 2037 if unutilized.

As at December 31, 2018 (Successor), deferred tax liability related to intangibles from the application of fresh start accounting was $34 million (December 31, 2017: nil ).

We establish a valuation allowance for deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change. Our valuation allowance consists of $242 million on NOL carry forwards as at December 31, 2018 (Successor) ( December 31, 2017 (Predecessor): $216 million ).
 
Uncertain tax positions

As at December 31, 2018 (Successor), we had uncertain tax positions of $132 million excluding interest and penalties of $26 million , of which $1 million was included in other current liabilities and $73 million was included in other non-current liabilities, and $58 million was presented as a reduction of deferred tax assets. The changes to our uncertain tax positions were as follows:

 
Successor

 
Predecessor
 (In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Balance at the beginning of the period
61

 
55

 
44

 
9

Increases as a result of positions taken in prior periods
69

 
7

 
23

 
35

Increases as a result of positions taken during the current period
18

 
1

 
—

 
2

Decreases as a result of positions taken in prior periods
(9
)
 
(2
)
 
(9
)
 
(2
)
Decreases as a result of positions taken in the current period
—

 
—

 
—

 
—

Decreases due to settlements
(7
)
 
—

 
(3
)
 
—

Balance at the end of the period
132

 
61

 
55

 
44

 
Accrued interest and penalties totalled $26 million and $12 million as of December 31, 2018 (Successor) and December 31, 2017 (Predecessor) respectively and were included in "Other liabilities" on our Consolidated Balance Sheet. We recognized expenses of $11 million and $3 million during the period from July 2, 2018 through December 31, 2018 (Successor) and the period from January 1, 2018 through July 1, 2018 (Predecessor), respectively ( $10 million expense recognized in the year ended December 31, 2017 (Predecessor) and $2 million in the year ended December 31, 2016 (Predecessor)), related to interest and penalties for unrecognized tax benefits on the income tax expense line in the accompanying Consolidated Statement of Operations.

As of December 31, 2018 (Successor) has recognized liabilities for uncertain tax positions including interest and penalties of $100 million . In the event that these issues are resolved for amounts less than provided, there would be a favorable impact on the effective tax rate.
The increase in our uncertain tax position was largely due to US taxes following a recently identified interpretation of the US tax code that appears to be an unintended consequence of the US tax reform. We understand that the US Department of Treasury is aware of this issue and that it could potentially be remediated with additional guidance in the future. However, in the meanwhile, the Company is considering its approach for future filings which may result in a mitigation of a portion of the liability that has been recorded.  At this stage, no cash payment is expected as a result of this uncertain tax position.



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Tax returns and open years

We are subject to taxation in various jurisdictions. Tax authorities in certain jurisdictions examine our tax returns and some have issued assessments. We are defending our tax positions in those jurisdictions.

The Brazilian tax authorities have issued a series of assessments with respect to our returns for certain years up to 2012 for an aggregate amount equivalent to $161 million including interest and penalties. The relevant group companies are robustly contesting these assessments including filing relevant appeals. An adverse outcome on these proposed assessments could result in a material adverse impact on our Consolidated Balance Sheets, Statements of Operations or Cash Flows. In order to continue the appeal against certain years, it will be necessary to post collateral with a financial institution in an amount totaling approximately $70 million , which is expected to be required in the second calendar quarter of 2019.

The Nigerian tax authorities have issued a series of claims and assessments both directly and lodged through the Chapter 11 process with respect to returns for subsidiaries for certain years up to 2016 for an aggregate amount equivalent to $171 million . The relevant group companies are robustly contesting these assessments including filing relevant appeals in Nigeria and it is also intended that one or more formal objections against these claims for distribution purposes will be filed in the US court. An adverse outcome on these proposed assessments could result in a material adverse impact on our Consolidated Balance Sheets, Statements of Operations or Cash Flows.

The following table summarizes the earliest tax years that remain subject to examination by other major taxable jurisdictions in which we operate. 
Jurisdiction
Earliest Open Year
Angola
2015
Nigeria
2014
United States
2015
Norway
2015
Brazil
2008


Note 13 – Loss per share
 
The computation of basic (loss)/earnings per share (“EPS”) is based on the weighted average number of shares outstanding during the period. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments.

The components of the numerator for the calculation of basic and diluted EPS are as follows:
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Net loss attributable to the parent
(602
)
 
(3,881
)
 
(2,973
)
 
(181
)
Less: Allocation to participating securities
—

 
—

 
—

 
—

Net loss available to stockholders
(602
)
 
(3,881
)
 
(2,973
)
 
(181
)
Effect of dilution
—

 
—

 
—

 
—

Diluted net loss available to stockholders
(602
)
 
(3,881
)
 
(2,973
)
 
(181
)

The components of the denominator for the calculation of basic and diluted EPS are as follows:
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Basic earnings per share:
 
 
 
 
 
 
 
Weighted average number of common shares outstanding
100

 
504

 
505

 
501

Diluted earnings per share:
 

 
 
 
 

 
 

Effect of dilution
—

 
—

 
—

 
—

Weighted average number of common shares outstanding adjusted for the effects of dilution
100

 
504

 
505

 
501


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The basic and diluted loss per share are as follows:
 
Successor
 
Predecessor
(In $)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

Basic loss per share
(6.02
)
 
(7.71
)
 
(5.89
)
 
(0.36
)
Diluted loss per share
(6.02
)
 
(7.71
)
 
(5.89
)
 
(0.36
)

Note 14 – Restricted cash
 
Restricted cash consists of the following:
 
Successor

 
Predecessor

(In $ millions)
December 31, 2018

 
December 31, 2017

Funding Escrow for NSN (1)
328

 
—

Cash pledged as collateral (2)
101

 
76

Other
32


28

Total restricted cash
461

 
104


(1) Restricted cash at December 31, 2018 included cash held as collateral against the New Secured Notes. This included (i) $228 million of the initial proceeds from issuing the notes, (ii) $55 million deferred consideration payment from Sapura Energy and (iii) $43 million shareholder loan repayment from Seabras Sapura.

(2) Cash held as collateral against guarantees and other linked facilities we have with Danske Bank.

Note 15 – Marketable securities
 
Effective January 1, 2018, we adopted ASU 2016-01, which applies to equity investments that are neither (i) accounted for under the equity method or (ii) result in consolidation. Under ASU 2016-01 we record such investments at fair value and recognize any changes directly in net income, unless there is no readily ascertainable fair value, in which case we record the investment at cost less impairment. We hold investments in certain marketable securities which we account for at fair value through profit and loss per this guidance. We use quoted market prices to determine the fair value of our marketable securities and categorize them as level 1 on the fair value hierarchy.

For fiscal periods beginning prior to January 1, 2018, marketable securities not accounted for under the equity method were classified as available-for-sale. Unrealized gains and losses on equity securities classified as available-for-sale were recognized in other comprehensive income. When we adopted ASU 2016-01 for the first time at January 1, 2018, we reclassified $31 million of previously recognized fair value gains from accumulated other comprehensive income to retained earnings on January 1, 2018.

The below table shows the carrying value of our investments in marketable securities for periods presented in this report.
 
 
Successor

 
Predecessor

(In $ millions)
 
December 31, 2018

 
December 31, 2017

Seadrill Partners - Common units
 
45

 
96

Archer
 
12

 
28

Total marketable securities
 
57

 
124


The below table shows the gain and losses recognized through net income for the periods presented in this report since the adoption of ASU 2016-01.

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Successor

 
Predecessor

(In $ millions)
 
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

Seadrill Partners - Common Units - unrealized loss on marketable securities
 
(45
)
 
(5
)
Archer - unrealized (loss)/gain on marketable securities
 
(19
)
 
2

Total unrealized loss on marketable securities
 
(64
)
 
(3
)

The below table shows the gain and losses recognized through other comprehensive income for the periods presented in this report before the adoption of ASU 2016-01.
 
 
Predecessor

 
Predecessor
(In $ millions)
 
Year ended December 31, 2017

 
Year ended December 31, 2016

Seadrill Partners - Common Units - unrealized (loss) / gain on marketable securities
 
(14
)

17

Archer - unrealized gain on marketable securities
 
28


—

Total unrealized gain on marketable securities
 
14

 
17


Until April 2017, we accounted for our investment in Archer under the equity method. However, as part of a financial restructuring, Archer completed two share issuances in March and April 2017, which diluted our ownership interest to 15.7% . Also, as part of this restructuring, we agreed with Archer to convert total outstanding subordinated loans, fees and interest provided to Archer, with a carrying value of $37 million , into a $45 million loan. The fair value of the new loan receivable at the date of conversion was $56 million resulting in a gain of $19 million on debt extinguishment, which is presented within “Gain on debt extinguishment” in our Predecessor Consolidated Statement of Operations.

As a result of these activities, we concluded that we no longer had significant influence over Archer's financial and operating decisions, primarily as a result of the reduction in our shareholding and the significant reduction in our interests in related debt and guarantees. We reclassified our equity method investment in Archer, which had a carrying value of nil , to an investment in marketable security, also with a carrying value of nil . We then revalued the investment in marketable security to fair value based on Archer's share price. We recognized the gain through other comprehensive income.

For periods before we adopted ASU 2016-01, we reviewed our marketable securities for other-than-temporary impairment at each reporting date. Please see Note 11 - Impairment loss on marketable securities and investments in associated companies for details.

Note 16 – Accounts receivable
 
Accounts receivables are held at their nominal amount less an allowance for doubtful accounts. Doubtful accounts are recognized when it is unlikely that required payments of specific amounts will occur as a result of the financial condition of the customer. As at December 31, 2018 (Successor) we had no allowances for doubtful accounts netted against our accounts receivable ( December 31, 2017 (Predecessor): nil ; December 31, 2016 (Predecessor): nil ).

We recognized no bad debt expense in the period from July 2, 2018 through December 31, 2018 (Successor) and $48 million in the period from January 1, 2018 through July 1, 2018 . We did not recognize any bad debt expense in 2017 , or 2016 , but have instead reduced contract revenue for any disputed amounts.


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Note 17 – Other assets
 
 
Successor

 
Predecessor

(In $ millions)
As at December 31,
2018


As at December 31,
2017

Favorable drilling and management service contracts to be amortized
186

 
—

Taxes receivable
50

 
24

Derivative asset - Interest rate cap (1)
39

 
—

Prepaid Expenses
32

 
87

Deferred mobilization cost
15

 
20

Reimbursable amounts due from customers
10

 
15

Deferred Consideration (2)
—

 
80

Income tax effects of intercompany sales or transfers of assets (3)
—

 
84

Other assets
26

 
28

Total other assets
358

 
338

(1) On May 11, 2018, Seadrill Limited bought an interest rate cap from Citigroup for $68 million . The interest rate mitigates our exposure to future increases in LIBOR rates. We have an exposure to LIBOR rates because we hold floating rate debt. For the period from January 1, 2018 through to July 1, 2018 and from July 2, 2018 through to December 31, 2018 there had been a net fair value adjustment on the interest rate cap of $ 6 million and $ 22 million respectively to bring the asset value to $39 million .
(2) On April 30, 2013 , we completed the disposal of the tender rig business to Sapura Energy. The total consideration consisted of a non-contingent deferred consideration of $145 million , bearing interest at LIBOR plus 5% , which was due in April 30, 2016 . During the year ended December 31, 2016, Sapura Energy repaid $10 million of the principal and paid $25 million of interest. On August 28, 2017, this was converted into a formalized loan agreement whereby $5 million is repaid each month. During the year ended December 31, 2018, the full amount was repaid.
(3) Income tax effects following the sale of assets on divestment of North Atlantic Drilling Limited. The asset was expensed on January 1, 2018 following adoption of ASU 2016-16 - for further information refer to Note 3 - Recent accounting standards.

Other assets are presented in our Consolidated Balance Sheet as follows:
 
Successor

 
Predecessor

(In $ millions)
As at December 31,
2018

 
As at December 31,
2017

Other current assets
322

 
257

Other non-current assets
36

 
81

Total other assets
358

 
338


Intangible assets - Favorable Drilling Contracts and Management Services Contracts

On emergence from Chapter 11, we recognized favorable drilling and management service contracts at fair value, which will be amortized over their remaining contract period. The amounts recognized represent the net present value of the existing contracts at the time of emergence compared to the current market rates at that time, discounted at the weighted average cost of capital.

The gross carrying amounts and accumulated amortization included in 'Other current assets' and 'Other non-current assets' for favorable contracts in the Consolidated Balance Sheet are as follows:

 
 
Successor
 
Predecessor
 
 
As at December 31, 2018
 
As at December 31, 2017
(In $ millions)
 
Gross Carrying Amount

Accumulated amortization

Net carrying amount

 
Gross Carrying Amount

Accumulated amortization

Net carrying amount

Favorable contracts
 
 
 
 
 
 
 
 
Balance at beginning of period
 
287

—

287

 
—

—

—

Amortization of favorable contracts
 
—

(101
)
(101
)
 
—

—

—

Balance at end of period
 
287

(101
)
186

 
—

—

—



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Table of Contents

The amortization is recognized in the Consolidated Statements of Operations under "Amortization of favorable and unfavorable contracts". The weighted average remaining amortization period for the favorable contracts is 4 years 3 months.

The table below shows the amounts relating to favorable contracts that is expected to be amortized over the following periods:
 
 
Period ended December 31,
(In $ millions)
 
2019

2020

2021

2022

2023 and after

Total

Amortization of favorable contracts
 
153

2

2

2

27

186


Note 18 – Investment in associated companies
 
We have the following investments in associated companies:
 
Successor

 
Predecessor
Ownership percentage
December 31, 2018

 
December 31, 2017

Seadrill Partners and Seadrill Partner subsidiaries ("SDLP investments") (a) (b)
(a)

 
(a)

Seabras Sapura  (b)
50.0
%
 
50.0
%
SeaMex Ltd. ("SeaMex")  (b)
50.0
%
 
50.0
%
(a)  
Refer to the Seadrill Partners subsidiaries paragraph below for additional information.
(b)  
For transactions with related parties refer to Note 30 - Related party transactions.

SDLP investments

SDLP investments consist of the following:

(a) Subordinated units - Our holdings of subordinated units of Seadrill Partners are accounted for under the equity method on the basis that the subordinated units are considered to be ‘in-substance common stock’. The subordination period will end on the satisfaction of various tests as prescribed in the Operating Agreement of Seadrill Partners. Upon the expiration of the subordination period, the subordinated units will convert into Common Units. Our holding in the subordinated units represents 18% of the limited partner interests in Seadrill Partners.

(b) Direct ownership interests - All of our direct ownership interests in subsidiaries of Seadrill Partners are accounted for under the equity method. We deem these investments to represent significant influence over the investees through their voting rights and by virtue of Seadrill’s representation on the Board of Seadrill Partners. We hold ownership interests in the following entities controlled by Seadrill Partners as at December 31, 2018 :

i.
42% in Seadrill Operating LP : Seadrill Operating LP is a limited partnership and is controlled by its General Partner, Seadrill Operating GP LLC, which is wholly owned by Seadrill Partners.
ii.
49% Seadrill Capricorn Holdings LLC : Seadrill Capricorn Holdings LLC is a limited liability company. There is only one class of member interest which is deemed to represent voting common stock.
iii.
39% in Seadrill Deepwater Drillship Ltd and 49% indirect interest in Seadrill Mobile Units (Nigeria) Ltd. : Both entities are limited companies and only have one class of stock, which is deemed to represent voting common stock.

(c) Member interests and IDR's - Seadrill applies the cost method to account for its investment in Seadrill member interest and Incentive Distribution Rights (“IDR’s”) on the basis that they do not represent common stock interests and their fair value is not readily determinable. The investments are held at cost less impairment.

Seabras Sapura
Seabras Sapura is 50% owned by Sapura Energy, and 50% owned by Seadrill. We account for our 50% investment in Seabras Sapura under the equity method.

SeaMex
We own a 50% equity interest in SeaMex. The remaining 50% is owned by Fintech. We account for our 50% investment in the joint venture under the equity method.


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Table of Contents

Share in results from associated companies
Our share in results of our associated companies (net of tax) were as follows:
 
Successor

Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

Period from January 1, 2018 through July 1, 2018


Year ended December 31, 2017

Year ended December 31, 2016

Seadrill Partners - Direct ownership interests
(82
)
77

82

216

Seadrill Partners - Subordinated units
(20
)
22

22

44

Seabras Sapura
24

46

80

62

SeaMex
(12
)
4

—

20

Archer
—

—

(10
)
(59
)
Total share in results from associated companies (net of tax)
(90
)
149

174

283


Summary of Consolidated Statements of Operations for our equity method investees

On emergence from bankruptcy, our equity method investments were measured at fair value which resulted in a different basis from the underlying carrying values of the investees' net assets at the date of emergence. The basis differences comprise of (i) drilling unit basis differences which are depreciated over the remaining useful life of the associated asset and (ii) contract basis differences which are amortized over the remaining term of the contract. The unwinding of the basis difference is recognized as a "Share in results from associated companies" in the Consolidated Statement of Operations.

The results of the Direct ownership interests in the SDLP companies and our share in those results (net of tax) were as follows:
SDLP
Successor

Predecessor
(in $ millions)
Period from July 2, 2018 through December 31, 2018

Period from January 1, 2018 through July 1, 2018

Year ended
December 31, 2017

Year ended
December 31, 2016

Operating revenues
426

612

1,128

1,600

Net operating income
100

257

464

818

Net income
(127
)
201

235

546

 
 
 
 
 
Net (loss)/income allocated to SDLP direct ownership interests
(59
)
77

93

254

Amortization of basis differences
(23
)
—

(11
)
(38
)
Share in results of SDLP direct investments
(82
)
77

82

216

 
 
 
 
 
Net (loss)/income allocated to SDLP subordinated units
(15
)
22

24

49

Amortization of basis differences
(5
)
—

(2
)
(5
)
Share in results of SDLP subordinated units
(20
)
22

22

44


The results of the Seabras Sapura companies and our share in those results (net of tax) were as follows:

F-47
Table of Contents

Seabras Sapura
Successor

Predecessor
(in $ millions)
Period from July 2, 2018 through December 31, 2018

Period from January 1, 2018 through July 1, 2018

Year ended
December 31, 2017

Year ended
December 31, 2016

Operating revenues
232

241

487

389

Net operating income
124

125

244

201

Net income
88

92

160

124

 
 
 
 
 
Seadrill ownership percentage
50%
50%
50%
50%
Share of net income
44

46

80

62

 
 
 
 
 
Amortization of basis differences
(20
)
—

—

—

Total basis difference
(20
)
—

—

—

Share in results from Seabras Sapura (net of tax)
24

46

80

62


The results of the SeaMex companies and our share in those results (net of tax) were as follows:
SeaMex
Successor

Predecessor
(in $ millions)
Period from July 2, 2018 through December 31, 2018

Period from January 1, 2018 through July 1, 2018

Year ended
December 31, 2017

Year ended
December 31, 2016

Operating revenues
118

121

239

280

Net operating income
40

40

80

119

Net income
4

7

—

40

 
 
 
 
 
Seadrill ownership percentage
50%
50%
50%
50%
Share of net income
2

4

—

20

 
 
 
 
 
Amortization of basis differences
(14
)
—

—

—

Total basis difference
(14
)
—

—

—

Share in results from SeaMex (net of tax)
(12
)
4

—

20



Book value of our investments in associated companies

At the year end, the book values of our investments in our associated companies were as follows:
 
Successor

 
Predecessor

(In $ millions)
December 31, 2018

 
December 31, 2017

Seadrill Partners - Direct ownership interests
479

 
857

Seadrill Partners subsidiaries - Subordinated units
17

 
97

Seadrill Partners subsidiaries - IDRs
54

 
64

Seabras Sapura
209

 
353

SeaMex
41

 
102

Total
800

 
1,473


Quoted market prices for all of our other equity investments are not available because, other than Seadrill Partners Common Units, these companies are not publicly traded. Seadrill Partners subordinated units are not traded as we own 100% of them and hence have no quoted market price.

Summarized Consolidated Balance sheets for our equity method investees

The summarized balance sheets of the directly owned SDLP companies at the year and our share of recorded equity in those companies was as follows:

F-48
Table of Contents

SDLP
Successor

 
Predecessor

(in $ millions)
December 31, 2018

 
December 31, 2017

Current assets
1,110

 
1,214

Non-current assets
5,076

 
5,317

Current liabilities
(433
)
 
(546
)
Non-current liabilities
(3,039
)
 
(3,284
)
Net Assets
2,714

 
2,701

 
 
 
 
Seadrill share of book equity
1,399

 
1,398

Basis difference allocated to rigs
(1,019
)
 
—

Basis difference allocated to contracts
99

 
—

Prior period impairments and other adjustments
—

 
(541
)
SDLP book equity allocated to direct investments
479

 
857

 
 
 
 
SDLP book equity allocated to subordinated units (1)
17

 
97

(1)     Seadrill Partners subordinated units have a lock-up period during which they have subordinated liquidation and dividend rights. On application of fresh start accounting the units were valued with reference to the market price of common units and adjusted for a discount for lack of marketability (because of the subordination period). The value of the subordinated units on application of fresh start accounting was $37 million . Since application of fresh start accounting we allocated a share of the net loss incurred by Seadrill Partners to the subordinated units using a Hypothetical Liquidation at Book Value methodology. We allocated a net loss of $20 million for the period from July 2, 2018 through December 31, 2018. After allocating this loss the remaining balance of the investment in subordinated units at December 31, 2018 was $17 million .

The summarized balance sheets of the Seabras Sapura companies at the year and our share of recorded equity in those companies was as follows:
Seabras Sapura
Successor

 
Predecessor

(in $ millions)
December 31, 2018

 
December 31, 2017

Current assets
255

 
467

Non-current assets
1,567

 
1,630

Current liabilities
(599
)
 
(673
)
Non-current liabilities
(637
)
 
(1,014
)
Net Assets
586

 
410

Seadrill ownership percentage
50
%
 
50
%
Seadrill share of book equity
293

 
205

 
 
 
 
Shareholder loans held as equity
125

 
148

Basis difference allocated to rigs
(387
)
 
—

Basis difference allocated to contracts
178

 
—

Total adjustments
(84
)
 
148

Book value of Seadrill investment
209

 
353

The summarized balance sheets of the SeaMex companies at the year and our share of recorded equity in those companies was as follows:

F-49
Table of Contents

SeaMex
Successor

 
Predecessor

(in $ millions)
December 31, 2018

 
December 31, 2017

Current assets
253

 
294

Non-current assets
977

 
1,036

Current liabilities
(149
)
 
(222
)
Non-current liabilities
(627
)
 
(666
)
Net Assets
454

 
442

Seadrill ownership percentage
50
%
 
50
%
Seadrill share of book equity
227

 
221

 
 
 
 
Prior period impairments and other adjustments
—

 
(119
)
Basis difference allocated to rigs
(357
)
 
—

Basis difference allocated to contracts
171

 
—

Total adjustments
(186
)
 
(119
)
Book value of Seadrill investment
41

 
102



Note 19 – Newbuildings

Newbuildings consist of the following:
(In $ millions)



Opening balance as at January 1, 2017 (Predecessor)

1,531

Additions

5

Capitalized interest and loan related costs

28

Disposals (1)

(620
)
Impairment (2)

(696
)
Closing balance as at December 31, 2017 (Predecessor)

248

Additions

1

Closing balance as at July 1, 2018 (Predecessor)

249

Fresh Start adjustments (3)

(249
)
Opening balance as at July 2, 2018 (Successor)
 
—

Additions

—

Closing balance as at December 31, 2018 (Successor)

—


(1)  
In July 2017, Sevan Drilling and Cosco reached agreement to defer the Sevan Developer delivery period until June 30, 2020. The contract amendment included a termination clause for Cosco and therefore it was deemed that Sevan had lost control of the asset. The Newbuild asset and corresponding construction obligation were derecognized. Refer to Note 9 - Loss on disposals for further information.
(2)  
As part of the Chapter 11 proceedings, the Debtors negotiated and announced a global settlement with various creditors, including Samsung Heavy Industries ("Samsung") and Daewoo Shipbuilding & Marine Engineering ("DSME"). The global settlement included an agreement regarding the allowed claim of the newbuild shipyards Samsung and DSME, and the Debtors’ rejection and recognized termination of the newbuild contracts for the West Dorado, West Draco, West Aquila and the West Libra . As the Plan anticipated the rejection and termination of the newbuild contracts we recognized an impairment of the newbuild assets related to the West Dorado, West Draco, West Aquila and the West Libra, totaling $696 million , in the year ended December 31, 2017 (Predecessor).
(3)  
Adjustment to record the newbuildings at fair value based on the value derived from an income approach compared to the current contractual obligations remaining to be paid. Refer to Note 5 - Fresh Start Accounting for further information.


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Table of Contents



Note 20 – Drilling units

  (In $ millions)
 
 
Cost

 
Accumulated depreciation

 
Net book value

Opening balance as at January 1, 2017 (Predecessor)
 
 
17,753

 
(3,477
)
 
14,276

Additions
 
 
110

 
—

 
110

Depreciation
 
 
—

 
(779
)
 
(779
)
Disposals
 
 
(528
)
 
137

 
(391
)
Closing balance as at December 31, 2017 (Predecessor)
 
 
17,335

 
(4,119
)
 
13,216

Additions
 
 
117

 
—

 
117

Depreciation
 
 
—

 
(388
)
 
(388
)
Impairment
 
 
(414
)
 
—

 
(414
)
Closing balance as at July 1, 2018 (Predecessor)
 
 
17,038

 
(4,507
)
 
12,531

Fresh Start adjustments
 
 
(10,241
)
 
4,507

 
(5,734
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Opening balance as at July 2, 2018 (Successor)
 
 
6,797

 
—

 
6,797

Additions
 
 
93

 
—

 
93

Depreciation
 
 
—

 
(231
)
 
(231
)
Closing balance as at December 31, 2018 (Successor)
 
 
6,890

 
(231
)
 
6,659


On emergence from Chapter 11, the carrying value of our drilling units were adjusted to fair value, through a combination of income-based and market-based approaches, with accumulated depreciation being reset to nil. The total net fair value adjustment to our drilling units was $5,734 million , resulting in a loss recognized in the Consolidated Statement of Operations in "Reorganization items".

Impairment of long-lived assets

We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. In our reported period ended July 1, 2018 (Predecessor), we observed contracted dayrates to be below forecasted levels assumed, which was deemed an indicator of potential impairment. On assessment of asset recoverability through an estimated undiscounted future net cash flow we calculated the value to be lower than the carrying value, resulting in an impairment expense of $414 million which was classified within "Loss on impairment of long-lived assets" on our Consolidated Statement of Operations for the period from January 1, 2018 through July 1, 2018 (Predecessor).

We derived the fair value of the rigs using an income approach based on updated projections of future dayrates, contract probabilities, economic utilization, capital and operating expenditures, applicable tax rates and asset lives. The cash flows were estimated over the remaining useful economic lives of the assets and discounted using an estimated market participant weighted average cost of capital of 11.4% . To estimate these fair values, we were required to use various unobservable inputs including assumptions related to the future performance of our rigs as explained above. We based all estimates on information available at the time of performing the impairment test.


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Table of Contents

Note 21 – Equipment
 
Equipment consists of office equipment, software, furniture and fittings.
  (In $ millions)
 
 
Cost

 
Accumulated depreciation

 
Net book value

Opening balance as at January 1, 2017 (Predecessor)
 
 
77

 
(36
)
 
41

Additions
 
 
7

 
—

 
7

Depreciation
 
 
—

 
(19
)
 
(19
)
Closing balance as at December 31, 2017 (Predecessor)
 
 
84

 
(55
)
 
29

Additions
 
 
9

 
—

 
9

Depreciation
 
 
—

 
(3
)
 
(3
)
Closing balance as at July 1, 2018 (Predecessor)
 
 
93

 
(58
)
 
35

Fresh Start adjustments
 
 
(64
)
 
58

 
(6
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Opening balance as at July 2, 2018 (Successor)
 
 
29

 
—

 
29

Additions
 
 
5

 
—

 
5

Depreciation
 
 
—

 
(5
)
 
(5
)
Closing balance as at December 31, 2018 (Successor)
 
 
34

 
(5
)
 
29


On emergence from Chapter 11, the carrying value of our equipment was adjusted to fair value based on a cost-based approach, with accumulated depreciation being reset to nil. Refer to Note 5 - Fresh start accounting for further information. The total net fair value adjustment to our drilling units was $6 million , resulting in a loss recognized in the Consolidated Statement of Operations in "Reorganization items".


F-52
Table of Contents

Note 22 – Debt

As at December 31, 2018 (Successor) and 2017 (Predecessor), we had the following liabilities for third party debt agreements:
 
 
Successor

 
Predecessor

(In $ millions)
 
December 31, 2018

 
December 31, 2017

Secured credit facilities
 
5,662

 
5,581

New secured notes
 
769

 
—

Credit facilities contained within variable interest entities
 
655

 
786

Unsecured bonds
 
—

 
2,334

Total debt principal
 
7,086

 
8,701

Less: debt discount and fees

(172
)

(2
)
Carrying value
 
6,914

 
8,699


This was presented in our Consolidated Balance Sheet as follows.
 
 
Successor

 
Predecessor

(In $ millions)
 
December 31, 2018

 
December 31, 2017

Debt due within one year
 
33

 
509

Long-term debt
 
6,881

 
485

Liabilities subject to compromise
 
—

 
7,705

Total debt principal
 
6,914


8,699


As set out in Note 4 - Chapter 11 Proceedings, we filed for Bankruptcy and operated as a debtor-in-possession from September 12, 2017 to July 2, 2018. The Chapter 11 reorganization had several impacts on our debt as set out in the sections below. Further, whilst we were in Chapter 11 we prepared our Consolidated Financial Statements under ASC 852 "Reorganizations". This caused us to make the following accounting adjustments for our debt obligations:

•
On filing for Chapter 11, we recorded an impairment of $66 million against unamortized issuance costs on our impaired secured credit facilities and unsecured bonds. This expense was classified within reorganization items (see Note 4 for further details).
•
Whilst in Bankruptcy, we classified debt liabilities for our impaired secured credit facilities and unsecured bonds in our Consolidated Balance Sheet as liabilities subject to compromise.
•
During Bankruptcy, we continued to make interest payments on our secured credit facilities. These were treated as adequate protection payments which we recognized as a reduction in the principal balance of secured credit facilities held within "Liabilities subject to compromise". On emergence we expensed the $185 million of adequate protection payments we made during Chapter 11. We classified this expense within reorganization items (see Note 4 for further details).
•
On emergence from Chapter 11, 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. For fair value considerations, refer to Note 32 - Fair values of financial instruments .

In the next sections we cover key terms of our debt facilities at December 31, 2018, including any changes that resulted from the Chapter 11 Reorganization.

Secured Credit Facilities

The terms of our secured credit facilities were amended either through our Chapter 11 reorganization or, in the case of the $360 million facility , through a separate restructuring agreement. The main changes to the terms of our facilities that applied on emergence from Chapter 11 were as follows:

•
Amortization payments were deferred until 2020 ;
•
Maturities were extended to fall due between June 2022 and December 2024 ;
•
There was a 1% increase in margin.

Our credit facilities are secured by, among other things, liens on our drilling units. Our credit facility agreements contain cross-default provisions, meaning that if we defaulted and amounts became due and payable under one of our credit agreements, this would trigger a cross-default in our other facilities so that amounts outstanding under our other credit facility agreements become due and payable and capable of being accelerated.

We have summarized the key terms of our secured credit facilities as at December 31, 2018 in the table below:

F-53
Table of Contents

  Facility name
Maturity
Repayments before maturity ($m)

Final Repayment ($m)

Total ($m)

Margin on LIBOR floating interest
Collateral vessels
Book value of collateral vessels ($m)

Notes
$400 million facility
4Q 2022
51

84

135

3.50%
West Cressida
West Callisto
West Leda
157

(1)  
$2,000 million facility
1Q 2023
268

640

908

3.00%
West Alpha
West Venture
West Phoenix
West Navigator
West Epsilon
West Elara
794

 
$440 million facility
3Q 2023
24

40

64

4.25%
West Telesto
58

(2)  
$1,450 million facility
4Q 2023
87

235

322

1.2% - 4.0%
West Tellus
337

(3)  
$360 million facility
4Q 2023
78

132

210

3.75%
AOD I
AOD II
AOD III
201

(4)  
$300 million facility
1Q 2024
48

96

144

4.00%
West Tucana
West Castor
111

 
$1,750 million facility
1Q 2024
316

559

875

2.5% - 2.9%
Sevan Driller
Sevan Brasil
Sevan Louisiana
910

 
$450 million facility
4Q 2024
60

205

265

3.50%
West Eminence
290

 
$1,500 million facility
4Q 2024
355

770

1,125

2.38% - 3.25%
West Saturn
West Neptune
West Jupiter
1,051

(5)  
$1,350 million facility
4Q 2024
351

594

945

3.00%
West Pegasus
West Gemini
West Orion
917

 
$950 million facility
4Q 2024
207

359

566

2.12% - 3%
West Eclipse
West Carina
659

(6)  
$450 million facility (2015)
4Q 2024
63

40

103

3.85%
West Freedom
West Vigilant
West Prospero
West Ariel
186

 
Total secured credit facilities
5,662

 
 
 
 

(1)
In May 2017, we completed the sale of the West Triton to Shelf Drilling. Shelf Drilling subsequently repaid the tranches related to the West Triton in full, amounting to $47 million .
(2)  
In August 2017, Seadrill Partners amended certain credit facilities to insulate itself from Seadrill. This resulted in a $109 million repayment in respect of this facility. Please refer to Note 30 "Related party transactions" for further information.
(3)  
In August 2017, Seadrill Partners completed amendments to this facility to insulate itself from Seadrill Limited and therefore Seadrill no longer provided an indemnity to Seadrill Partners for any payments or obligations related to this facility that are not related to the West Auriga and West Vela .
(4)  
The facility is held by AOD, by which we hold a 67% ownership.
(5)  
This facility has a CIRR fixed interest rate of 2.38%
(6)  
This facility has a CIRR fixed interest rate of 2.12% and guarantee fee to the export credit agency of 1.30% .

New Secured Notes

On July 2, 2018, we raised $880 million of aggregate principle amount of 12.00% senior secured notes due in 2025 . The notes bear interest at the annual rate of 4.00% payable in cash plus 8.00% payment-in-kind. The principal borrowed on the notes included the initial $880 million principal value of the notes plus $10 million of payment-in-kind interest that was compounded into the principal on emergence from Chapter 11.

Per the terms of the New Secured Notes, we were required to redeem a proportion of the principal and interest outstanding on the notes using our share of the West Rigel sale proceeds. We received $126 million proceeds from the sale of the West Rigel on May 9, 2018 and used this to make a mandatory redemption of $121 million of principal and $5 million of accrued interest on November 1, 2018.

We were also required to make an offer to repurchase a proportion of the New Secured Notes using proceeds from a deferred consideration arrangement relating to the sale of our tender rig business to Sapura Energy in 2013. We made an offer to purchase up to $56 million of the New Secured Notes on October 10, 2018 . On expiry of the offer, $0.1 million in aggregate principal amount of the notes were validly tendered. We accepted and made payment for the tendered notes on November 14, 2018 .

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After the two redemptions there was a remaining $769 million principal outstanding on the notes.

The New Secured Notes are secured by, among other things, our investments in Seadrill Partners, SeaMex and Seabras Sapura. Refer to Note 18 - Investment in associated companies for further information.

Credit facilities contained within variable interest entities

We consolidate three legal subsidiaries of Ship Finance that own the West Taurus , West Hercules and West Linus . Please refer to Note 35 for further details of this arrangement. These facilities were also amended during the period to conform with the charter payment schedules which were amended as part of the RSA linked to our reorganization.

The terms of these facilities are set out in the below table:
  Facility Name
Maturity
Repayments before maturity ($m)

Final Repayment ($m)

Total ($m)

Margin on LIBOR floating interest
Collateral vessels
Book value of collateral vessels ($m)

$390 million facility
4Q 2022
60

144

204

Margin not disclosed
West Taurus
286

$375 million facility
2Q 2023
61

149

210

Margin not disclosed
West Hercules
343

$475 million facility
2Q 2023
62

179

241

Margin not disclosed
West Linus
194

Total credit facilities within VIEs
655

 
 
 

Unsecured Bonds

We ceased recording interest on unsecured bond facilities when we filed for Chapter 11 on September 12, 2017. The unsecured bonds were extinguished when we emerged from Chapter 11. Refer to Note 5 - Fresh start accounting for further information.

Debt maturities

The outstanding debt as at December 31, 2018 is repayable as follows:
(In $ millions)
 
December 31, 2018

2019
 
33

2020
 
407

2021
 
570

2022
 
973

2023
 
1,748

2024 and thereafter
 
3,355

Total debt principal
 
7,086


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Covenants and restrictions contained in our debt facilities

We have provided a summary of the main debt covenants contained within our debt facilities below:

The below financial covenants contained in our credit facilities post emergence are measured at the RigCo group level. Details of the levels which are required to be maintained under the credit facilities are as follows:

•
Aggregated minimum liquidity requirement for the Group: In summary, and as more particularly set out in the credit facilities, to maintain cash and cash equivalents of at least $525 million within the Group at any time during the period from and including the Effective Date to and including 31 December 2018; and $400 million at any time during the period from and including 1 January 2019 to the final maturity date of the credit facilities;
•
Net leverage ratio: to maintain a ratio of net debt to EBITDA as set out below (which will be tested on each financial quarter commencing with the financial quarter ending on March 31, 2022 until the final maturity date of the credit facilities):
Twelve months ended
 
Net leverage ratio
March 31, 2022
 
4.5x
June 30, 2022
 
4.2x
September 30, 2022
 
3.9x
December 31, 2022
 
3.7x
March 31, 2023
 
3.4x
June 30, 2023
 
3.3x
September 30, 2023
 
3.1x
December 31, 2023
 
3.0x
March 31, 2024
 
2.8x
June 30, 2024
 
2.7x
September 30, 2024
 
2.4x
December 31, 2024
 
2.2x

•
Debt service coverage ratio: in summary to maintain a ratio of EBIDTA to debt services (being all finance charges and principal, as more particularly set out in the credit facilities) equal to or greater than 1:1 (which will be tested on each financial quarter commencing with the financial quarter ending on March 31, 2022 until the final maturity date of the credit facilities).

In addition, for the periods ended March 31, 2021, June 30, 2021, September 30, 2021 and December 31, 2021 a margin increase will be enacted if:
•
Debt service coverage ratio is less than 0.8:1 in respect of the applicable period; and/or
•
Net leverage ratio is greater than:
Twelve months ended
 
Net leverage ratio
March 31, 2021
 
7.3x
June 30, 2021
 
6.6x
September 30, 2021
 
6.2x
December 31, 2021
 
5.8x

The covenants included in the New Secured Notes agreements limit our ability to:

•
Pay dividends or make certain other restricted payments or investments;
•
Incur additional indebtedness and issue disqualified shares;
•
Create liens on assets;
•
Amalgamate, merge, consolidate or sell substantially all our, NSNCo's, IHCo's, RigCo's and their respective subsidiaries and the guarantors' assets;
•
Enter into certain transactions with affiliates;
•
Create restrictions on dividends and other payments by our subsidiaries; and
•
Guarantee indebtedness by our subsidiaries.

The above covenants are subject to important exceptions and qualifications.


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Note 23 – Other liabilities
 
 
Successor

 
Predecessor

(In $ millions)
As at December 31,
2018

 
As at December 31,
2017

Accrued expenses
107

 
103

Taxes Payable
42

 
70

Accrued interest expense (1)
61

 
3

Employee withheld taxes, social security and vacation payments
40

 
15

Unfavorable contracts to be amortized
27

 
23

Deferred mobilization revenue (2)
19

 
55

Other liabilities
135

 
66

Total Other Liabilities  (3)
431

 
335

(1) Interest was settled monthly during the filing period.
(2) Residual deferred mobilization revenue was recognized in the predecessor on fresh start.
(3) Balances held as at December 31, 2017 exclude liabilities that were subject to compromise, which were reclassified to a separate line within the Consolidated Balance Sheet. This represents our estimate at 31 December, 2017 of known or potential pre-petition claims to be resolved in connection with the Chapter 11 proceedings. Refer to Note 1 - General information.

Other liabilities are presented in our Consolidated Balance Sheet as follows:
 
Successor

 
Predecessor

(In $ millions)
As at December 31,
2018

 
As at December 31,
2017

Other current liabilities
310

 
268

Other non-current liabilities
121

 
67

Total Other Liabilities
431

 
335


Unfavorable contracts

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. The amounts recognized represent the net present value of the existing contracts at the time of emergence compared to the current market rates at the time of acquisition, discounted at the weighted average cost of capital. We amortize these assets and liabilities over the remaining contract period and classify the amortization under operating expenses. For periods before emergence from Chapter 11 and application of fresh start accounting 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 expense for such contracts within other revenues.

The gross carrying amounts and accumulated amortization included in 'Other current liabilities' and 'Other non-current liabilities' for unfavorable contracts in the Consolidated Balance Sheets as follows:

 
 
Successor
 
Predecessor
 
 
December 31, 2018
 
December 31, 2017
(In $ millions)
 
Gross Carrying Amount

Accumulated amortization

Net carrying amount

 
Gross Carrying Amount

Accumulated amortization

Net carrying amount

Unfavorable contracts
 
 
 
—

 
 
 
 
Balance at beginning of period
 
(66
)
—

(66
)
 
(444
)
378

(66
)
Amortization of unfavorable contracts
 
—

39

39

 
—

43

43

Balance at end of period
 
(66
)
39

(27
)
 
(444
)
421

(23
)

The amortization is recognized in the Consolidated Statement of Operations under "Amortization of favorable and unfavorable contracts". For periods before emergence from Chapter 11 and application of fresh start accounting we recognized intangible liabilities only where we acquired

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a drilling contract in a business combination. We classified amortization expense for such contracts within other revenues in the Predecessor. The weighted average remaining amortization period for the unfavorable contracts is 2 years 11 months.

The table below shows the amounts relating to unfavorable contracts that is expected to be amortized over the following periods:
 
 
Period ended December 31,
(In $ millions)
 
2019

2020

2021

2022

2023 and after

Total

Amortization of unfavorable contracts
 
(19
)
(1
)
(1
)
(1
)
(5
)
(27
)

Note 24 – Common shares
 
Issued and fully paid share capital $0.10 par value each
 
Issued and fully paid share capital $2.00 par value each
 
Treasury shares held by the Company - $2.00 par value each
 
Shares

 
$ millions

 
Shares

 
$ millions

 
Shares

 
$ millions

At January 1, 2016 (Predecessor)
—

 
—

 
493,078,680

 
986

 
(318,740
)
 
(1
)
Share for debt exchange
—

 
—

 
15,684,340

 
31

 
—

 
—

Repurchase of shares
—

 
—

 
—

 
—

 
(4,000,000
)
 
(8
)
At December 31, 2016 (Predecessor)
—

 
—

 
508,763,020

 
1,017

 
(4,318,740
)
 
(9
)
Cancellation of shares
—

 
—

 
—

 
—

 
74,660

 
—

At December 31, 2017 (Predecessor)
—

 
—

 
508,763,020

 
1,017

 
(4,244,080
)
 
(9
)
At July 1, 2018 (Predecessor)
—

 
—

 
508,763,020

 
1,017

 
(4,244,080
)
 
(9
)
Cancellation of Predecessor Company common stock
—

 
—

 
(508,763,020
)
 
(1,017
)
 
4,244,080

 
9

Successor Company share issuance
100,000,000

 
10

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
At July 2, 2018 (Successor)
100,000,000

 
10

 
—

 
—

 
—

 
—

At December 31, 2018 (Successor)
100,000,000

 
10

 
—

 
—

 
—

 
—


Common share transactions after July 2, 2018 (Successor)
As at December 31, 2018 (Successor) our shares were listed on the Oslo Stock Exchange and the New York Stock Exchange. On emergence, our authorized share capital was $11 million consisting of 111,111,111 common shares each with a par value of $0.10 , of which 100,000,000 common shares are currently in issue. The Board of Directors has reserved the remaining 11,111,111 common shares for issuance under our employee incentive plan in accordance with the Plan.

All our issued and outstanding common shares are and will be fully paid. Subject to the Bye-Laws, the Board of Directors is authorized to issue any of the authorized but unissued common shares. There are no limitations on the right of non-Bermudians or non-residents of Bermuda to hold or vote in the Company's shares.

Holders of common shares have no pre-emptive, redemption, conversion or sinking fund rights. Holders of common shares are entitled to one vote per common share on all matters submitted to a vote of holders of common shares. Unless a different majority is required by law or the Bye-Laws, resolutions to be approved by holders of common shares require the approval by an ordinary resolution (being a resolution approved by a simple majority of votes cast at a general meeting at which a quorum is present). Under the Bye-Laws, each common share is entitled to dividends if, as and when dividends are declared by the Board of Directors, subject to any preferred dividend right of the holders of any preference shares.

In the event of liquidation, dissolution or winding up of the Company, the holders of common shares are entitled to share equally and ratably in the Company's assets, if any, remaining after the payment of all its debts and liabilities, subject to any liquidation preference on any issued and outstanding preference shares.

Common share transactions prior to July 2, 2018 (Predecessor)
Our predecessor Company was incorporated on May 10, 2005 and 6,000 ordinary shares of par value $2.00 each were issued. From incorporation to July 2, 2018 when the plan was confirmed by the Bankruptcy Court, the number of shares issues from our Predecessor company increased from 6,000 to 508,763,020 of par value $2.00 each.


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A share repurchase program for our Predecessor shares was approved by the Board in 2007 giving us the authorization to buy back shares. Shares bought back under the authorization could be cancelled or held as treasury shares. Treasury shares may be held to meet our obligations relating to the share option plans. This share repurchase program was cancelled on July 2, 2018 when the plan was confirmed by the Bankruptcy Court. As at December 31, 2017 (Predecessor) we held 4,244,080 Treasury shares.

During the year ended December 31, 2016 , as a result of the share-for-debt exchange the number of our predecessor common shares outstanding increased by 15,684,340 shares.

On September 5, 2016 we repurchased 4,000,000 shares in settlement of our total return swap agreements. This was completed at a strike price of NOK20.3 .


Note 25 – Non-controlling interest
 
Changes in non-controlling interest for the years ended December 31, 2018 (Successor), 2017 (Predecessor) and 2016 (Predecessor) are as follows:
(In $ millions)
North Atlantic Drilling Ltd

 
Sevan Drilling Limited

 
Asia Offshore Drilling Ltd

 
Ship Finance International Ltd VIEs

 
Seadrill Nigeria Operations Limited

 
Total

 
December 31, 2015 (Predecessor)
179

 
282

 
140

 
14

 
—

 
615

 
Changes in 2016
7

 
—

 
—

 
(112
)
 
6

 
(99
)
 
Net income attributable to non-controlling interest in 2016
(21
)
 
9

 
9

 
29

 
—

 
26

 
December 31, 2016 (Predecessor)
165

 
291

 
149

 
(69
)
 
6

 
542

 
Changes in 2017
—

 
—

 
—

 
(14
)
 
—

 
(14
)
 
Net income attributable to non-controlling interest in 2017
(89
)
 
(65
)
 
—

 
24

 
1

 
(129
)
 
December 31, 2017
76

 
226

 
149

 
(59
)
 
7

 
399

 
Adoption of new accounting standard ASU 2016-16 - Income Taxes
(25
)
 
—

 
—

 
—

 
—

 
(25
)
 
Net income attributable to non-controlling interest in period from January 1, 2018 to July 1, 2018
(160
)
 
(10
)
 
1

 
7

 
2

 
(160
)
 
Redeemable non-controlling interest
—

 
—

 
(150
)
 
—

 
—

 
(150
)
 
July 1, 2018 (Predecessor)
(109
)
 
216

 
—

 
(52
)
 
9

 
64

 
Elimination of NCI of North Atlantic Drilling Ltd and Sevan Drilling Limited
109

 
(216
)
 
—

 
—

 
—

 
(107
)
 
Fair value adjustment of the non-controlling interest in the Ship Finance VIEs and Seadrill Nigeria Operations Limited
—

 
—

 
—

 
199

 
(2
)
 
197

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
July 2, 2018 (Successor)
—

 
—

 
—

 
147

 
7

 
154

 
Net income attributable to non-controlling interest in period from July 2, 2018 to December 31, 2018
—

 
—

 
—

 
(2
)
 
—

 
(2
)
 
December 31, 2018
—

 
—

 
—

 
145

 
7

 
152

 

On emergence from Chapter 11 the non-controlling interest was adjusted to fair value. Refer to Note 5 - Fresh Start Accounting for further information.

North Atlantic Drilling Ltd and Sevan Drilling Limited

In the predecessor company we held a 70.36% interest in NADL and 50.11% interest in Sevan. The amount of shareholders' equity not attributable to us was included in non-controlling interests. As determined in the plan of reorganization, both companies became wholly owned subsidiaries of Seadrill and the non-controlling interests were eliminated prior to emergence on July 2, 2018.


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Asia Offshore Drilling Ltd
In the predecessor company we held a 66.24% interest in Asia Offshore Drilling Ltd. The amount of shareholders' equity not attributable to us was included in non-controlling interests. Subsequent to filing bankruptcy petitions, the predecessor executed a Transaction Support Agreement on April 4, 2018, which included a put option to the holders of the non-controlling interest shares. This redemption feature caused the fair value of the non-controlling interest held in AOD to be reclassified from equity to 'Redeemable non-controlling interest' within the Consolidated Balance Sheet. Refer to Note 26 - Redeemable non-controlling interest for further information.

Ship Finance International Ltd VIEs

In 2007 and 2008 we entered into sale and leaseback arrangements for drilling units with Ship Finance International Ltd, who incorporated subsidiary companies for the sole purpose of owning and leasing the drilling units. We had recognized these subsidiary companies as VIEs and concluded that we are their primary beneficiary. Accordingly, these subsidiary companies are included in our Consolidated Financial Statements, with the Ship Finance International Ltd equity in these companies included in non-controlling interest. Refer to Note 35 – Variable Interest Entities for more information.

During the predecessor years ended December 31, 2017 and 2016 dividends, of $14 million and $113 million were declared by VIEs to Ship Finance and was settled against related party balances with Ship Finance.

On emergence from Chapter 11 the non-controlling interest was adjusted to fair value. Refer to Note 5 – Fresh Start Accounting for further information.

Seadrill Nigeria Operations Limited

On December 5, 2016 (Predecessor), our wholly owned subsidiary, Seadrill UK Ltd., acquired a 10% interest that an unrelated party, HH Global Alliance Investments Limited (“HHL”) held in Seadrill Mobile Units (Nigeria) Ltd, the service company for West Capella , for a fair value of $6 million . Following the completion of this transaction Seadrill UK Ltd. owns 49% of Seadrill Mobile Units Nigeria Limited, with the remaining 51% being owned by subsidiaries of Seadrill Partners. Simultaneously HHL acquired from Seadrill UK Ltd. a 49% interest in Seadrill Nigeria Operations Limited, the service company for West Jupiter for a fair value of $6 million . The impact of these transactions was to increase Seadrill’s direct ownership interest in Seadrill Partners by $6 million , and to recognize HHL’s non-controlling interest in Seadrill Nigeria Operations Ltd of $6 million . During the year ended December 31, 2017 (Predecessor), HHL acquired a further 2% interest in Seadrill Nigeria Operations Ltd for total consideration of $0.3 million .

Note 26 - Redeemable non-controlling interest

Changes in redeemable non-controlling interest for the period from January 1, 2018 through July 1, 2018 (Predecessor) and period from July 2, 2018 through December 31, 2018 (Successor) are as follows:
(In $ millions) 
 
Asia Offshore Drilling Ltd

 
As at December 31, 2017 (Predecessor)
 
—

 
Reclassification from non-controlling interest
 
150

 
Fair value adjustment on initial recognition
 
(127
)
 
Net income attributable to redeemable non-controlling interest
 
2

 
Fresh start fair value adjustment
 
5

 
As at July 1, 2018 (Predecessor)
 
30

 
 
 
 
 
As at July 2, 2018 (Successor)
 
30

 
Fair value adjustment
 
9

 
Net loss attributable to redeemable non-controlling interest
 
(1
)
 
As at December 31, 2018 (Successor)
 
38

 

Subsequent to filing bankruptcy petitions, the Predecessor executed a Transaction Support Agreement (“TSA”) on April 4, 2018 with a minority shareholder of one of Seadrill Limited's subsidiaries, Asia Offshore Drilling Limited (“AOD”). The purpose of the TSA was to provide a framework for a monetization event for the minority shareholder of AOD as well as obtain unanimous approval of the AOD board of directors (which included the minority shareholder) in order for AOD to become a party to the RSA and participate in Seadrill’s broader debt restructuring under its Chapter 11 reorganization.

The TSA executed between the parties provided a put option to the holders of non-controlling interest shares. The put option gave the holders the right (with no obligation) to sell the shares it owns to Seadrill subject to a price ceiling. After the end of the effective period of the put option, if the right remains unexercised, Seadrill gets the right (with no obligation) to purchase the non-controlling interest in AOD at a price subject to

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the floor price (“Call Option”). While the call option provides for a redemption mechanism, the redemption option is made by Seadrill. The put option, however, generates a redemption feature for the non-controlling interest holder that is outside the control of Seadrill.

This redemption feature caused the fair value of the non-controlling interest held in AOD to be reclassified from equity to "Redeemable non-controlling interest" within the Consolidated Balance Sheets. Any fair value adjustments to generate an expected redemption value have been recognized through retained earnings.

In the period from January 1, 2018 through July 1, 2018 (Predecessor), we reclassified $150 million of non-controlling interest from equity to redeemable non-controlling interest on the date of the TSA (April 4, 2018) and recorded a fair value adjustment of $127 million on initial recognition. We attributed $2 million of net income to the redeemable non-controlling interest covering the period April 2018 to July 1, 2018, and a fair value adjustment on initial recognition of $5 million , resulting in the redeemable non-controlling interest having a fair value on July 1, 2018 (Predecessor) of $30 million . Subsequent changes in fair value are recognised in retained earnings.

In the period from July 2, 2018 through December 31, 2018 (Successor), we recognized a net loss attributable to redeemable non-controlling interest of $1 million and a fair value adjustment of $9 million , resulting in the redeemable non-controlling interest having a fair value on December 31, 2018 (Successor) of $38 million .

Note 27 – Accumulated other comprehensive income/(loss)

Accumulated other comprehensive income consists of the following:
(In $ millions)
Unrealized gain on marketable securities

 
Unrealized gain on foreign exchange

 
Actuarial gain/(loss) relating to pension

 
Share in unrealized gains from associated companies

 
Change in unrealized gain on interest rate swaps in VIEs

 
Change in debt component on Archer facility

 
Total

Balance at December 31, 2015 (Predecessor)
(151
)
 
36

 
(38
)
 
11

 
—

 
—

 
(142
)
Other comprehensive income before reclassifications
168

 
—

 
15

 
12

 
—

 
—

 
195

Balance as at December 31, 2016 (Predecessor)
17

 
36

 
(23
)
 
23

 
—

 
—

 
53

Other comprehensive income before reclassifications
14

 
—

 
(3
)
 
2

 
2

 
—

 
15

Amounts reclassified from accumulated other comprehensive income
—

 
—

 
—

 
(10
)
 
—

 
—

 
(10
)
Balance as at December 31, 2017 (Predecessor)
31

 
36

 
(26
)
 
15

 
2

 
—

 
58

Adoption of accounting standard update
(31
)
 
—

 
—

 
—

 
—

 
—

 
(31
)
Balance as at January 1, 2018 (Predecessor)
—

 
36

 
(26
)
 
15

 
2

 
—

 
27

Reset accumulated other comprehensive (loss)/income
—

 
(36
)
 
26

 
(15
)
 
(2
)
 
—

 
(27
)
Balance as at July 1, 2018 (Predecessor)
—

 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other comprehensive income before reclassifications
—

 
—

 
1

 
(5
)
 
—

 
(3
)
 
(7
)
Balance as at December 31, 2018 (Successor)
—

 
—

 
1

 
(5
)
 
—

 
(3
)
 
(7
)
 
In January 2016, the FASB issued ASU 2016-01 "Recognition and Measurement of Financial Assets and Financial Liabilities" to enhance the reporting model for financial instruments to provide users of financial statements with more decision-useful information. ASU 2016-01 became effective for fiscal years and interim periods beginning after December 15, 2017. We adopted ASU 2016-01 starting from January 1, 2018 on a modified retrospective basis, with no changes recognized in the prior year comparatives and a cumulative catch up adjustment recognized in the Predecessor opening retained earnings.

Upon adoption of ASU 2016-01, we reclassified $31 million of unrealized gains related to our marketable securities from accumulated other comprehensive income to retained earnings in the Predecessor. As a result of the adoption of this guidance we are required to recognize the movement in the fair value of our marketable securities in the Consolidated Statement of Operations. Refer to Note 15 "Marketable securities" for further information.


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On emergence from Chapter 11, the accumulated other comprehensive income of the Predecessor was reset to nil. For further information refer to Note 5 - Fresh start accounting.

The applicable amount of income taxes associated with each component of other comprehensive income in the Successor is nil , other than on the actuarial loss on pension, due to the fact that the items relate to companies domiciled in non-taxable jurisdictions. For actuarial loss related to pension, the accumulated applicable amount of income taxes is nil for the period from July 2, 2018 to December 31, 2018 ( $1 million for the period from January 1, 2018 to July 1, 2018 and $1 million for the year ended December 31, 2017 (Predecessor)) as this item is related to companies domiciled in Norway where the tax rate is 23% ( December 31, 2017 (Predecessor): 24% ).

Note 28 – Share based compensation
 
The share-based compensation expense for our Predecessor share options and Restricted Stock Unit plans in the Consolidated Statement of Operations for the period from January 1, 2018 through July 1, 2018 and years ended December 31, 2017 and 2016 was $9 million , $7 million , and $7 million respectively. The $9 million expense for the period from January 1, 2018 through July 1, 2018 included a charge of $6 million for schemes cancelled on emergence from Chapter 11. This was classified within reorganization items.

On August 16, 2018, we established an employee incentive plan with a limit of 11.1 million shares in Seadrill Limited. On September 4, 2018 we made a grant of 0.5 million Restricted Stock Units. The share-based compensation expense recognized in the Consolidated Statement of Operations for the period from July 2, 2018 through December 31, 2018 (Successor) was nil . The compensation cost for non-vested awards not yet recognized as at December 31, 2018 is $9 million , with a weighted average vesting period of 2 years and 9 months .

Note 29 - Pension benefits

Defined benefit plans

We have several defined benefit pension plans covering a number of our Norwegian employees. All the plans are administered by a life insurance company. Our net obligation is calculated separately for each plan by estimating the amount of the future benefit that employees have earned in return for their cumulative service. The aggregated projected future benefit obligation is discounted to present value, from which the aggregated fair value of plan assets is deducted. The discount rate is the market yield at the balance sheet date on government bonds in the relevant currency and based on terms consistent with the post-employment benefit obligations.

Actuarial gains and losses are recognized in the Consolidated Statement of Operations when the net cumulative unrecognized actuarial gains or losses for each individual plan at the end of the previous reporting year exceed 10 percent of the higher of the present value of the defined benefit obligation and the fair value of plan assets at that date. These gains and losses are recognized over the expected remaining working lives of the employees participating in the plans. Otherwise, recognition of actuarial gains and losses is included in other comprehensive income. Those amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income.

On retirement, or when an employee leaves the company, the member’s pension liability is transferred to the life insurance company administering the plan, and the pension plan no longer retains an obligation relating to the leaving member. This action is deemed to represent a settlement under U.S. GAAP, as it represents the elimination of significant risks relating to the pension obligation and related assets. Under settlement accounting, the portion of the net unrealized actuarial gains/losses corresponding to the relative value of the obligation reduction is recognized through the Consolidated Statement of Operations. However, settlement accounting is not required if the cost of all settlements in a year is not deemed to be significant in the context of the plan. We deem the settlement not to be significant when the cost of settlements in the year is less than the sum of service cost and interest cost in the year. In this case, the difference between the reduction in benefit obligation and the plan assets transferred to the life insurance company is recognized within “other comprehensive income,” rather than being recognized in the Consolidated Statement of Operations.

For onshore employees in Norway, who are participants in the defined benefit plans, the primary benefits are a retirement pension of approximately 66 percent of salary at retirement age of 67 years, together with a long-term disability pension. The retirement pension per employee is capped at an annual payment of 66 percent of the total of 12 times the Norwegian Social Security Base. Most employees in this group may choose to retire at 62 years of age on a pre-retirement pension.

Consolidated Balance Sheet position
 
Successor

 
Predecessor

(In $ millions)
December 31, 2018

 
December 31, 2017

Accrued pension liabilities - Non-current liabilities
4

 
6

Less: Deferred tax (Asset)
(1
)
 
(2
)
Shareholders' equity
3

 
4

 
Annual pension cost
We record pension costs in the period during which the services are rendered by the employees.

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Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018


Year ended December 31, 2017


Year ended December 31, 2016

Service cost
2

 
1

 
2

 
7

Interest cost on prior years’ benefit obligation
1

 
—

 
2

 
3

Gross pension cost for the year
3

 
1

 
4

 
10

Expected return on plan assets
(1
)
 
—

 
(1
)
 
(4
)
Net pension cost for the year
2

 
1

 
3

 
6

Social security cost
—

 
—

 
—

 
1

Amortization of actuarial gains/losses
—

 
—

 
—

 
1

Impact of settlement/curtailment funded status
—

 
—

 
(1
)
 
(1
)
Total net pension cost
2

 
1

 
2

 
7


The funded status of the defined benefit plan
 
Successor

 
Predecessor

(In $ millions)
December 31, 2018

 
December 31, 2017

Projected benefit obligations at end of period
37

 
38

Plan assets at market value
(33
)
 
(33
)
Accrued pension liability exclusive social security
4

 
5

Social security related to pension obligations
—

 
1

Accrued pension liabilities
4

 
6


Change in projected benefit obligations
 
Successor

 
Predecessor
(In $ millions)
December 31, 2018

 
June 30, 2018

December 31, 2017

Projected benefit obligations at beginning of period
36

 
38

60

Interest cost
1

 
—

2

Service cost
1

 
1

2

Benefits paid
(1
)
 
(1
)
(2
)
Change in unrecognized actuarial gain
2

 
(2
)
(3
)
Settlement
—

 
—

(24
)
Foreign currency translations
(2
)
 
—

3

Projected benefit obligations at end of period
37

 
36

38

 
Change in pension plan assets
 
Successor

 
Predecessor
(In $ millions)
December 31, 2018

 
June 30, 2018

December 31, 2017

Fair value of plan assets at beginning of year
33

 
33

58

Estimated return
1

 
—

1

Contribution by employer
—

 
2

1

Administration charges
—

 
—

—

Benefits paid
(1
)
 
(1
)
(2
)
Actuarial gain
2

 
(1
)
(5
)
Settlement
—

 
—

(23
)
Foreign currency translations
(2
)
 
—

3

Fair value of plan assets at end of year
33

 
33

33



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The accumulated benefit obligation for all defined benefit pension plans was $33 million and $33 million at December 31, 2018 (Successor) and 2017 (Predecessor), respectively.

Pension obligations are actuarially determined and are critically affected by the assumptions used, including the expected return on plan assets, discount rates, compensation increases and employee turnover rates. We periodically review the assumptions used and adjust them and the recorded liabilities as necessary.
 
During the year ended December 31, 2017, a number of employees left and as a result, the defined benefit scheme transferred the pension liability for these employees to the life insurance company administering the scheme. The difference between the reduction in benefit obligation and the plan assets transferred to the life insurance company has been recognized within “Other comprehensive income.” The settlement is not deemed to be significant in the context of the overall scheme and as such net unrecognized actuarial losses have not been recycled as a result of the settlement.

The expected rate of return on plan assets and the discount rate applied to projected benefits are particularly important factors in calculating our pension expense and liabilities. We evaluate assumptions regarding the estimated rate of return on plan assets based on historical experience and future expectations on investment returns, utilizing the asset allocation classes held by the plan’s portfolios. The discount rate is based on the covered bond rate in Norway. Changes in these and other assumptions used in the actuarial computations could impact the projected benefit obligations, pension liabilities, pension expense and other comprehensive income.

Assumptions used in calculation of pension obligations  
 
Successor
 
Predecessor
 
Period from July 2, 2018 through December 31, 2018


Period from January 1, 2018 through July 1, 2018


Year ended December 31, 2017


Year ended December 31, 2016

Rate of compensation increase at the end of year
2.75
%
 
2.50
%
 
2.50
%
 
2.50
%
Discount rate at the end of year
2.60
%
 
2.40
%
 
2.40
%
 
2.10
%
Prescribed pension index factor
2.00
%
 
2.00
%
 
1.50
%
 
1.20
%
Expected return on plan assets for the year
2.60
%
 
2.40
%
 
2.40
%
 
3.00
%
Employee turnover
4.00
%
 
4.00
%
 
4.00
%
 
4.00
%
Expected increases in Social Security Base
2.50
%
 
2.25
%
 
2.25
%
 
2.25
%

The weighted-average asset allocation of funds related to our defined benefit plan at December 31, was as follows:

Pension benefit plan assets   
 
Successor

 
Predecessor

 
December 31, 2018

 
December 31, 2017

Equity securities
12.7
%
 
10.6
%
Debt securities
70.0
%
 
66.1
%
Real estate
9.9
%
 
8.8
%
Money market
6.9
%
 
13.5
%
Other
0.5
%
 
1.0
%
Total
100.0
%
 
100.0
%

The investment policies and strategies for the pension benefit plan funds do not use target allocations for the individual asset categories. The investment objectives are to maximize returns subject to specific risk management policies. We diversify our allocation of plan assets by investing in both domestic and international fixed income securities and domestic and international equity securities. These investments are readily marketable and can be sold to fund benefit payment obligations as they become payable.
 
Cash flows - Contributions expected to be paid
 
The table below shows our expected annual pension plans contributions under defined benefit plans for the years ending December 31, 2019-2028 . The expected payments are based on the assumptions used to measure our obligations at December 31, 2018 and include estimated future employee services. 

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(In $ millions)
December 31, 2018

2019
2

2020
2

2021
2

2022
3

2023
3

2024-2028
13

Total payments expected during the next 10 years
25


Defined contribution and other plans

We made contributions to personal defined contribution pension and other plans totaling $9 million for the period from July 2, 2018 through December 31, 2018 (Successor) and $10 million for the period from January 1, 2018 through July 1, 2018 (Predecessor). For the year to December 31, 2017 (Predecessor) and December 31, 2016 (Predecessor) the charge was $17 million and $26 million , respectively. These were charged as operational expenses as they became payable.

Note 30 – Related party transactions

Our main related parties include (i) affiliated companies over which we hold significant influence and (ii) companies who are either controlled by or whose operating policies may be significantly influenced by our major shareholder, Hemen.

Companies in which we hold significant influence include (i) Seadrill Partners, (ii) SeaMex and (iii) Seabras Sapura. Companies that are controlled by or whose operating policies may be significantly influenced by Hemen include (i) Ship Finance, (ii) Archer, (iii) Frontline, (iv) Seatankers and (v) Northern Drilling. In the following sections we provide an analysis of (i) transactions with related parties and (ii) balances outstanding with related parties.

Related party revenue
The below table provides an analysis of related party revenues for periods presented in this report.
 
Successor
 
Predecessor
  (In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

 
Year ended December 31, 2016

Management fee revenues (a)
41

 
41


84


72

In country support services revenues (b)
—

 
1


23


25

Related party inventory sales
1

 
1


—


1

Other
4

 
—


3


2

Total related party operating revenues (c)
46

 
43


110


100


(a) We provide management and administrative services to Seadrill Partners and SeaMex and operation and technical support services to Seadrill Partners, SeaMex and Northern Drilling. We charge our affiliates for support services provided either on a cost-plus mark up or dayrate basis.

(b) We previously provided in country support services to the Seadrill Partners rig West Polaris when it operated in Angola. The West Polaris 's contract ended in December 31, 2018, so we no longer earn revenues under this arrangement.

(c) In addition to the amounts shown above, we recognized reimbursable revenues of $10 million in the period from July 2, 2018 through December 31, 2018 for work performed to mobilize the Northern Drilling rig West Mira for its first drilling contract, which we expect to commence in 2019.

Related party operating expenses
The below table provides an analysis of related party operating expenses for periods presented in this report.

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Successor
 
Predecessor
  (In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

 
Year ended December 31, 2016

In country support services expenses (d)
—

 
1


8


14

Related party inventory purchases
—

 
3


3


1

Other related party operating expenses (e)
1

 
3

 
3

 
5

Net bareboat charter arrangements (f)
—

 
—


(1
)

(7
)
Total related party operating expenses
1

 
7

 
13

 
13


(d) Seadrill Partners previously provided us with in-country support services for the West Jupiter in Nigeria. This arrangement ended in early 2018. In addition, SeaMex previously provided us with in-county support services for the West Pegasus and West Freedom when those rigs operated in Mexico and Venezuela.

(e) We received services from certain other related parties. These included management and administrative services from Frontline, warehouse rental from Seabras Sapura and other services from Archer and Seatankers.

(f) We previously acted as an intermediate charterer for the Seadrill Partners rig West Aquarius , during its contract with Hibernia in Canada, which ended in April 2017. We also acted as an intermediate charterer for the Seadrill Partners rigs T-15 and T-16 until December 2016.

Related party financial items
The below table provides an analysis of related party financial income for periods presented in this report.
 
Successor
 
Predecessor
  (In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

 
Year ended December 31, 2016

Interest income (g)
15

 
12


34


29

Gains on related party derivatives (h)
—

 
—

 
1

 
1

Interest income recognized on deferred contingent consideration (i)
1

 
2


3


4

Total related party financial items
16

 
14

 
38

 
34


(g) We earn interest income on our related party loans to SeaMex and Seabras Sapura (see below). We also previously earned interest income on our related party loans to Seadrill Partners.

(h) We previously held interest rate swap agreements with Seadrill Partners. These were canceled when we filed for Chapter 11 in September 2017.

(i) We record interest income on deferred consideration receivables from Seadrill Partners (see item (k) below).

Related party receivable balances
The below table provides an analysis of related party receivable balances for periods presented in this report.
 
 
Successor
 
Predecessor
(In $ millions)
 
December 31, 2018

 
December 31, 2017

Related party loans and interest (j)
 
476

 
495

Deferred consideration arrangements (k)
 
59

 
52

Convertible bond (l)
 
43

 
53

Trading balances (m)
 
138

 
164

Total related party receivables
 
716

 
764


(j) We have loan receivables outstanding from SeaMex and Seabras Sapura. We previously had loan receivables from Seadrill Partners, which have been repaid. We have summarized the amounts outstanding in the table below:

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Successor
 
Predecessor
(In $ millions)
 
December 31, 2018

 
December 31, 2017

SeaMex seller's credit and loans receivable
 
398

 
369

Seabras loans receivable
 
78

 
101

Seadrill Partners - West Vencedor  facility
 
—

 
25

Total related party loans and interest
 
476

 
495


SeaMex loans include (i) $250 million "sellers credit" provided to SeaMex in March 2015 which matures in December 2019 (ii) $45 million working capital loan advanced in November 2016 and (iii) $103 million accrued interest on above loans and other funding. The sellers credit and working capital loan both earn interest at 6.5% and are subordinated to SeaMex's external debt facility.

Seabras loans include a series of loan facilities that we extended to Seabras Sapura between May 2014 and December 2016. The $78 million balance shown in the table above includes (i) $70 million of loan principal and (ii) $8 million of accrued interest. The loans are repayable on demand, subject to restrictions on Seabras Sapura's external debt facilities. We earn interest of between 3.4% - LIBOR + 3.99% on the loans, depending on the facility. We received repayments against these related party loans of $23 million during 2018.

In addition to the Seabras loans referred above, we have made certain other shareholder loans to Seabras Sapura, which we classify as part of our equity method investment in Seabras Sapura. See Note 18 - "Investments in Associated Companies" for further details. We received repayments against these shareholder loans of $20 million during 2018.

The outstanding balance of the West Vencedor facility was repaid by Seadrill Partners in May 2018.

(k) Deferred consideration arrangements include receivables due to us from Seadrill Partners from the sale of the West Vela and the West Polaris to Seadrill Partners in November 2014 and June 2015 respectively. We have summarized amounts due for each period in the table below:

 
 
Successor
 
Predecessor
(In $ millions)
 
December 31, 2018

 
December 31, 2017

West Vela  - Mobilization receivable
 
31

 
44

West Vela  - Share of dayrate
 
27

 
4

West Polaris
 
1

 
5

Total deferred consideration receivable
 
59

 
53


On adoption of fresh start accounting, we recorded receivables for West Vela share of dayrate and West Polaris earnout. These amounts were previously accounted for as gain contingencies so were only recognized when realized. The receivables were recognized at fair value of $29 million and $1 million respectively and the gain was recognized in reorganization items.

We recorded the following gains in other operating income for these arrangements.
 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
December 31, 2017

 
December 31, 2016

West Polaris  earn out realized
—

 
—

 
13

 
8

West Vela  earn out realized
—

 
7

 
14

 
13

Total contingent consideration recognized
—

 
7

 
27

 
21



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(l) On April 26, 2017, we converted $146 million , including accrued interest and fees, in subordinated loans provided to Archer into a $45 million convertible loan. The subordinated convertible loan bears interest of 5.5% , matures in December 2021 and has a conversion right into equity of Archer Limited in 2021. At inception, the fair value of the convertible bond was $56 million whereas the previous loan had a carrying value of $37 million . We therefore recognized a gain on debt extinguishment of $19 million in 2017 because of this transaction.

The loan receivable is a convertible debt instrument comprised of a debt instrument and a conversion option, classed as an embedded derivative. Both elements are measured at fair value at each reporting date. As at December 31, 2018 (Successor), the fair value of the convertible debt instrument was $43 million of which the split between debt and embedded derivative option was $43 million and nil respectively.

The fair value gain/(loss) on the convertible bond for periods presented is summarized below:
 
Successor
 
Predecessor
  (In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

Fair value (loss) / gain of Archer debt component
(3
)
 
2

 
1

Fair value (loss) / gain of Archer embedded conversion option
(9
)
 
2

 
(4
)

(m) Trading balances primarily comprise receivables from Seadrill Partners and SeaMex for related party management fees. In addition, certain receivables and payables arise when we pay an invoice on behalf of Seadrill Partners or SeaMex and vice versa. Receivables and payables are generally settled quarterly in arrears.

Related party payable balances
The below table provides an analysis of related party receivable balances for periods presented in this report.
 
 
Successor
 
Predecessor
(In $ millions)
 
December 31, 2018

 
December 31, 2017

Related party loans payable (n)
 
222

 
314

Trading balances (o)
 
39

 
10

Total related party liabilities
 
261

 
324


(n) Related party loans include related party loans from Ship Finance to the Ship Finance subsidiaries that we consolidated as variable interest entities (see Note 35 - Variable Interest Entities for further details). The carrying amount of the loans was $222 million at December 31, 2018 (2017: $314 million ). The principal outstanding on the loans was $314 million at December 31, 2018, (2017: $314 million ).
There is a right of offset of trading balance assets against the loans, the net position is disclosed within “Long-term debt due to related parties” on the Consolidated Balance Sheets. As at December 31, 2018 (Successor) the trading position was a net asset position of $4 million .
The loans bear interest at a fixed rate of 4.5% per annum and mature between 2023 and 2029. The total interest expense incurred for the period from July 2, 2018 through December 31, 2018 (Successor) was $7 million , the period from January 1, 2018 through July 1, 2018 (Predecessor) was $7 million (year ended December 31, 2017 (Predecessor): $15 million ).

(o) Trading balances primarily include related party payables due from our Ship Finance variable interest entities to Ship Finance and trading balances due from us to SeaMex and Seadrill Partners.

Related party assets and liabilities are presented in our Consolidated Balance Sheet as follows:

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Successor
 
Predecessor
(In $ millions)
 
December 31, 2018

 
December 31, 2017

Amount due from related parties - current
 
177

 
217

Amount due from related parties - non-current
 
539

 
547

Amounts due to related parties - current
 
(39
)
 
(10
)
Long-term debt due to related parties
 
(222
)
 
(314
)
Total net related party balances
 
455

 
440


Other related party transactions
Seabras Sapura guarantees - In November 2012, a subsidiary of Seabras Sapura Participações S.A. entered into a $179 million senior secured credit facility agreement in order to part fund the acquisition of the Sapura Esmeralda pipe-laying support vessel, with a maturity in 2032. During 2013 an additional facility of $36 million was entered into, with a maturity in 2020 . As a condition to the lenders making the loan available, we provided a sponsor guarantee, on a joint and several basis with the joint venture partner, Sapura Energy, in respect of the obligations of the borrower. The total amount guaranteed by the joint venture partners as at December 31, 2018 (Successor) was $165 million (December 31, 2017 (Predecessor): $184 million ).

In December 2013 certain subsidiaries of Seabras Sapura Holding GmbH entered into a $543 million senior secured credit facility agreement in order to part fund the acquisition of the Sapura Diamante, and Sapura Topazio pipe-laying support vessels ("PLSV 1 facility"). As a condition to the lenders making the loan available to each of the borrowers, we provided a sponsor guarantee, on a 50:50 basis with the joint venture partner, Sapura Energy, in respect of the obligations of the borrowers during certain defined time periods, the release of such guarantees being subject to the satisfaction of certain defined conditions. The guarantees covered obligations and liabilities of the borrowers under the facility agreement which arose during the period between the expiry of a contract and extension or renewal of that contract and following a guarantee extension relating to early termination of a contract. During these periods, the guarantees could only be called if the facility was in default. The guarantee was automatically discharged on emergence from Chapter 11 and any related potential claims from lenders were waived as part of a deal reached on October 31, 2018. The total amount guaranteed by the Predecessor as at December 31, 2017 was $186 million .
In April 2015, certain subsidiaries of Seabras Sapura Holding GmbH entered into a $780 million senior secured credit facility agreement in order to part fund the acquisition of the Sapura Onix, Sapura Jade and Sapura Rubi pipe-laying support vessels ("PLSV 2 facility"). As a condition to the lenders making the loan available to each of the borrowers, we provided a sponsor guarantee, on a 50:50 basis with the joint venture partner, Sapura Energy, in respect of the obligations of the borrowers during certain defined time periods, the release of such guarantees being subject to the satisfaction of certain defined conditions. The guarantees covered obligations and liabilities of the borrowers under the facility agreement which arose during the period between the expiry of a contract and extension or renewal of that contract and following a guarantee extension relating to early termination of a contract. During these periods, the guarantees can only be called if the facility is in default. The guarantee was automatically discharged on emergence from Chapter 11 and any related potential claims from lenders were waived as part of a deal reached on October 31, 2018. The amount guaranteed by the Predecessor as at December 31, 2017 was $328 million .
On October 31, 2018, we completed a transaction that fully extinguished the sponsor guarantees given by Seadrill and Sapura Energy for the benefit of the lenders of the PLSV 1 and PLSV 2 facilities. Our guarantee obligations were previously released, discharged and terminated as part of the Chapter 11 proceedings and under the terms of the October 31 transaction, the lenders confirmed that they had no outstanding claims against Seadrill in respect of our guarantees and also released and discharged Sapura Energy's guarantees. In return for the release and discharge of both sponsors’ guarantees, the lenders under the debt facilities have received, amongst other things, cross-collateralisation of the debt facilities, a prepayment from the joint venture, an increase in margin and a consent fee.
We have not recognized a liability for any of the above guarantees as we did not consider it to be probable that the guarantees would be called.

Other guarantees - In addition, we have made certain guarantees over the performance of Seadrill Partners, SeaMex and Archer on behalf of customers and suppliers. Please refer to Note 33- "Commitments and contingencies" for details.

Omnibus agreement - In 2012 we entered into an Omnibus Agreement with Seadrill Partners. The agreement outlines the following provisions: (i) a non-competition agreement with Seadrill Partners for any drilling rig operating under a contract for five or more years; (ii) rights of first offer on any proposed sale, transfer or other disposition of drilling rigs; (iii) rights of first offer on any proposed transfer, assignment, sale or other disposition of any equity interest in Seadrill Operating LP, Seadrill Capricorn Holdings LLC and Seadrill Partners Operating LLC (the "OPCO"); and indemnification – Old Seadrill Limited agreed to indemnify Seadrill Partners against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to Seadrill Partners, and also certain tax liabilities. Refer to exhibit 4.4.


Note 31 – Financial instruments and risk management

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.

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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 interest rate swap agreements, currency option contracts and foreign currency contracts 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 also a concentration of credit risk with respect to cash and cash equivalents to the extent that most of the amounts are carried with Citibank, Nordea Bank Finland Plc, Danske Bank A/S, BNP Paribas and ING Bank N.V. We consider these risks to be remote. For details on the customers with greater than 10% of contract revenues, refer to Note 6 - Segment information.  

Foreign exchange risk

As is customary in the oil and gas industry, a majority 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.

Before we entered Chapter 11, we had unsecured bonds denominated in Norwegian Krone and Swedish Krona. These bonds were extinguished on emergence from Chapter 11. Our remaining foreign exchange exposures primarily relate to foreign denominated cash and working capital balances. We do not expect these remaining 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 December 31, 2018 (Successor) in the below table.
(In $ millions)
 
Principal outstanding

 
Hedging instruments - see below

 
Net exposure

 
Impact of 1% increase in rates

Senior Credit Facilities
 
5,662

 
4,500

 
1,162

 
15

Debt contained within VIEs
 
655

 
—

 
655

 
6

Total floating rate debt obligations
 
6,317

 
4,500

 
1,817

 
21

New Secured Notes
 
769

 
—

 
—

 
—

Less: Cash and Restricted Cash
 
(2,003
)
 
—

 
(2,003
)
 
(20
)
Net debt
 
5,083

 
4,500

 
(186
)
 
1


At December 31, 2017 we were in Chapter 11 and did not make interest payments on our Senior Credit Facilities. Our exposure to interest rate risk was therefore limited to loans contained within VIEs. The net exposure on those debt obligations was not materially different to the amount shown in the above table.

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 therefore does 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 December 31, 2018 was 2.81% . Therefore, the interest cap would mitigate the impact of 94% of a theoretical 1% point increase in the LIBOR rate. This is set out in the below table.


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(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

 
(42
)
 
3

Senior Credit Facility debt - not hedged
 
1,162

 
12

 
—

 
12

Total Senior Credit Facility Debt
 
5,662

 
57

 
(42
)
 
15


One of the Ship Finance subsidiaries that we consolidate as a VIE (refer to Note 35 "Variable Interest Entities") 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.

Gains and losses on derivatives reported in consolidated statement of operations

Gains and losses on derivatives reported in our consolidated statement of operations included the following:

 
Successor
 
Predecessor
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31,
2017

 
Year ended December 31,
2016

(Loss)/gain recognized in the Consolidated Statement of Operations relating to derivative financial instruments
 
 
 
 
 
 
 
Interest rate cap agreement
(22
)
 
(6
)
 
—

 
—

Archer convertible debt instrument
(9
)
 
2

 
(4
)
 
—

Interest rate swaps not designated for hedge accounting
—

 
—

 
(31
)
 
(48
)
Cross currency swaps not designated for hedge accounting
—

 
—

 
46

 
(20
)
Other
—

 
—

 
—

 
(6
)
Loss/(gain) on derivative financial instruments
(31
)
 
(4
)
 
11

 
(74
)

Interest rate cap - This represents changes in fair value on our interest rate cap agreement referred above.

Archer convertible debt instrument - This represents gains and losses on the conversion option included within a $45 million convertible bond issued to us by Archer. Please see Note 30 - Related party transactions for further details.

Interest rate swaps and cross currency swaps - Prior to filing for Chapter 11 (Predecessor), we used interest rate swaps and cross currency swaps to mitigate the impact of currency and interest rate fluctuations on our debt. When we filed for Chapter 11 we triggered a default under these agreements and our counterparties terminated the contracts and received an allowed claim for damages suffered. We reversed the liabilities for these instruments and recorded liabilities equal to the expected value of the allowed claims received by our counterparties. The allowed claim values were higher than the previous fair values, which factored in a discount for our own credit risk, so this led to an expense of $89 million . We classified the expense within reorganization items (see note 4 for further details).

Derivative financial instruments included in our Consolidated Balance Sheet

Derivative financial instruments included in our Consolidated Balance Sheet, within "Other Assets" included the following:
 
(In $ millions)
Maturity date
Applicable rate
Outstanding principal - December 31, 2018

As at December 31, 2018

As at December 31, 2017

 
 
Interest rate cap
June 2023
2.87% LIBOR cap
4,500

39

—

 
Interest rate hedge agreement in the VIE
October 2018 - December 2018
1.77% - 2.01%
—

—

—

 
 
 
 
 
39

—





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Note 32 - Fair values of financial instruments
 
Fair value of financial instruments measured at amortized cost

The carrying value and estimated fair value of our financial instruments that are measured at amortized cost at December 31, 2018 (Successor) and December 31, 2017 (Predecessor) are as follows:
 
Successor
 
Predecessor
 
December 31, 2018
 
December 31, 2017
(In $ millions)
Fair
value

 
Carrying
value

 
Fair
value

 
Carrying
value

Assets
 
 
 
 
 
 
 
Related party loans receivable (1)   (Level 2)
476

 
476

 
470

 
470

 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
Secured credit facilities (Level 2)
5,388

 
5,519

 
N/A (2)

 
5,581

Credit facilities contained within variable interest entities (Level 2)
612

 
626

 
N/A (2)

 
786

New secured notes (Level 1)
770

 
769

 
—

 
—

Unsecured bonds (Level 2)
—

 
—

 
N/A (2)

 
2,334

Related party loans payable by the VIE (Level 2)
222

 
226

 
218

 
314

(1) Excludes Archer convertible debt receivable, which is measured at fair value on a recurring basis  
(2) During the period we were in Chapter 11 Bankruptcy, the fair value for these financial instruments was not reasonably determinable.

Level 1
The fair value of the secured notes are derived using market traded value. We have categorized this at level 1 on the fair value measurement hierarchy. Refer to Note 22 – Debt for further information.

Level 2
Upon the adoption of fresh start accounting, the related party loans receivable from Seadrill Partners, SeaMex and Seabras Sapura were recorded at fair value. We estimate that the fair value continues to be equal to the carrying value as at December 31, 2018 as the debt is not freely tradable and cannot be recalled by us at prices other than specified in the loan note agreements and the loans were entered into at market rates. They are categorized as level 2 on the fair value measurement hierarchy. Other trading balances with related parties are not shown in the table above and are covered under Note 30 - Related party transactions. The fair value of other trading balances with related parties are also assumed to be equal to their carrying value.

The fair value of the secured credit facilities and Ship Finance loans are derived using the discounted cash flow model, using a cost of debt of 7%.

The fair value of the loans provided by Ship Finance to our VIE's are derived using the discounted cash flow model, using a cost of debt of 11% . We have categorized this at level 2 on the fair value measurement hierarchy. Refer to Note 30 - Related party transactions for further information.

Financial instruments measured at fair value on a recurring basis

The carrying value and estimated fair value of our financial instruments that are measured at fair value on a recurring basis at December 31, 2018 (Successor) and December 31, 2017 (Predecessor) are as follows: 
 
Successor
 
Predecessor
 
December 31, 2018
 
December 31, 2017
(In $ millions)
Fair
value

 
Carrying
value

 
Fair
value

 
Carrying
value

Assets
 
 
 
 
 
 
 
Cash and cash equivalents ( Level 1)
1,542

 
1,542

 
1,255

 
1,255

Restricted cash (Level 1)
461

 
461

 
104

 
104

Marketable securities (Level 1)
57

 
57

 
124

 
124

Related party loans receivable - Archer convertible debt (Level 3)
43

 
43

 
53

 
53

Interest rate cap (Level 2)
39

 
39

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Temporary equity
 
 
 
 
 
 
 
Redeemable non-controlling interest (Level 3)
38

 
38

 
—

 
—



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Level 1
The carrying value of cash and cash equivalents and restricted cash, which are highly liquid, is a reasonable estimate of fair value and categorized at level 1 on the fair value measurement hierarchy. Quoted market prices are used to estimate the fair value of marketable securities, which are valued at fair value on a recurring basis.

Level 2
The fair value of the interest rate cap as at December 31, 2018 is calculated using well-established independence valuation techniques and counterparty non-performance credit risk assumptions. The calculation of the credit risk in the swap values is subject to a number of assumptions including an assumed credit default swap rate based on our traded debt, and recovery rate, which assumes the proportion of value recovered, given an event of default. We have categorized these transactions as level 2 on the fair value measurement hierarchy.

Level 3
The Archer convertible debt instrument is bifurcated into two elements. The fair value of the embedded derivative option is calculated using a modified version of the Black-Scholes formula for a currency translated option. Assumptions include Archer's share price in NOK, NOK/ USD FX volatility and dividend yield. The fair value of the debt component is derived using the discounted cash flow model including assumptions relating to cost of debt and credit risk associated to the instrument.

The redeemable non-controlling interest in AOD is calculated by applying a fair value to the three AOD rigs and debt facility using a discounted cash flow model. The rig values are determined using an income approach based on projected future dayrates, contract probabilities, economic utilization, capital and operating expenditures, applicable tax rates and asset lives, discounted using a weighted average cost of capital of 11% . The fair value of the debt is derived using the discounted cash flow model, using a cost of debt of 8% .

Fair value considerations on one-time transactions

Fresh start valuations
The Plan presented on February 26, 2018, and confirmed by the Bankruptcy Court on April 17, 2018, estimated a range of distributable value for the Successor Company of which a reorganization value was derived based on the mid-point of this range of estimated distributable values. The reorganization value represents the fair value of the Successor Company’s total assets and, under fresh start accounting, we are required to allocate the reorganization value to individual assets based on their estimated fair values. For further information, refer to Note 5 - Fresh Start Accounting.

Drilling unit impairment
In our reported Predecessor period ended July 2, 2018 (Predecessor), we recorded an impairment expense of $414 million against our drilling units, derived from a fair value using an income approach based on updated projections of future dayrates, contract probabilities, economic utilization, capital and operating expenditures, applicable tax rates and asset lives. For further information, refer to Note 20 - Drilling units.

Impairment of marketable securities and investments in associated companies and joint ventures
In the years ended December 31, 2017 and 2016 we recognized impairments on our investments in marketable securities, associated companies and joint ventures following deteriorating conditions in the oil and gas industry and supply and demand conditions in the offshore drilling sector. For further information and fair value considerations, refer to Note 11 - Impairment loss on marketable securities and investments in associated companies.

Note 33 – Commitments and contingencies
 
Legal Proceedings

From time to time we are a party, as plaintiff or defendant, to lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the construction or operation of our drilling units, in the ordinary course of business or in connection with our acquisition or disposal activities.  We believe that the resolution of such claims will not have a material impact individually or in the aggregate on our operations or financial condition. Our best estimate of the outcome of the various disputes has been reflected in our Consolidated Financial Statements as at December 31, 2018 .

Sevan Drilling
On June 29, 2015, Sevan Drilling disclosed that it had initiated an internal investigation into activities with an agent under certain drilling contracts with Petrobras in Brazil, which were entered prior to the separation from the Sevan Marine Group. On October 16, 2015, Sevan Drilling further disclosed that Sevan Drilling ASA, previously the parent company of Sevan Drilling, had been accused of breaches of Sections 276a and 276b of the Norwegian Criminal Code in respect of payments made in connection with the performance during 2012 to 2015 of drilling contracts originally awarded by Petrobras to Sevan Marine ASA in the period between 2005–2008. On May 4, 2018, Sevan Drilling disclosed that Norway's anti-corruption agency, Økokrim, had completed its investigation and that the charges had been dismissed. Accordingly, no loss contingency has been recognized in Seadrill’s Consolidated Financial Statements.

Seabras Sapura joint venture
The Sapura Esmeralda, operates under a temporary Brazilian flag which expires on July 29, 2019. Seabras Sapura is currently in the process of applying for a registration with Brazilian authorities which will entitle the vessel to permanently fly the Brazilian flag. There is a risk that if no permanent right to fly the Brazilian flag is obtained, or that the temporary flag is revoked and Seabras Sapura is unsuccessful in any appeals or

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in pursuing other available remedies, this could affect the operations of the Sapura Esmeralda and potentially impact its commercial agreements and related financing.

Patent infringement
In January 2015, a subsidiary of Transocean Ltd. filed suit (“the Suit”) against certain of our subsidiaries for patent infringement. The Suit alleged that one of our drilling rigs operating in the U.S. Gulf of Mexico, along with two rigs owned by Seadrill Partners, violated Transocean patents relating to dual-activity. In the same year, we challenged the validity of the patents via the Inter Parties Review process within the U.S. Patent and Trademark Office. The IPR board held in March 2017 that the patents were valid. In May 2017 we appealed to the U.S. Federal Circuit Court of Appeal and in June 2018 the court affirmed the IPR decision.  The Suit passed through the Chapter 11 bankruptcy proceedings unimpaired and was reinstated.

In December 2018, Seadrill and Seadrill Partners reached an amicable agreement with Transocean over alleged patent infringement of the Transocean dual activity patent. Under the terms of the settlement, Seadrill and Seadrill Partners have entered into a global license agreement with Transocean of the dual activity drilling method on our rigs covering alleged past infringements and future use.

Dalian Newbuilds
At December 31, 2018, we had contractual commitments under two (2017: eight) newbuilding contracts with Dalian totaling $0.4 billion (2017: $1.7 billion). In January 2019, Dalian appointed an administrator to restructure its liabilities.

Contracts for the newbuild jack-up rigs West Titan , West Proteus , West Rhea , West Hyperion , West Tethys and West Umbriel were terminated as of December 31, 2018. Further, in February 2019, the Seadrill contracting party terminated the contract to acquire the jack-up rig West Dione due to: (i) delays to delivery of the rig, and (ii) Dalian being subject to bankruptcy proceedings. In March 2019, Dalian purported to terminate the eighth newbuilding contract for the West Mimas . The Seadrill contracting party rejected Dalian’s termination of the contract as wrongful and reserved all its rights. The Seadrill contracting party will obtain a right to terminate the contract for the West Mimas for delay and claim a refund of the pre-delivery installments plus interest in early April 2019, and it intends to enforce all its rights under the contract as they arise.

In March 2019, the Seadrill contracting parties commenced arbitration proceedings in the UK for all eight rigs and will claim for the return of the paid installments plus interest and further damages for losses. They will also file claims for these amounts as part of the Dalian insolvency. Dalian has maintained it has a damages claim in respect of each of the rigs. The contracts are all with limited liability subsidiaries of Seadrill. There are no parent company guarantees. Apart from the Seadrill contracting parties’ claims for repayment of the paid installments plus interest, no quantification of claims has been made by either party.

Guarantees

We have issued guarantees in favor of third parties as follows, which is the maximum potential future payment for each type of guarantee:
 
Successor

 
Predecessor

  (In $ millions)
December 31, 2018

 
December 31, 2017

Guarantees in favor of customers 1, 2, 3
7

 
203

Guarantees in favor of banks 4
165

 
698

Guarantees in favor of suppliers 1, 3
1

 
11

Total
173

 
912


(1)  
Guarantees to Seadrill Partners - Within guarantees in favor of customers are guarantees provided on behalf of Seadrill Partners of $7 million (Predecessor 2017 : $165 million ). Guarantees in favor of suppliers includes guarantees on behalf of Seadrill Partners of $1 million (Predecessor 2017 : $1 million ). Refer to Note 30 - Related party transactions for more information.

(2)
Guarantees to SeaMex - Within guarantees in favor of customers are guarantees provided on behalf of SeaMex being nil for the Successor 2018 (Predecessor 2017 : $30 million ). Refer to Note 30 - Related party transactions for more information.

(3)  
Guarantees to Archer - Within guarantees provided to customers are guarantees provided on behalf of Archer being nil for the Successor 2018 (Predecessor 2017 : $8 million ). Guarantees in favor of suppliers include guarantees on behalf of Archer being nil for the Successor 2018 (Predecessor 2017 : GBP 7 million ( $10 million )). Refer to Note 30 - Related party transactions for more information.

(4)  
Guarantees to Seabras Sapura - Within guarantees in favor of banks are guarantees provided on behalf of Seabras Sapura Participacoes and Seabras Sapura Holdco totaling $165 million (Predecessor 2017 : $698 million ). Refer to Note 30 - Related party transactions for more information.

As of the Consolidated Balance Sheet date we have not recognized any liabilities for the above guarantees, as we do not consider it is probable for the guarantees to be called.

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Note 34 – Operating leases

We have operating leases relating to our premises, the most significant being our offices in London, Liverpool, Oslo, Stavanger, Singapore, Houston, Rio de Janeiro and Dubai.

In the period from July 2, 2018 through December 31, 2018 (Successor) and the period from January 1, 2018 through July 1, 2018 (Predecessor) rental expenses amounted to $7 million and $9 million . Rental expenses for the years ended December 31, 2017 (Predecessor) and 2016 (Predecessor) amounted to $19 million and $17 million , respectively. Future minimum rental payments are as follows:

Year
  (In $ millions)
2019
11

2020
9

2021
9

2022
5

2023
3

2024 and thereafter
1

Total
38

 
Note 35 – Variable Interest Entities
 
As at December 31, 2018 (Successor), we have two semi-submersible rigs and a jack-up rig from VIEs under capital leases. Each of the units had been sold by us to single purpose subsidiaries of Ship Finance and simultaneously leased back by us on bareboat charter contracts for a term of 15 years . We have several options to repurchase the units during the charter periods, and obligations to purchase the assets at the end of the 15 years lease period.


The following table gives a summary of the sale and leaseback arrangements and repurchase options from VIEs, as at December 31, 2018 :
Unit
 
Effective
from
 
Sale value
(In $ millions)
 
First
repurchase
option
(In $ millions)
 
Month of first
repurchase
option
 
Last
repurchase
option (1)
(In $ millions)
 
Month of last
repurchase
Option (1)
West Taurus
 
Nov 2008
 
850
 
418
 
Feb 2015
 
154
 
Dec 2024
West Hercules
 
Oct 2008
 
850
 
580
 
Aug 2011
 
138
 
Dec 2024
West Linus
 
June 2013
 
600
 
370
 
Jun 2018
 
170
 
May 2029

(1)
Ship Finance has a right to require us to purchase the West Linus rig on the 15th anniversary for the price of $86 million if we don’t exercise the final repurchase option.
 
We have determined that the Ship Finance subsidiaries, which own the units, are VIEs, and that we are the primary beneficiary of the risks and rewards connected with the ownership of the units and the charter contracts. Accordingly, these VIEs are fully consolidated in our Consolidated Financial Statements. The equity attributable to Ship Finance in the VIEs is included in non-controlling interests in our Consolidated Financial Statements. At December 31, 2018 (Successor) and at December 31, 2017 (Predecessor) the units are reported within drilling units in our balance sheet. We did not record any gains from the sale of the units, as they continued to be reported as assets at their original cost in our Consolidated Balance Sheet at the time of each transaction. The investment in capital lease amounts are eliminated on consolidation against the corresponding capital lease liability held within Seadrill entities. The remainder of assets and liabilities of the VIEs are fully reflected within the Consolidated Financial Statements.
 
The bareboat charter rates are set on the basis of a Base LIBOR Interest Rate for each bareboat charter contract, and thereafter are adjusted for differences between the LIBOR fixing each month and the Base LIBOR Interest Rate for each contract. A summary of the average bareboat charter rates per day for each unit is given below for the respective years.
(In $ thousands)
 
2018
 
2019
 
2020
 
2021
 
2022
 
2023
West Taurus
 
112
 
102
 
101
 
96
 
96
 
179
West Hercules
 
117
 
101
 
100
 
96
 
96
 
180
West Linus
 
158
 
119
 
99
 
99
 
92
 
171


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The assets and liabilities in the statutory accounts of the VIEs as at December 31, 2018 (Successor) and as at December 31, 2017 (Predecessor) are as follows:
 
Successor
 
Predecessor
(In $ millions)
December 31, 2018
 
December 31, 2017
 
SFL
Deepwater
Limited

 
SFL
Hercules
Limited

 
SFL
Linus
Limited

 
SFL
Deepwater
Limited

 
SFL
Hercules
Limited

 
SFL
Linus
Limited

Name of unit
West Taurus

 
West Hercules

 
West Linus

 
West Taurus

 
West Hercules

 
West Linus

Investment in finance lease
320

 
307

 
397

 
335

 
326

 
431

Amount due from related parties
—

 
—

 
—

 
4

 
4

 
—

Other assets (1)
2

 
—

 
—

 
6

 
6

 
8

Total assets
322

 
307

 
397

 
345

 
336

 
439

 
 
 
 
 
 
 
 
 
 
 
 
Short-term interest-bearing debt
16

 
8

 
9

 
226

 
27

 
48

Long-term interest-bearing debt
179

 
193

 
221

 
—

 
224

 
261

Other liabilities
2

 
—

 
—

 
3

 
2

 
—

Short-term trading balances due to related parties
—

 
10

 
21

 
—

 
—

 
4

Long-term debt due to related parties (2)
84

 
62

 
76

 
113

 
80

 
121

Total liabilities
281

 
273

 
327

 
342

 
333

 
434

Equity
41

 
34

 
70

 
3

 
3

 
5


(1)
Includes cash balance of $2 million as at December 31, 2018 (Successor) ( December 31, 2017 (Predecessor): $17 million ). These have been consolidated into the Consolidated Balance Sheet within "Cash and cash equivalents".
(2)
We present balances due to/from Ship Finance on a net basis, due to the fact that there is a right to offset established in the long-term loan agreements, and the balances are intended to be settled on a net basis.
    
 
Successor
 
Predecessor
(In $ millions)
December 31, 2018
 
December 31, 2017
 
SFL
Deepwater
Limited

 
SFL
Hercules
Limited

 
SFL
Linus
Limited

 
SFL
Deepwater
Limited

 
SFL
Hercules
Limited

 
SFL
Linus
Limited

Debt principal outstanding
113

 
80

 
121

 
113

 
80

 
121

Debt discount
(25
)
 
(18
)
 
(45
)
 
—

 
—

 
—

Trading asset positions held against long-term loan
(4
)
 
—

 
—

 
—

 
—

 
—

Long-term loan due to related parties
84

 
62

 
76

 
113

 
80

 
121


In the period ended December 31, 2018 (Successor), the VIEs declared and paid no dividends ( December 31, 2017 (Predecessor): $14 million ).

Note 36 – Assets held for sale

West Rigel
On December 2, 2015 (Predecessor), we signed an amendment with Jurong Shipyard (“Jurong”) for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel (the “Unit”). The deferral period originally lasted until June 2, 2016 (Predecessor), but this was subsequently extended to July 6, 2018.

In the event no employment was secured for the Unit, no alternative action is completed and following completion of the deferral period, we agreed with Jurong that we would form a Joint Asset Holding Company for joint ownership of the Unit, of which 23% was to be owned by us and 77% by Jurong.

On December 26, 2017 (Predecessor), Jurong announced that a sale agreement, subject to conditions had been signed for the West Rigel . As the agreement is pursuant to conditions being met, we continued to hold the asset within "Non-current assets held for sale" in the year ended December 31, 2017 (Predecessor).

On April 5 (Predecessor), 2018, we entered into a settlement and release agreement, subject to Bankruptcy Court approval, with Jurong whereby we agreed that our share of the sale proceeds from the sale of the West Rigel by Jurong would be $126 million . To reflect this as

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the asset held for sale value at December 31, 2017 (Predecessor), a further $2 million loss on disposal was recognized in the Consolidated Statement of Operations for the year ended December 31, 2017 (Predecessor).

On May 9, 2018 the West Rigel was sold by Jurong and we received a share of proceeds totaling $126 million .

Note 37 - Supplementary cash flow information

The table below summarizes the non-cash investing and financing activities relating to the periods presented:
 
Successor
 
Predecessor
 
(In $ millions)
Period from July 2, 2018 through December 31, 2018

 
Period from January 1, 2018 through July 1, 2018

 
Year ended December 31, 2017

 
Year ended December 31, 2016

Non-cash investing activities
 
 
 
 
 
 
 
Sale of rigs and equipment (1)
—

 
—

 
103

 
—

Increase of investment in Seadrill Mobile Units (Nigeria) Ltd (2)
—

 
—

 
—

 
(6
)
Proceeds from repayment of short-term loan from related parties due to Seadrill Partners insulation from Seadrill Limited (3)
—

 
—

 
109

 
—

Derecognition of Sevan Developer newbuild asset (4)
—

 
—

 
620

 
—

Derecognition of Sevan Developer construction obligation (4)
—

 
—

 
(526
)
 
—

 
 
 
 
 
 
 
 
Non-cash financing activities
 
 
 
 
 
 
 
Repayment of debt following sale of rigs and equipment (1)
—

 
—

 
(103
)
 
—

Increase in non-controlling interest in Seadrill Nigeria Operations Ltd (2)
—

 
—

 
—

 
7

Repayment of debt following insulation of Seadrill Partners from Seadrill Limited (3)
—

 
—

 
(109
)
 
—

Conversion of convertible bond into shares, decrease in long term debt (5)
—

 
—

 
—

 
(105
)
Conversion of convertible bond into shares, net increase in equity (5)
—

 
—

 
—

 
58

Proceeds from long-term loans (6)
—

 
—

 
—

 
150

Long term loans netted-down with related party balances (6)
—

 
—

 
—

 
(150
)
Dividend to non-controlling interests in VIEs (7)
—

 
—

 
(14
)
 
(113
)

(1)  
During the year ended December 31, 2017 (Predecessor), we completed the sale of the West Triton, West Resolute and West Mischief to Shelf Drilling, receiving cash consideration of $ 122 million . This comprised sales value of $225 million offset by $103 million of debt repayments. Refer to Note 9 - Loss on disposals for further information.

(2)  
During the year ended December 31, 2016 (Predecessor), our wholly owned subsidiary Seadrill UK Ltd. acquired a 10% interest that an unrelated party, HH Global Alliance Investments Limited (“HHL”) held in Seadrill Mobile Units (Nigeria) Ltd, the service company for West Capella , for a notional value of $6 million . Simultaneously HHL acquired from Seadrill UK Ltd. a 49% interest in Seadrill Nigeria Operations Limited, the service company for West Jupiter for a notional value of $6 million . The impact of these transactions was to increase Seadrill’s direct ownership interest in Seadrill Partners by $6 million , and to recognize HHL’s non-controlling interest in Seadrill Nigeria Operations Ltd of $6 million .

(3)  
During the year ended December 31, 2017 (Predecessor), Seadrill Partners amended certain credit facilities to insulate itself from Seadrill Limited. This resulted in a $109 million repayment in respect to the $440 million secured debt facility. Refer to Note 30 - Related party transactions for further information on related party transactions.

(4)  
During the year ended December 31, 2017 (Predecessor), Sevan and Cosco agreed to defer the Sevan Developer delivery period until June 30, 2020. The contract amendment included a contract termination clause for Cosco and therefore it was deemed that Sevan had lost control of the asset and therefore derecognized the newbuild asset, which was held at $620 million , construction obligation held at $526 million , and accrued interest and other liabilities held at $19 million , resulting in a net loss on disposal of $75 million . Refer to Note 9 – Loss on disposals for further information.

(5)  
In May 2016 (Predecessor), we entered into a privately negotiated exchange agreement with certain holders of our outstanding 5.625% (subsequently increased to 6.125% ) Senior Notes due in 2017 (the "2017 Notes"), pursuant to which we agreed to issue a total of 8,184,340 new shares of our common stock, par value $2.00 per share, in exchange for $55 million principal amount of the 2017 Notes. Settlement occurred on May 20, 2016 , upon which we had a total of 500,944,280 shares of our common stock issued and outstanding.


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In June 2016 (Predecessor), we entered into another privately negotiated exchange agreement with certain holders of our outstanding 5.625% (subsequently increased to 6.125% ) Senior Notes due 2017 (the "2017 Notes"), pursuant to which we agreed to issue a total of 7,500,000 new shares of our common stock, par value $2.00 per share, in exchange for $50 million principal amount of the 2017 Notes. We had a total of 508,444,280 shares of our common stock issued and outstanding, post settlement on June 13, 2016 .

(6)  
During the year ended December 31, 2016 (Predecessor), the Ship Finance VIEs that we consolidate withdrew bank loans and made loans to the related party Ship Finance International. These balances are presented net in the Consolidated Statement of Cash Flows. Refer to Note 22 "Long-term debt" for further information.

(7)  
During the years ended December 31, 2017 and December 31, 2016 , the Ship Finance VIEs declared dividends payable to Ship Finance. Refer to Note 35 - Variable interest entities for further information.

Note 38 – Subsequent Events

Sonangol
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.

Receipt of overdue receivable
In January 2019, we received $26 million for an overdue receivable which was fully provided in the Predecessor company. This will be recognized as other operating income in our first quarter 2019 results.

Tender offer of New Secured Notes
In February 2019, we launched a consent solicitation for proposed amendments to our Senior Secured Notes due in 2025 where we planned to launch a tender offer for the Senior Secured Notes. The required majority of Note holders representing greater than 50% of the principal amount outstanding agreed to consent to the proposed amendments and to participate in the tender offer.

In March 2019, we launched a c.$311 million tender offer at an offer price of 107 . Following completion of the tender offer, the outstanding Senior Secured Notes held by third parties is expected to reduce from $769 million to $458 million .

Dalian Newbuilds
The Newbuild contract for the jack-up rig West Dione was terminated in February 2019. In March 2019, the Seadrill contracting parties commenced arbitration proceedings on all eight Dalian rigs and will claim for repayment of yard installments plus interest and damages.








F-78
Table of Contents

Seadrill Partners LLC
Index to Consolidated Financial Statements



A - 1
Table of Contents

Management’s Annual Report on Internal Control over Financial Reporting

The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15 and Rules 15d-15 promulgated under the Exchange Act.
Internal controls over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers and effected by the Board, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
Provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with generally accepted accounting principles, and that the Company's receipts and expenditures are being made only in accordance with authorizations of Company's management and directors; and
•
Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree or compliance with the policies or procedures may deteriorate.
Our Management, with the participation of the Chief Executive Officer and the Chief Financial Officer, assessed the effectiveness of the design and operation of our internal control over financial reporting pursuant to Rule 13a-15 of the Exchange Act as of December 31, 2018.

Management conducted the evaluation of the effectiveness of internal control over financial reporting using the control criteria framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), published in its report entitled Internal Control- Integrated Framework (2013). Management reviewed the results of its assessment with the Audit Committee of our Board of Directors. Based on this assessment, Management concluded that, as of December 31, 2018, our internal control over financial reporting was effective.


A - 2
Table of Contents

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Members of Seadrill Partners LLC
 
Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying Consolidated Balance Sheets of Seadrill Partners LLC and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of Operations, of Changes in Members’ Capital and of Cash Flows for each of the three years in the period ended December 31, 2018 including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under Item 15. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.




/s/ PricewaterhouseCoopers LLP
Uxbridge, United Kingdom
March 28, 2019

We have served as the Company’s auditor since 2012.  


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SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
for the years ended December 31, 2018, 2017 and 2016
(In US$ millions, except per unit data)
 
 
Note
 
2018
 
2017
 
2016
Operating revenues
 
 
 
 
 
 
 
Contract revenues
 
 
$
797.5

 
$
1,007.7

 
$
1,356.4

Reimbursable revenues
 
 
31.2

 
17.7

 
32.8

Other revenues
7

*
209.5

 
103.0

 
211.1

Total operating revenues
 
 
1,038.2

 
1,128.4

 
1,600.3

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Vessel and rig operating expenses
 
*
(278.2
)
 
(345.4
)
 
(373.9
)
Depreciation
11

 
(280.3
)
 
(274.9
)
 
(266.3
)
Amortization of favorable contracts
10

 
(45.1
)
 
(74.4
)
 
(70.6
)
Reimbursable expenses
 
 
(28.6
)
 
(16.1
)
 
(30.2
)
General and administrative expenses
 
*
(45.8
)
 
(44.8
)
 
(41.2
)
Total operating expenses
 
 
(678.0
)
 
(755.6
)
 
(782.2
)
 
 
 
 
 
 
 
 
Other operating items
 
 
 
 
 
 
 
Loss on impairment of goodwill
 
 
(3.2
)
 
—

 
—

Revaluation of contingent consideration
 
 
—

 
89.9

 
—

Gain on sale of assets
 
 
—

 
0.8

 
—

Total other operating items
8

 
(3.2
)
 
90.7

 
—

 
 
 
 
 
 
 
 
Operating income
 
 
357.0

 
463.5

 
818.1

 
 
 
 
 
 
 
 
Financial items
 
 
 
 
 
 
 
Interest income
 
 
47.1

 
15.7

 
11.5

Interest expense
 
*
(263.7
)
 
(179.1
)
 
(180.0
)
Gain/(loss) on derivative financial instruments
15

*
24.9

 
(13.9
)
 
(18.0
)
Currency exchange gain
 
 
0.2

 
0.9

 
0.6

Other financial expenses
 
 
(4.8
)
 
(11.5
)
 
—

Total financial items
 
 
(196.3
)
 
(187.9
)
 
(185.9
)
 
 
 
 
 
 
 
 
Income before income taxes
 
 
160.7

 
275.6

 
632.2

Income tax expense
6

 
(86.7
)
 
(40.3
)
 
(86.5
)
Net income
 
 
74.0

 
235.3

 
545.7

 
 
 
 
 
 
 
 
Net income attributable to the non-controlling interest
 
 
17.9

 
94.1

 
264.7

Net income attributable to Seadrill Partners LLC owners
 
 
56.1

 
141.2

 
281.0

 
 
 
 
 
 
 
 
Earnings per unit (common and subordinated)
 
 
 
 
 
 
 
Common unitholders
 
 
$
0.75

 
$
1.88

 
$
3.20

Subordinated unitholders
 
 
$
—

 
$
—

 
$
2.28

* Includes transactions with related parties. Refer to Note 14 - "Related party transactions".
A Statement of Other Comprehensive Income has not been presented as there are no items recognized in other comprehensive income.
See accompanying notes that are an integral part of these Consolidated Financial Statements.

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SEADRILL PARTNERS LLC
CONSOLIDATED BALANCE SHEETS
As of December 31, 2018 and 2017
(In US$ millions)
 
Note
2018
 
2017
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
841.6

 
$
848.6

Accounts receivables, net
9

150.9

 
254.1

Amount due from related party
14

6.4

 
24.2

Other current assets
10

110.6

 
86.8

Total current assets
 
1,109.5

 
1,213.7

Non-current assets:
 
 
 
 
Drilling units
11

5,005.6

 
5,170.9

Goodwill
3

—

 
3.2

Deferred tax assets
6

7.7

 
9.5

Other non-current assets
10

62.6

 
133.5

Total non-current assets
 
5,075.9

 
5,317.1

Total assets
 
$
6,185.4

 
$
6,530.8

 
 
 
 
 
LIABILITIES AND MEMBERS' CAPITAL
 
 
 
 
Current liabilities:
 
 
 
 
Current portion of long-term debt
12

$
162.9

 
$
162.9

Current portion of long-term related party debt
14

—

 
24.7

Trade accounts payable and accruals
 
25.7

 
37.4

Current portion of deferred and contingent consideration to related party
14

37.5

 
41.7

Related party payable
14

126.3

 
157.0

Other current liabilities
13

80.2

 
121.8

Total current liabilities
 
432.6

 
545.5

Non-current liabilities:
 
 
 
 
Long-term debt
12

2,896.2

 
3,180.2

Deferred and contingent consideration to related party
14

21.5

 
46.0

Deferred tax liability
6

0.4

 
1.5

Other non-current liabilities
13

120.5

 
55.8

Total non-current liabilities
 
3,038.6

 
3,283.5

 
 
 
 
 
Commitments and contingencies (see Note 17)
 
 
 
 
Equity
 
 
 
 
Members' Capital:
 
 
 
 
Common unitholders (issued 75,278,250 units as at December 31, 2018 and December 31, 2017)
 
1,224.8

 
1,208.9

Subordinated unitholders (issued 16,543,350 units as at December 31, 2018 and December 31, 2017)
 
104.9

 
94.8

Total members' capital
 
1,329.7

 
1,303.7

Non-controlling interest
 
1,384.5

 
1,398.1

Total equity
 
2,714.2

 
2,701.8

Total liabilities and equity
 
$
6,185.4

 
$
6,530.8

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


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SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31, 2018, 2017 and 2016
(In US$ millions)
 
 
 
2018
 
2017
 
2016
Cash Flows from Operating Activities
 
 
 
 
 
 
Net income
 
$
74.0

 
$
235.3

 
$
545.7

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation
 
280.3

 
274.9

 
266.3

Amortization of deferred loan charges
 
12.4

 
12.6

 
11.4

Amortization of favorable contracts
 
45.1

 
74.4

 
70.6

Gain on disposal of PPE
 
—

 
(0.8
)
 
—

Loss on impairment of goodwill
 
3.2

 
—

 
—

Unrealized gain related to derivative financial instruments
 
(38.9
)
 
(25.8
)
 
(32.2
)
Unrealized foreign exchange loss/(gain)
 
0.5

 
(3.5
)
 
(9.4
)
Payment for long term maintenance
 
(91.6
)
 
(54.9
)
 
(48.0
)
Gain on revaluation of contingent consideration
 
—

 
(89.9
)
 
—

Deferred tax expense
 
0.7

 
4.6

 
19.2

Accretion of discount on deferred consideration
 
5.3

 
13.2

 
17.3

 
 
 
 
 
 
 
Changes in operating assets and liabilities, net of effect of acquisitions
 
 
 
 
 
 
Trade accounts receivable
 
103.2

 
(1.6
)
 
38.7

Prepaid expenses and accrued income
 
(3.6
)
 
(4.0
)
 
8.6

Trade accounts payable
 
(11.7
)
 
5.4

 
7.8

Related party balances
 
(12.9
)
 
16.1

 
(64.3
)
Other assets
 
15.5

 
34.4

 
70.0

Other liabilities
 
56.5

 
(4.9
)
 
(12.1
)
Changes in deferred revenue
 
(3.4
)
 
(9.7
)
 
(17.0
)
Other, net
 
(0.5
)
 
0.4

 
1.2

Net cash provided by operating activities
 
$
434.1

 
$
476.2

 
$
873.8

 
 
 
 
 
 
 
Cash Flows from Investing Activities
 
 
 
 
 
 
Additions to drilling units
 
(23.4
)
 
(66.7
)
 
(13.1
)
Proceeds from sale of assets
 
—

 
16.2

 
—

Payment received from loans granted to related parties
 
—

 
39.4

 
103.6

Insurance refund
 
—

 
—

 
7.1

Net cash (used in) / provided by investing activities
 
$
(23.4
)
 
$
(11.1
)
 
$
97.6




A - 6
Table of Contents

SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31, 2018, 2017 and 2016
(In US$ millions)
 
 
 
2018
 
2017
 
2016
Cash Flows from Financing Activities
 
 
 
 
 
 
Repayments of long term debt
 
(296.4
)
 
(215.0
)
 
(105.3
)
Debt fees paid
 
—

 
(3.8
)
 
(0.3
)
Repayments of related party debt
 
(24.7
)
 
(66.0
)
 
(249.5
)
Contingent consideration paid
 
(34.0
)
 
(40.0
)
 
(59.7
)
Cash distributions
 
(55.4
)
 
(60.1
)
 
(107.3
)
Repayment of shareholder loan
 
(6.2
)
 
—

 
—

Net cash (used in) / provided by financing activities
 
$
(416.7
)
 
$
(384.9
)
 
$
(522.1
)
 
 
 
 
 
 
 
Effect of exchange rate changes on cash
 
(1.0
)
 
0.8

 
(0.7
)
 
 
 
 
 
 
 
Net (decrease) / increase in cash and cash equivalents
 
(7.0
)
 
81.0

 
448.6

Cash and cash equivalents at beginning of the year
 
848.6

 
767.6

 
319.0

Cash and cash equivalents at the end of year
 
$
841.6

 
$
848.6

 
$
767.6

 
 
 
 
 
 
 
Supplementary disclosure of cash flow information
 
 
 
 
 
 
Interest and other financial items paid
 
$
261.3

 
$
200.3

 
$
196.4

Taxes paid
 
24.9

 
42.9

 
49.0

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


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SEADRILL PARTNERS LLC
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’
CAPITAL
for the years ended December 31, 2018, 2017 and 2016
(In US$ millions)
 
 
Members’ Capital
 
 
 
 
 
 
 
 
Common
Units
 
Subordinated
Units
 
Total Before
Non-
Controlling
interest
 
Non-
controlling
Interest
 
Total 
Equity
Consolidated balance at December 31, 2015
 
$
945.5

 
$
18.8

 
$
964.3

 
$
1,133.1

 
$
2,097.4

Net income
 
230.4

 
50.6

 
281.0

 
264.7

 
545.7

Cash distributions
 
(52.7
)
 
—

 
(52.7
)
 
(54.6
)
 
(107.3
)
Consolidated balance at December 31, 2016
 
$
1,123.2

 
$
69.4

 
$
1,192.6

 
$
1,343.2

 
$
2,535.8

Net income
 
115.8

 
25.4

 
141.2

 
94.1

 
235.3

Cash distributions
 
(30.1
)
 
—

 
(30.1
)
 
(30.0
)
 
(60.1
)
Other distributions
 
—

 
—

 
—

 
(9.2
)
 
(9.2
)
Consolidated balance at December 31, 2017
 
$
1,208.9

 
$
94.8

 
$
1,303.7

 
$
1,398.1

 
$
2,701.8

Net income
 
46.0

 
10.1

 
56.1

 
17.9

 
74.0

Cash distributions
 
(30.1
)
 
—

 
(30.1
)
 
(25.3
)
 
(55.4
)
Repayment of shareholder loan
 
—

 
—

 
—

 
(6.2
)
 
(6.2
)
Consolidated balance at December 31, 2018
 
$
1,224.8

 
$
104.9

 
$
1,329.7

 
$
1,384.5

 
$
2,714.2

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


A - 8
Table of Contents

SEADRILL PARTNERS LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - General information
Background
On June 28, 2012, Seadrill Limited ("Seadrill") formed Seadrill Partners LLC (the "Company" or "we") under the laws of the Republic of the Marshall Islands. On October 24, 2012, we completed initial public offerings ("IPO") and listed our common units on the New York Stock Exchange under the symbol "SDLP". In connection with the IPO we acquired:
(i) a 51% limited liability company interest in Seadrill Capricorn Holdings LLC. Seadrill Capricorn Holdings LLC owned 100% of the entities that own and operate the West Capricorn , and
(ii) a 30% limited partner interest in Seadrill Operating LP, as well as the non-economic general partner interest in Seadrill Operating LP through our 100% ownership of its general partner, Seadrill Operating GP LLC.
Seadrill Capricorn Holdings LLC owned 100% of the entities that own and operate the West Capricorn . Seadrill Operating LP owned: (i) 100% interest in the entities that own the West Aquarius and the West Vencedor and (ii) approximately 56% interest in the entity that owns and operates the West Capella .
In connection with the IPO we issued to Seadrill Member LLC, a wholly owned subsidiary of Seadrill, the Seadrill Member interest, which is a non-economic limited liability company interest in the Company, and all of the Company's incentive distribution rights, which entitle the Seadrill Member to increasing percentages of the cash the Company can distribute in excess of $0.4456 per unit, per quarter.
Subsequent to the IPO (i) our wholly-owned subsidiary, Seadrill Partners Operating LLC, acquired from Seadrill two entities that own the T-15 and T-16 , (ii) Seadrill Capricorn Holdings LLC acquired from Seadrill two entities that own the West Auriga and West Vela , (iii) Seadrill Operating LP acquired from Seadrill the entity that owns the West Polaris , (iv) Seadrill Capricorn Holdings LLC acquired the West Sirius and Seadrill Operating LP acquired the West Leo ; and (v) we acquired from Seadrill an additional 28% limited partner interest in Seadrill Operating LP.  As a result of the acquisition, the Company's limited partner interest in Seadrill Operating LP increased from 30% to 58%.
As of December 31, 2018 and 2017, Seadrill owned 34.9% of the Company's common units and all of its subordinated units (which together represent 46.6% of the outstanding limited liability company interests) as well as Seadrill Member LLC, which owns a non-economic interest in the Company and all of its incentive distribution rights.
As of January 2, 2014, the date of the Company's first annual general meeting, Seadrill ceased to control the Company as defined under GAAP and, therefore, Seadrill Partners and Seadrill are no longer deemed to be entities under common control.
Basis of presentation
The financial statements are presented in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The amounts are presented in United States dollar (US dollar) rounded to the nearest hundred thousand, unless otherwise stated.
Going concern
In our Form 20-F covering our annual report for the fiscal year ended December 31, 2017, issued on April 12, 2018, we reported that the combination of (i) our operational dependence on Seadrill because of the management, administrative and technical support services provided to us by Seadrill and (ii) uncertainties over Seadrill's ability to continue as a going concern linked to its Chapter 11 Re-organization, gave rise to a substantial doubt over our ability to continue as a going concern for a period of at least twelve months after the date the financial statements were issued.
Seadrill completed its plan of reorganization and emerged from Bankruptcy on July 2, 2018. Therefore, the above uncertainty has been mitigated and there is no longer a substantial doubt over our ability to continue as a going concern for at least the twelve months after the date the financial statements are issued.
Basis of consolidation
The financial statements include the results and financial position of all companies in which we directly or indirectly hold more than 50% of the voting control. We eliminate all intercompany balances and transactions.
We control Seadrill Operating LP and its majority owned subsidiaries as well as Seadrill Capricorn Holdings LLC and its majority owned subsidiaries. We separately present within equity on our Consolidated Balance Sheets the ownership interests attributable to parties with non-controlling interests in our Consolidated subsidiaries, and we separately present net income attributable to such parties in our Consolidated Statements of Operations.

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Note 2 - Accounting policies
The accounting policies set out below have been applied consistently to all periods in these Consolidated Financial Statements, unless otherwise noted.
Use of estimates
Preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Business combinations
We apply the acquisition method of accounting for business combinations. The acquisition method requires the total of the purchase price of acquired businesses and any non-controlling interest recognized to be allocated to the identifiable tangible and intangible assets and liabilities acquired at fair value, with any residual amount being recorded as goodwill as of the acquisition date. Costs associated with the acquisition are expensed as incurred.
Foreign currencies
The majority of our revenues and expenses are denominated in U.S. dollars and therefore the majority of our subsidiaries use U.S. dollars as their functional currency. Our reporting currency is also U.S. dollars. For subsidiaries that maintain their accounts in currencies other than U.S. dollars, we use the current method of translation whereby the Statement of Operations are translated using the average exchange rate for the year and the assets and liabilities are translated using the year-end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in shareholders' equity.
Related parties
Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence. Refer to Note 14 - ''Related party transactions''.
Revenue from contracts with customers
The activities that primarily drive the revenue earned from our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services as a single performance obligation that is (i) satisfied over time and (ii) comprised of a series of distinct time increments.
We recognize consideration for activities that correspond to a distinct time increment within the contract term in the period when the services are performed. We recognize consideration for activities that are (i) not distinct within the context of our contracts and (ii) do not correspond to a distinct time increment, ratably over the estimated contract term.
We determine the total transaction price for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. The amount estimated for variable consideration may be constrained and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, we consider whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. We re-assess these estimates each reporting period as required.
Dayrate Drilling Revenue - Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.
Mobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the expected term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract.
Demobilization Revenue - We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the demobilization of our rigs. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized over the term of the contract. In most of our contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, the amount may vary dependent upon whether or not the rig has additional contracted work following the contract. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.

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Revenues Related to Reimbursable Expenses - We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, at a point in time, as "Reimbursable revenues" in our Consolidated Statements of Operations.
Contract Balances - Accounts receivable is recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Contract asset balances consist primarily of demobilization revenues which have been recognized during the period but are contingent on future demobilization activities. Contract liabilities include payments received for mobilization as well as rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.
Local Taxes - In some countries, the local government or taxing authority may assess taxes on our revenues. Such taxes may include sales taxes, use taxes, value-added taxes, gross receipts taxes and excise taxes. We generally record tax-assessed revenue transactions on a net basis.
Deferred Contract Costs - Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract.
Other revenues
Other revenues consist of related party revenues, external management fees, and early termination fees. Refer to Note 7 - ''Other revenues''.
Related party revenues - Related party revenues relate to onshore support and offshore personnel provided to Seadrill
Early termination fees - Other revenues also include amounts recognized as early termination fees under drilling contracts which have been terminated prior to the contract end date. Contract termination fees are recognized daily as and when any contingencies or uncertainties are resolved. Refer to Note 14 - ''Related party transactions''.
Vessel and rig operating expenses
Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked, and include the remuneration of offshore crews and related costs, rig supplies, insurance costs, expenses for repairs and maintenance and costs for onshore support personnel. We expense such costs as incurred.
Mobilization and demobilization expenses
We incur costs to prepare a drilling unit for a new customer contract and to move the rig to a new contract location. We capitalize the mobilization and preparation costs for a rig's first contract as a part of the rig value and recognize them as depreciation expense over the expected useful life of the rig (i.e. 30 years). For subsequent contracts, we defer these costs over the expected contract term (see deferred contract costs above), unless we don't expect the costs to be recoverable, in which case we expense them as incurred.
We incur costs to transfer a drilling unit to a safe harbor or different geographic area at the end of a contract. We expense such demobilization costs as incurred. We also expense any costs incurred to relocate drilling units that are not under contract.
Repairs, maintenance and periodic surveys
Costs related to periodic overhauls of drilling units are capitalized and amortized over the anticipated period between overhauls, which is generally five years. Related costs are primarily yard costs and the cost of employees directly involved in the work. We include amortization costs for periodic overhauls in depreciation expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and are expensed as incurred.
Income taxes
Seadrill Partners LLC is organized in the Republic of the Marshall Islands and resident in the United Kingdom for taxation purposes. The Company does not conduct business or operate in the Republic of the Marshall Islands, and is not subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a tax resident of the United Kingdom the Company is subject to tax on income earned from sources within the United Kingdom. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate.
Significant judgment is involved in determining the provision for income taxes. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. The Company recognizes tax liabilities based on its assessment of whether its tax positions are more likely than not sustainable, based on the technical merits and considerations of the relevant taxing authorities widely understood administrative practices and precedent.
Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules. Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards. A deferred tax asset is recognized only to the extent that it is more likely than not that future taxable profits will be available against which the asset can be utilized. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted. We have presented

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all deferred tax liabilities and assets, as well as any related valuation allowance, as non-current for all periods presented in this annual report. Refer to Note 6 - ''Taxation''.
Earnings Per Unit ("EPU")
We compute EPU using the two-class method set out in GAAP. We first allocate undistributed earnings for the period to the holders of common units, subordinated units and incentive distribution rights. This allocation is made in accordance with the cash distribution provisions contained in our Operating Agreement. Unallocated earnings may be negative if amounts distributed are higher than total earnings. We allocate such deficits using the same cash distribution model.
We calculate the EPU for each category of units by taking the sum of the distributions to those units plus the allocation of those units undistributed earnings for the period and dividing this total by the weighted average number of units outstanding for the period. We don't have any potentially dilutive instruments and therefore don't present a diluted EPU. Refer to Note 18 - ''Earnings per unit and cash distributions''.
Current and non-current classification
Generally, assets and liabilities (excluding deferred taxes) are classified as current assets and liabilities respectively if their maturity is within one year of the balance sheet date. In addition, we classify any derivatives financial instruments whose fair value is a net liability as current.
Generally, assets and liabilities are classified as non-current assets and liabilities respectively if their maturity is beyond one year of the balance sheet date. In addition, we classify loan fees based on the classification of the associated debt principal and we classify any derivatives financial instruments whose fair value is a net asset as non-current.
Cash and cash equivalents
Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with original maturities of three months or less.
Receivables
Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount less an allowance for doubtful accounts. We establish reserves for doubtful accounts on a case-by-case basis when it is unlikely that required payments of specific amounts will occur. In establishing these reserves, we consider the financial condition of the customer as well as specific circumstances related to the receivable such as customer disputes. Receivable amounts determined as being unrecoverable are written off. Interest income on receivables is recognized as earned. Refer to Note 9 - ''Accounts receivable''.
Drilling units
Rigs, vessels and related equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated residual value is taken to be offset by any decommissioning costs that may be incurred. The estimated economic useful life of our floaters and, jack-up rigs, when new, is 30 years. Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset's value for its remaining useful life are capitalized and depreciated over the remaining life of the asset. Refer to Note 11 - ''Drilling rigs''.
Impairment of long-lived assets
We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We first assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposal. If the undiscounted future net cash flows are less than the carrying value of the asset, we then compare the carrying value of the intangible asset with the discounted future net cash flows, using relevant WACC to determine an impairment loss to be recognized during the period.
Favorable drilling contracts - intangible assets
Favorable drilling contracts are recorded as an intangible asset at fair value on the date of acquisition less accumulated amortization. The amortization is recognized in the Consolidated Statements of Operations under "amortization of favorable contracts". The amounts of these assets are amortized on a straight-line basis over the estimated remaining economic useful life or contractual period.
Derivative Financial Instruments and Hedging Activities
We record derivative financial instruments at fair value. None of our derivative financial instruments have been designated as hedging instruments. Therefore, changes in their fair value are taken to the Consolidated Statements of Operations in each period. Refer to Note 16 - ''Fair value of financial instruments''.
We classify the gain or loss on derivative financial instruments as a separate line item within financial items in the Consolidated Statements of Operations. We classify the asset or liability for derivative financial instruments as an other current asset or liability in our Consolidated Balance Sheets. We offset assets and liabilities for derivatives that are subject to legally enforceable master netting agreements.
Deferred charges
Loan related costs, including debt issuance, arrangement fees and legal expenses, are capitalized and presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, and amortized over the term of the related loan and the amortization is included in interest expense.

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Debt
We have financed a significant proportion of the cost of acquiring our fleet of drilling units through the issue of debt instruments. At the inception of a term debt arrangement, or whenever we make the initial drawdown on a revolving debt arrangement, we will incur a liability for the principal to be repaid. Refer to Note 12 - ''Debt''.
Loss contingencies
We recognize a loss contingency in the Consolidated Balance Sheets where we have a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Refer to Note 17- ''Commitments and contingencies''.
Equity allocation
Earnings attributable to unitholders of Seadrill Partners are allocated to all unitholders on a pro rata basis for the purposes of presentation in the Consolidated Statements of Changes in Members' Capital. Earnings attributable to unitholders for any period are first reduced for any cash distributions for the period to be paid to the holders of the incentive distribution rights.
At the time of the IPO the equity attributable to unitholders was allocated using the hypothetical amounts which would be distributed to the various unitholders on a liquidation of the Company ("hypothetical liquidation method"). This method has also been used to account for issuances of common units by the Company, and the deemed distributions from equity which resulted from acquisitions of drilling units from Seadrill.

Note 3 - Recent accounting standards
We adopted the following accounting standard updates ("ASUs") in the year:
ASU 2014-09 - Revenue from contracts with customers (also 2016-8, 2016-10, 2016-11, 2016-12, 2016-20, 2017-13, 2017-14)
In May 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition. Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services and in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services.

We adopted ASU 2014-09 and its related amendments, or collectively Topic 606, effective January 1, 2018 using the modified retrospective method. Accordingly, we have applied the five-step method outlined in Topic 606 for determining when and how revenue is recognized to all contracts that were not completed as of the date of adoption. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance. For contracts that were modified before the effective date, we have considered the modification guidance within the new standard and determined that the revenue recognized and contract balances recorded prior to adoption for such contracts were not impacted. While Topic 606 requires additional disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, its adoption has not had a material impact on the measurement or recognition of our revenues or on our opening retained earnings at January 1, 2018. Refer to Note 5 - "Revenue from Contracts with Customers" for further information.
ASU 2017-04 Intangibles (Topic 350)- Simplifying the Test for Goodwill Impairment
In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the new guidance, entities will continue to perform Step 1 of the goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. The entity will now recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.

We early adopted ASU 2017-04, effective December 31, 2018. on a prospective basis. Accordingly, we have applied the simplified test for goodwill at December 31, 2018. Prior to adopting ASU 2017-04, we had recorded goodwill of $3.2 million with accumulated impairment losses of nil. As a result of adopting ASU 2017-04, we have recorded a goodwill impairment loss of $3.2 million in 2018.


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Other ASUs
We adopted the following ASUs in the year, none of which had any impact on our Consolidated Financial Statements and related disclosures:
•
ASU 2016-01 Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities
•
ASU 2016-15 Statement of Cash Flows (Topic 230) - Classification of Certain Cash Receipts and Cash Payments
•
ASU 2016-16 Income Taxes - Income taxes intra-entity transfers of assets other than inventory
•
ASU 2016-18 Statement of Cash Flows - Restricted Cash
•
ASU 2017-01 Business Combinations (Topic 805)- Clarifying the Definition of a Business
•
ASU 2018-03 Technical Corrections and Improvements to Financial Instruments-Overall (Subtopic 825-10)
•
ASU 2018-04 Investments-Debt Securities (Topic 320) and Regulated Operations (Topic 980)
•
ASU 2018-05 Income Taxes (Topic 740)
•
ASU 2018-06 Codification Improvements to (Topic 942)
•
ASU 2018-09 Codification Improvements
•
ASU 2018-19 Codification Improvements to (Topic 326)

Recently Issued Accounting Standards
The FASB have issued the following ASUs that we have not yet adopted but which could affect our Consolidated Financial Statements and related disclosures in future periods.
•
ASU 2016-02 Leases (Topic 842) (also 2018-01, 2018-10, 2018-11. 2018-20)
•
ASU 2016-13 Financial Instruments - Credit Losses (Topic 326)
•
ASU 2018-07 Compensation-Stock Compensation (Topic 718)
•
ASU 2018-13 Fair Value Measurement (Topic 820)
•
ASU 2018-14 Compensation-Retirement Benefits-Defined Benefit Plans (Subtopic 715-20)
•
ASU 2018-15 Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40)
•
ASU 2018-16 Derivatives and Hedging (Topic 815)
•
ASU 2018-17 Consolidation (Topic 810)
ASU 2016-02 - Leases (also 2018-01, 2018-10, 2018-11. 2018-20)
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update required an entity to recognize right-of-use assets and lease
liabilities on its balance sheet and disclose key information about leasing arrangements. It also offered specific accounting guidance for a lessee, a lessor and sale and leaseback transactions. Lessees and lessors are required to disclose qualitative and quantitative information about leasing arrangements to enable a user of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal year, using a modified retrospective application.
Effective January 1, 2019, we will adopt Topic 842 using the modified retrospective application through a cumulative-effect adjustment to retained earnings at January 1, 2019. We have elected the following transition practical expedients, which will be applied consistently to all leases that commenced before January 1, 2019:
1.
We will not reassess whether any expired or existing contracts are or contain leases.
2.
We will not reassess the lease classification for any expired or existing leases.
3.
We will not reassess initial direct costs for any existing leases.
4.
We will use hindsight in determining the lease term and in assessing impairment of the right-of-use assets.
We have determined that our drilling contracts contain a lease component, however, we have elected not to separate the drilling contract lease and non-lease components. We have determined that the non-lease component in our drilling contracts is the predominant component. As such, we will continue to account for our drilling contracts under the guidance in Topic 606. We do not expect our pattern of revenue recognition to change significantly compared to current accounting standards.
We have determined that adoption of this standard will result in increased disclosure of our leasing arrangements. We currently expect this guidance to have nil impact our Consolidated Financial Statements and related disclosures when we adopt it.

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ASU 2016-13 - Financial Instruments - Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which revises guidance for the accounting for credit losses on financial instruments within its scope. The new standard introduces an approach, based on expected losses, to estimate credit losses on certain types of financial instruments and modifies the impairment model for available-for-sale debt securities. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted only from January 1, 2019. Entities are required to apply the standard's provisions as a cumulative-effect adjustment to retained earnings as at the beginning of the first reporting period in which the guidance is adopted.
We are in the early stage of evaluating the impact of this standard update. Our customers are international oil companies, national oil companies and large independent oil companies. Our financial assets are primarily held with counter parties with high credit standing and we have historically had a low incidence of bad debt expense. Therefore, we do not currently expect this guidance to significantly affect our Consolidated Financial Statements and related disclosures when we adopt it.
ASU 2018-07 Compensation - Stock Compensation
In June 2018, the FASB issued ASU 2018-07, Stock Compensation (Topic 718): Improvements to non-employee share-based payment accounting, which intended to reduce cost and complexity and to improve financial reporting for share-based payments issued to non-employees. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-13 Fair Value Measurement - Changes to the Disclosure Requirements for Fair Value Measurement
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The update is intended to improve the effectiveness of disclosures in the notes to financial statements by facilitating clear communication of the US GAAP information requirements that are most important to users of an entity's financial statements. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-14 Compensation - Changes to the Disclosure Requirements for Defined Benefit Plans
In August 2018, the FASB issued ASU 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans- General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans. The update is intended to improve the effectiveness of disclosures in the notes to financial statements by facilitating clear communication of the US GAAP information requirements that are most important to users of an entity's financial statements. The guidance will be effective for annual and interim periods beginning after December 15, 2020, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-15 Intangibles
In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force). The update is intended to provide additional guidance on the accounting for costs of implementation activities performed in a cloud computing arrangement that is a service contract. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-16 Derivatives and Hedging
In October 2018, the FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes. The update is intended to permit use of the OIS rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815 in addition to the direct Treasury obligations of the U.S. government, the LIBOR swap rate, the OIS rate based on the Fed Funds Effective Rate, and the Securities Industry and Financial Markets Association Municipal Swap Rate. The guidance will be effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted if an entity has already adopted ASU 2017-12. We are in the process of evaluating the impact of this standard update on our Consolidated Financial Statements and related disclosures.
ASU 2018-17 Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities
In October 2018, the FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities. The update is intended to improve general purpose financial reporting by considering indirect interests held through related parties in common control arrangements on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The guidance will be effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted.
Effective January 1, 2019, we will adopt ASU 2018-17 on a prospective basis and apply the amendments in the update to qualifying new or re-designated hedging relationships entered into on or after January 1, 2019. We do not expect this to have a material impact on our Consolidated Financial Statements and related disclosures.
Other accounting standard updates issued by the FASB
As of February 28, 2019, the FASB have issued several further updates not included above. We do not currently expect any of these updates to affect our Consolidated Financial Statements and related disclosures either on transition or in future periods.

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Note 4 – Segment information
Operating segment
We regard our fleet as one single operating segment. The Chief Operating Decision Maker, which is the Board of Directors, review performance at this level as an aggregated sum of assets, liabilities and activities generating distributable cash to meet minimum quarterly distributions.
A breakdown of our revenues by customer for the years ended December 31, 2018, 2017 and 2016 is as follows: 
 
2018
 
2017
 
2016
BP
68.0
%
 
56.8
%
 
42.0
%
Tullow
19.8
%
 
—
%
 
13.0
%
Chevron
8.5
%
 
7.9
%
 
5.4
%
ExxonMobil
0.3
%
 
22.2
%
 
22.0
%
Hibernia
—
%
 
6.4
%
 
15.1
%
Other
3.4
%
 
6.7
%
 
2.5
%
Total
100.0
%
 
100.0
%
 
100.0
%
Geographic Data
Revenues are attributed to geographical areas based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents the revenues for the years ended December 31, 2018, 2017 and 2016 and fixed assets as of December 31, 2018 and 2017 by geographic area:
Revenues
(In US$ millions)
2018
 
2017
 
2016
United States
$
618.1

 
$
638.0

 
$
672.2

Ghana
205.5

 
—

 
208.1

Thailand
88.7

 
89.2

 
86.3

Canada
85.3

 
87.1

 
241.5

Indonesia
8.9

 
37.3

 
—

Angola
1.3

 
152.5

 
175.9

Equatorial Guinea
0.9

 
48.1

 
—

Nigeria
—

 
39.5

 
185.2

Other
29.5

 
36.7

 
31.1

Total
$
1,038.2

 
$
1,128.4

 
$
1,600.3

Fixed Assets—Drilling Units (1)  
(In US$ millions)
2018
 
2017
United States
$
2,647.1

 
$
2,729.6

Spain
1,050.1

 
1,075.9

Malaysia
640.0

 
—

Canada
439.7

 
460.9

Thailand
228.7

 
234.6

Gabon
—

 
507.4

Indonesia
—

 
162.5

Total
$
5,005.6

 
$
5,170.9

(1)  
The fixed assets referred to in the table above include the eleven drilling units at December 31, 2018 and December 31, 2017. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.



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Note 5 – Revenue from contracts with customers

The following table provides information about receivables, contract assets and contract liabilities from our contracts with customers:
(In US$ millions)
2018
 
2017
Accounts receivable, net
$
150.9

 
$
254.1

Current contract liabilities (deferred revenues) (1)
4.0

 
5.3

Non-current contract liabilities (deferred revenues) (1)
2.4

 
4.1

(1)   Current contract assets and liabilities balances are included in "Other current assets" and "Other current liabilities", respectively in our Consolidated Balance Sheets as of December 31, 2018.

Significant changes in the contract assets and the contract liabilities balances during the year ended December 31, 2018 are as follows:
(In US$ millions)
Net Contract balances
Contract liabilities at December 31, 2017
(9.4
)
Decrease due to amortization of revenue that was included in the beginning contract liability balance
4.6

Increase due to cash received, excluding amounts recognized as revenue
(1.6
)
Contract liabilities at December 31, 2018
(6.4
)

Certain direct and incremental costs that are expected to be recovered, relate directly to a contract, and enhance resources that will be used in satisfying our performance obligations in the future. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Deferred contract revenue during the year ended December 31, 2018 and 2017 are as follows:
(In US$ millions)
Net Deferred Contract costs
Opening deferred contract costs at December 31, 2017
0.3

Decrease due to amortization of costs that were included in the beginning balance
(2.3
)
Increase due to contract costs incurred, excluding amounts recognized as operating expenses
14.6

Closing deferred contract costs at December 31, 2018
12.6


Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling unit additions and depreciated over the estimated useful life of the improvement. Refer to Note 11 - ''Drilling units'' for more information.

Deferred revenue - The deferred revenue balance of $4.0 million reported in "Other current liabilities" at December 31, 2018 is expected to be realized within the next twelve months and $2.4 million reporting in "Other non-current liabilities" is expected to be realized within the following next twelve months. The deferred revenue included above consists primarily of expected mobilization and upgrade revenue for both wholly and partially unsatisfied performance obligations as well as expected variable mobilization and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the entire corresponding performance obligations. The amounts are derived from the specific terms within drilling contracts that contain such provisions, and the expected timing for recognition of such revenue is based on the estimated start date and duration of each respective contract based on information known at December 31, 2018. The actual timing of recognition of such amounts may vary due to factors outside of our control.

Practical expedient - We have applied the disclosure practical expedient in ASC 606-10-50-14A(b) and have not included estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue. The duration of our performance obligations varies by contract.

Impact of Topic 606 on Financial Statement Line Items - Adopting Topic 606 did not have a material effect on the Consolidated Statement of Operations, or Consolidated Statement of Cash Flows in the year ended December 31, 2018 and 2017. Refer to Note 3 - ''Recent accounting standards'' for more information on the recently adopted accounting pronouncements.

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Note 6 – Taxation
Income taxes consist of the following:
(In US$ millions)
2018
 
2017
 
2016
Current tax expense:
 
 
 
 
 
U.K.
$
(0.3
)
 
$
(4.5
)
 
$
(1.6
)
Foreign
86.3

 
40.4

 
110.2

Total current tax expense
86.0

 
35.9

 
108.6

Deferred tax (benefit) / expense:
 
 
 
 
 
U.K.
—

 
—

 
—

Foreign
0.7

 
4.4

 
(22.1
)
Total income tax expense
$
86.7

 
$
40.3

 
$
86.5

Seadrill Partners LLC is tax resident in the U.K. The Company's controlled affiliates operate and earn income in several countries and are subject to the laws of taxation within those countries. Currently some of the Company's controlled affiliates formed in the Marshall Islands along with all those incorporated in the U.K. (none of whom presently own or operate rigs) are resident in the U.K. and are subject to U.K. tax. Subject to changes in the jurisdictions in which the Company's drilling units operate and/or are owned, differences in levels of income and changes in tax laws, the Company's effective income tax rate may vary substantially from one reporting period to another. The Company's effective income tax rate for each of the years ended on December 31, 2018, 2017 and 2016 differs from the U.K. statutory income tax rate as follows:
 
2018
 
2017
 
2016
U.K. statutory income tax rate
19.0
%
 
19.3
 %
 
20.0
 %
Non-U.K. taxes
35.0
%
 
(4.7
)%
 
(6.3
)%
Effective income tax rate
54.0
%
 
14.6
 %
 
13.7
 %
Deferred Income Taxes
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.
The net deferred tax assets consist of the following:
(In US$ millions)
2018
 
2017
Provisions
$
11.0

 
$
0.5

Net operating losses carry forward
64.4

 
33.3

Interest carry forward
16.7

 
—

Other
5.7

 
5.0

Gross deferred tax assets
97.8

 
38.8

Valuation allowance
(90.1
)
 
(28.9
)
Deferred tax asset, net of valuation allowance
$
7.7

 
$
9.9

The net deferred tax liabilities consist of the following:
(In US$ millions)
2018
 
2017
Property, plant and equipment
$
0.1

 
$
0.4

Unremitted earnings of subsidiaries
0.3

 
1.5

Gross deferred tax liabilities
0.4

 
1.9

 
 
 
 
Net deferred tax asset
7.3

 
8.0

As of December 31, 2018, deferred tax assets related to net operating loss ("NOL") carryforwards were $64.4 million, which can be used to offset future taxable income. NOL carryforwards which were generated in various jurisdictions, include $61.1 million which will not expire and $3.3 million that will expire between 2022 and 2023 if not utilized. We establish a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change. Our valuation allowance consists of $62.8 million on NOL carryforward, $16.7 million on interest carryforward, and $10.6 million on provisions.
The Company's increase in NOL and corresponding valuation allowance was primarily due to the increase in uncertain tax positions.

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Uncertain tax positions
As of December 31, 2018, the Company had uncertain tax positions, exclusive of interest and penalties, of $101.6 million (December 31, 2017: $43.7 million) included in "Other non-current liabilities" on the Consolidated Balance Sheets. The changes to the Company's liabilities related to uncertain tax positions were as follows:
(In US$ millions)
2018
 
2017
Balance beginning of year
$
43.7

 
$
40.0

Increases as a result of positions taken in prior years
70.4

 
—

Increases as a result of positions taken during the current year
10.1

 
3.7

Decreases as a result of positions taken in prior years
(22.6
)
 
—

Uncertain tax position
$
101.6

 
$
43.7

Accrued interest and penalties totaling $16.4 million as of December 31, 2018 (December 31, 2017: $8.0 million) was included in "Other non-current liabilities" on the Consolidated Balance Sheets. The associated expense of $8.4 million was recognized in "Income tax expense" in the Consolidated Statements of Operations during the year ended December 31, 2018 (December 31, 2017: $6.2 million and December 31, 2016: $1.8 million).
As of December 31, 2018, we have recognized liabilities for uncertain tax positions including interest and penalties of $118.0 million. In the event that these issues are resolved for amounts less than provided, there would be a favorable impact on the effective tax rate.
The increase in our uncertain tax position was primarily due to US taxes following a recently identified interpretation of the US tax code that appears to be an unintended consequence of the US tax reform. We understand that the US Department of Treasury is aware of this issue and that it could potentially remediated with additional guidance in the future. However, in the meanwhile, the Company is considering its approach for future filings which may result in a mitigation of a portion of the liability that has been recorded.  At this stage, no cash payment is expected as a result of this uncertain tax position.
Tax examinations
The Company is subject to taxation in various jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:
Jurisdiction
Earliest Open Year
United States
2015
Nigeria
2012
Ghana
2013

Note 7 – Other revenues
Other revenues comprise the following items: 
(In US$ millions)
2018
 
2017
 
2016
Termination payments revenue
$
204.9

 
$
95.9

 
$
198.8

Related party other revenues
4.6

 
7.1

 
12.3

Total
$
209.5

 
$
103.0

 
$
211.1

Termination payments earned during the year ended December 31, 2018 relates to the West Leo litigation judgment of which $204.9 million was recognized as revenue during 2018.
Termination payments earned during the years ended December 31, 2017 and December 31, 2016 include the termination fees for West Sirius and West Capella , which were canceled before the end of the contract term.
Related party other revenues primarily relate to the provision of onshore support services and offshore personnel to Seadrill's and Old Seadrill's drilling rigs that were operating in Nigeria during the years ended December 31, 2018, December 31, 2017 and December 31, 2016. Please refer to Note 14 – "Related party transactions" for further detail on related party other revenues.


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Note 8 – Other operating items
Other operating items comprise the following: 
(In US$ millions)
2018
 
2017
 
2016
Loss on impairment of goodwill

$
(3.2
)
 
$
—

 
$
—

Revaluation of contingent consideration
$
—

 
$
89.9

 
$
—

Gain on sale of assets
—

 
0.8

 
—

Total
$
(3.2
)
 
$
90.7

 
$
—

During the year ended December 31, 2018, we recognized a loss on impairment of goodwill following early adoption of ASU 2017-04, Intangibles . For further information refer to Note 3 - ''Recent accounting standards''.
There was gain on revaluation of contingent consideration of $89.9 million for the year ended December 31, 2017. This gain resulted from a decrease in the fair value of contingent liabilities to Seadrill relating to the purchase of the West Polaris in 2015. We use estimates of long-term dayrates and re-contracting factors to determine the fair value of these liabilities. These estimates decreased during 2017 as new market information became available. For further information please see Note 14 - "Related party transactions".
Note 9 – Accounts receivable
Accounts receivable are presented net of allowances for customer disputes and bad debts.
We have recorded provisions for disputes with customers totaling $2.2 million as of December 31, 2018 (December 31, 2017: $247.5 million). The offsetting entry for these provisions is to reduce revenue. These provisions primarily relate to disputed amounts billed to BP on West Vela .
The provisions as of December 31, 2017 primarily related to disputed amounts billed to Tullow on the West Leo , which were settled during 2018 and the provisions were reversed.
We do not hold any provisions for bad debts. We did not recognize any bad debt expense in 2018, 2017 or 2016.
Note 10 – Other assets
Other assets include the following:
(In US$ millions)
2018
 
2017
Reimbursable amounts due from customers
$
2.9

 
$
3.6

Mobilization revenue receivables
47.9

 
73.8

Intangible asset - Favorable contracts to be amortized
85.5

 
130.6

Prepaid expenses
12.1

 
8.5

Deferred mobilization costs
12.6

 
0.3

Interest rate swap agreements
9.9

 
—

Other
2.3

 
3.5

Total other assets
$
173.2

 
$
220.3

Other assets are presented in our Consolidated Balance Sheet as follows:
(In US$ millions)
2018
 
2017
Other current assets
110.6

 
86.8

Other non-current assets
62.6

 
133.5

Total other assets
$
173.2

 
$
220.3

Mobilization revenue receivables
Under our contracts for the West Capricorn , West Auriga and West Vela we are paid for mobilization activities over the contract term. We recorded a financial asset equal to the fair value of this future stream of payments when we acquired these drilling units from Seadrill. We expect to collect these amounts over the remaining term of the drilling contracts. We record the unwind of time value of money discount as interest income.
The mobilization receivable for the West Capricorn was collected in full by July 2017, which was the original firm term of the West Capricorn's contract with BP. The mobilization receivable for the West Auriga and West Vela will be collected by October 2020 and November 2020 respectively.

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Favorable contracts
Favorable drilling contracts are recorded as intangible assets at fair value on the date of acquisition less accumulated amortization. The amounts recognized represent the net present value of the existing contracts at the time of acquisition compared to the current market rates at the time of acquisition, discounted at the weighted average cost of capital. The estimated favorable contract values have been recognized and amortized on a straight-line basis over the terms of the contracts, ranging from two to five years.
Favorable contracts to be amortized relate to the favorable contracts acquired with the West Vela and the West Auriga from Seadrill as at December 31, 2018. As at December 31, 2017 the balance related to the contract acquired with the West Polaris was fully amortized when the contract was completed. The gross carrying amounts and accumulated amortization included in 'Other current assets' and 'Other non-current assets' in the Consolidated Balance Sheets were as follows:
 
2018
 
2017
(In US$ millions)
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
 
Gross carrying amount
 
Accumulated amortization
 
Net carrying amount
Intangible assets- Favorable contracts
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of period
$
357.3

 
$
(226.7
)
 
$
130.6

 
$
357.3

 
$
(152.3
)
 
$
205.0

Amortization of favorable contracts
—

 
(45.1
)
 
(45.1
)
 
—

 
(74.4
)
 
(74.4
)
Balance at end of period
$
357.3

 
$
(271.8
)
 
$
85.5

 
$
357.3

 
$
(226.7
)
 
$
130.6

The amortization is recognized in the Consolidated Statements of Operations under "amortization of favorable contracts". The table below shows the amounts relating to favorable contracts that is expected to be amortized over the next five years:
 
Year ended December 31
(In US$ millions)
2019

 
2020

 
2021

 
2022

 
2023

 
Total

Amortization of favorable contracts
$
45.1

 
$
40.4

 
$
—

 
$
—

 
$
—

 
$
85.5


Note 11 – Drilling units  
The below table shows the gross value and net book value of our drilling units at December 31, 2018 and December 31, 2017.
(In US$ millions)
Cost
 
Accumulated depreciation

 
Net Book Value
Opening balance as at January 1, 2017
$
6,494.1

 
$
(1,153.2
)
 
$
5,340.9

Additions
121.6

 
—

 
121.6

Disposals
(16.7
)
 
—

 
(16.7
)
Depreciation
—

 
(274.9
)
 
(274.9
)
Closing balance as at December 31, 2017
6,599.0

 
(1,428.1
)
 
5,170.9

Additions
115.0

 
—

 
115.0

Disposals
—

 
—

 
—

Depreciation
—

 
(280.3
)
 
(280.3
)
Closing balance as at December 31, 2018
6,714.0

 
(1,708.4
)
 
5,005.6

Depreciation and amortization expense related to the drilling units was $280.3 million, $274.9 million and $266.3 million for the years ended December 31, 2018, 2017 and 2016 respectively.
Each of our drilling units has been pledged as collateral under our debt agreements. Please read Note 12 – "Debt" for further details.


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Note 12 – Debt
As of December 31, 2018 and December 31, 2017, we had the following debt amounts outstanding:
 (In US$ millions)
2018
 
2017
External debt agreements
 
 
 
Term Loan B
$
2,686.4

 
$
2,836.9

West Vela Facility
191.3

 
255.3

West Polaris Facility
150.8

 
205.6

Tender Rig Facility

56.2

 
83.3

Sub-total external debt
3,084.7

 
3,381.1

 
 
 
 
Related party debt agreements
 
 
 
   West Vencedor Facility
—

 
24.7

Sub-total related party debt
—

 
24.7

 
 
 
 
Total external and related party debt
$
3,084.7

 
$
3,405.8

Term Loan B (previously the "Amended Senior Secured Credit Facilities")
Our Term Loan B facilities ("TLB") consists of a term loan and a linked $100.0 million revolving credit facility. We initially borrowed $1.8 billion under the term loan on February 21, 2014 and then a further $1.1 billion on June 26, 2014. This loan is subject to a 1% per year ($29.0 million) amortization payment with the balance of the loan then being repayable in February 2021. We had $2,636.4 million outstanding on the term loan at December 31, 2018. We have drawn $50 million under the $100 million revolving credit facility linked to the TLB. The remaining $50 million was available and undrawn at December 31, 2018. The revolving credit facility matured in February 2019 and was repaid.
During the year to December 31, 2018, we paid interest of LIBOR + 6.0% on the term loan and LIBOR + 2.25% on the revolving credit facility. LIBOR is subject to a 1% floor. We also pay a commitment fee of 0.5% on any unused portion of the revolving credit facility. As set out below, we have agreed to a 3.0% increase in margin on the term loan as part of an amendment to the TLB agreed in February 2018.
We have pledged the West Capella , West Aquarius , West Sirius, West Leo, West Capricorn, West Auriga and West Vencedor as collateral vessels under the TLB. The net book value of these drilling units at December 31, 2018 was $3.6 billion. We have also pledged substantially all the assets of our subsidiaries, which own or charter the collateral vessels as well as our investments in those companies.
In the year ended December 31, 2017 the TLB included certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable. This included a covenant over the ratio of TLB debt to the EBITDA of the TLB collateral vessels. Based on our results for the year-ended December 31, 2017 this ratio would have been above the level permitted under the covenant. Therefore, unless cured, we would have violated this covenant when financial statements were delivered on April 30, 2018.
To address this, we agreed a modification to the terms of the TLB in February 2018. Under this amendment our lenders agreed to waive the leverage covenant until maturity. In return the TLB lenders received a 3% increase in margin on the term loan and a conditional prepayment of $120.8 million based on the successful outcome of the litigation with Tullow on the West Leo . Refer to Note 17 - "Commitments and contingencies" for further details. We were required to repay the West Vencedor facility and make the West Vencedor a collateral vessel under the TLB. The amendment also added certain other restrictions on our ability to transfer cash outside of the TLB collateral group. As part of this amendment we also agreed that our quarterly distributions would not exceed 10 cents per common unit unless the Consolidated net leverage ratio is below 4x during 2018 and below 5x thereafter.
West Vela facility (previously the "$1,450 million Senior Secured Credit Facility")
The West Vela facility consists of a term loan with four tranches. We initially incurred the liability to repay $443 million under this term loan when we acquired the West Vela from Seadrill in November 2014. The loan is subject to amortization payments of $40.3 million per year. We made a prepayment of $46.7 million in August 2017 and further prepayments of $11.8 million in February 2018 and $11.9 million in August 2018. The $120.8 million balloon payment is due in October 2020. We had $191.3 million outstanding on this loan at December 31, 2018.
We pay interest on the term loan at LIBOR plus a margin of between 1.20% and 4%, inclusive of guarantee fees, depending on the tranche.
We have pledged the West Vela as a collateral vessel under this facility. The net book value of the West Vela was $660.8 million at December 31, 2018. We have also pledged substantially all the assets of our subsidiaries which own and operate the West Vela , as well as our investments in those companies.
The West Vela facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable.

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West Polaris facility (previously the $420 million West Polaris Facility)
The West Polaris facility consists of a term loan and a linked revolving credit facility. We initially incurred the liability to repay $226 million under this term loan and $100 million under the revolving credit facility when we acquired the West Polaris from Seadrill in June 2015. The loan is subject to amortization payments of $36 million per year. We made a prepayment of $37.4 million in August 2017 and further prepayments of $9.4 million in February 2018 and August 2018. The $93.8 million balloon payment is due in July 2020. We had $150.8 million outstanding on this facility at December 31, 2018.
We pay interest on the term loan and revolving credit facility at LIBOR plus a margin of 3.25%. We also pay a commitment fee of 1.3% on any unused portion of the revolving credit facility.
We have pledged the West Polaris as a collateral vessel under this facility. The net book value of the West Polaris was $525.8 million at December 31, 2018. We have also pledged substantially all the assets of our subsidiaries which own and operate the West Polaris , as well as our investments in those companies.
The West Polaris facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable.
Tender rig facility (previously the $440 million Rig Financing Agreement)
The Tender Rig facility consists of two term loans. We initially borrowed $100.5 million and $93.1 million under intercompany loans from Seadrill when we acquired the T-15 and T-16 in May 2013 and October 2013 respectively. These intercompany loans were back to back with an external debt facility Seadrill had used to finance the construction of the T-15 and T-16 . In August 2017, we amended the terms of these loans so that we held the facility directly with the external lender.
We are required to make amortization payments of $19.8 million per year against this facility. We made a prepayment of $15.8 million in August 2017 when we amended the facility and paid further prepayments of $3.8 million in February 2018 and $3.7 million in August 2018. The $31.2 million balloon payment is due in June 2020. We had $56.2 million outstanding on this loan at December 31, 2018.
We pay interest on these loans at LIBOR plus a margin of 4.25%.
We have pledged the T-15 and T-16 as collateral vessels under this facility. The net book value of the T-15 and T-16 was $228.7 million at December 31, 2018. We have also pledged substantially all the assets of our subsidiaries which own and operate the T-15 and T-16 , as well as our investments in those companies.
The Tender Rig facility includes certain covenants and other provisions that could cause amounts borrowed to become immediately due and payable.
West Vencedor Loan Agreement
The West Vencedor Loan Agreement facility was a term loan due to Seadrill. The outstanding balance of the loan at December 31, 2018 was nil as the facility was repaid during the year. We paid interest on the facility at LIBOR plus a margin of 2.3%.
We previously pledged the West Vencedor as a collateral vessel under this facility. After repaying the facility the West Vencedor was pledged as collateral to the TLB.
Debt repayments by year
The outstanding debt as of December 31, 2018 is repayable as follows: 
(In US$ millions)
2018
2019
$
175.1

2020
331.1

2021
2,578.5

2022
—

2023
—

2024 and thereafter
—

Total external and related party debt
$
3,084.7


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Presentation in Consolidated Balance Sheet
We present external debt net of debt issuance costs. The below tables show how the above balances are presented in the Consolidated Balance Sheet:
 
 
Outstanding debt as of December 31, 2018
(In $ millions)
 
Principal outstanding

Debt Issuance Costs

Total Debt

Current portion of long-term external debt
 
$
175.1

$
(12.2
)
$
162.9

Long-term external debt
 
2,909.6

(13.4
)
2,896.2

Total interest-bearing debt
 
$
3,084.7

$
(25.6
)
$
3,059.1

 
 
Outstanding debt as of December 31, 2017
(In $ millions)
 
Principal outstanding

Debt Issuance Costs

Total Debt

Current portion of long-term external debt
 
$
175.1

$
(12.2
)
$
162.9

Long-term external debt
 
3,206.0

(25.8
)
3,180.2

Total external debt
 
$
3,381.1

$
(38.0
)
$
3,343.1

Current portion of long term related party debt
 
$
24.7

$
—

$
24.7

Total interest-bearing debt
 
$
3,405.8

$
(38.0
)
$
3,367.8


Note 13 – Other liabilities
Other liabilities are comprised of the following: 
(In US$ millions)
2018
 
2017
Uncertain tax position
$
118.0

 
$
51.7

Accrued expenses
33.3

 
35.4

Taxes payable
31.3

 
36.5

Employee and business withheld taxes, social security and vacation payment
8.1

 
8.7

Deferred mobilization/demobilization revenues
6.4

 
9.4

VAT payable
3.6

 
6.5

Interest rate swap agreements
—

 
29.0

Other liabilities
—

 
0.4

Total other liabilities
$
200.7

 
$
177.6

Other liabilities are classified in our Consolidated Balance Sheets as follows:
(In US$ millions)
2018
 
2017
Other current liabilities
80.2

 
121.8

Other non-current liabilities
120.5

 
55.8

Total other liabilities
$
200.7

 
$
177.6



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Note 14 – Related party transactions
The below table provides a summary of revenues and expenses for transactions with Seadrill for the years ended December 31, 2018, 2017 and 2016.
(In US$ millions)
 
2018
 
2017
 
2016
Related party inventory sales (a)
 
$
3.2

 
$
2.2

 
$
1.4

Rig operating costs (b)
 
1.4

 
4.9

 
10.9

Total related party operating revenues

 
$
4.6

 
$
7.1

 
$
12.3

 
 
 
 
 
 
 
Management and technical support fees (c)   (d)
 
$
70.6

 
$
74.5

 
$
62.8

Rig operating costs  (e)
 
0.8

 
22.9

 
24.9

Bareboat charter arrangement (f)
 
—

 
2.8

 
9.5

Related party inventory purchases  (a)
 
0.7

 
1.0

 
2.0

Total related party operating expenses
 
$
72.1

 
$
101.2

 
$
99.2

 
 
 
 
 
 
 
Interest expense recognized on deferred contingent consideration (k)
 
$
(3.1
)
 
$
(4.2
)
 
$
(5.2
)
Related party interest expense (g)
 
(1.4
)
 
(4.7
)
 
(10.1
)
Losses on related party derivatives (h)
 
—

 
(1.3
)
 
(4.1
)
Related party commitment fee (i)
 
—

 
(1.3
)
 
(2.0
)
Total related party financial items
 
$
(4.5
)
 
$
(11.5
)
 
$
(21.4
)
The below table provides a summary of amounts due to or from Seadrill at December 31, 2018 and December 31, 2017.
(In US$ millions)
 
2018
 
2017
Trading balances due from Seadrill and subsidiaries (j)
 
$
6.4

 
$
24.2

Total related party receivables
 
$
6.4

 
$
24.2

(In US$ millions)
 
2018
 
2017
Trading balances due to Seadrill and subsidiaries (j)
 
$
(126.3
)
 
$
(157.0
)
Deferred and contingent consideration to related party - short term portion (k)
 
(37.5
)
 
(41.7
)
Deferred and contingent consideration to related party - long term portion (k)
 
(21.5
)
 
(46.0
)
West Vencedor Loan Agreement with Seadrill (l)
 
—

 
(24.7
)
Total related party payables
 
$
(185.3
)
 
$
(269.4
)
(a) Related party inventory sales and purchases
Revenue and expenses from the sale and purchase of inventories and spare parts from Seadrill.
(b) Rig operating costs charged to Seadrill
Seadrill Partners has charged to Seadrill Limited, through its Nigerian service company, certain services including the provision of onshore and offshore personnel, which was provided for the West Jupiter drilling rig operating in Nigeria. We charged Seadrill on a cost plus mark-up basis for these services. The mark-up charged was approximately 5%. This arrangement ended during 2018.
Service agreements
(c) Management and administrative services agreement
Seadrill provides us with services covering functions including general management, information systems, accounting & finance, human resources, legal and commercial. We are charged for these services on a cost plus mark-up basis. During the year ended December 31, 2018, the mark-up we were charged for these services ranged from 4.85% to 8%. The agreement has an indefinite term but we can terminate it for convenience by providing 90 days written notice.
(d) Operations and technical supervision agreements
In addition, certain subsidiaries of Seadrill Partners are in advisory, technical, and/or administrative services agreements with subsidiaries of Seadrill. The services provided by our subsidiaries are charged at cost plus service fee equal to approximately 5% of costs and expenses incurred in connection with providing these services.

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(e) Rig operating costs charged by Seadrill
Seadrill provided onshore support and crew for the West Polaris during its operations in Angola, which ended in July 2017. We were charged for these services on a cost plus mark-up basis. The mark-up we were charged was approximately 5%. During the year ended December 31, 2017 we also received similar services from Seadrill for the West Vencedor .
(f) Bareboat charter arrangement
Seadrill previously acted as an intermediate charterer for the West Aquarius during its contract with Hibernia. The contract ended on April 19, 2017. Seadrill also acted as an intermediate charterer for the T-15 and T-16 until December 2016.
(g) Interest expense charged by Seadrill
Interest expense charged by Seadrill for our related party loan arrangement. Please read Note 12 – "Debt" for a description of the loan facility.
(h) Loss on related party derivatives
Losses on related party interest rate swaps previously held to mitigate interest rate exposures on the West Vela facility, West Polaris facility and Tender Rig facility. See Note 15 – "Risk management and financial instruments" for a description of these interest rate swaps. These swaps were canceled in September 2017 when Seadrill filed for Chapter 11.
(i) Related party commitment fee
Seadrill previously provided us with a revolving credit facility of $100 million. We were charged an interest rate of LIBOR of 5% for any amounts drawn under the facility and a commitment fee of 2% for any unused portion. The facility was canceled in August 2017 as part of the amendments to our bank financing agreements.
(j) Trading balances
Receivables and payables with Seadrill Partners and its subsidiaries are comprised of management fees, advisory and administrative services, and other items including accrued interest. In addition, certain receivables and payables arise when we pay an invoice on behalf of Seadrill Partners or its subsidiaries and vice versa. Receivables and payables are generally settled quarterly in arrears. Trading balances to Seadrill Partners and its subsidiaries are unsecured and are intended to be settled in the ordinary course of business.
(k) Deferred consideration to related party
We have deferred and contingent consideration liabilities to Seadrill from the acquisition of the West Vela and West Polaris .
On the West Vela we are required to pay to Seadrill $42k per day for mobilization and a further $40k per day adjusted for utilization over the remaining contract term with BP, which runs until November 2020.
On the West Polaris we agreed to pay Seadrill 100% of dayrate earned above $450k per day for the remainder of the contract with ExxonMobil and 50% of the dayrate earned above $450k per day on any subsequent contract until March 2025. We also issued a $50 million note ("Sellers Credit") that is payable in March 2021. Payment in kind interest of 6.5% per year is accreted to the note. If the average dayrate earned by the West Polaris is less than $450k per day during the period March 2018 to March 2021, then the value of the note is reduced by the difference between the actual dayrate earned during the period and the amount that would have been earned if the average dayrate earned had been $450k per day.
The below table sets out the fair value of the liabilities at December 31, 2018 and December 31, 2017.
(In US$ millions)
 
2018
 
2017
West Vela
 
 
 
 
Mobilization due to Seadrill
 
$
31.2

 
$
44.2

Seadrill share of dayrate from BP contract
 
27.0

 
38.6

 
 
58.2

 
82.8

West Polaris
 
 
 
 
Seadrill share of dayrate from ExxonMobil contract ("Earnout 1")
 
—

 
4.2

Seadrill share of dayrate from subsequent contracts ("Earnout 2")
 
0.8

 
0.7

 
 
0.8

 
4.9

 
 
 
 
 
Total
 
$
59.0

 
$
87.7







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These liabilities are presented in our Consolidated Balance Sheets as follows:
(In US$ millions)
 
2018
 
2017
Current portion of deferred and contingent consideration to related party
 
$
37.5

 
$
41.7

Non-current portion of deferred and contingent consideration to related party
 
21.5

 
46.0

Total
 
$
59.0

 
$
87.7

In the year ended December 31, 2017, a $89.9 million gain is included in operating income resulting from a reduction in contingent liabilities related to the purchase of the West Polaris in 2015. Future dayrate estimates and re-contracting assumptions have been used to determine the fair value of these liabilities. These estimates have decreased during the year, resulting in a decrease in the fair value of the liabilities. Included in the fair value recognized in the year ended December 31, 2017 is an out of period gain of $20.9 million. Management has evaluated the impact of this out of period adjustment in 2017 and concluded that this was not material to the financial statements for the year ended December 31, 2017 or to any previously reported financial statements.
(l) West Vencedor Loan Agreement
Please read Note 12 - "Debt" for details of the loan facilities.
Other agreements and transactions with Seadrill
Equity Distribution
During the year ended December 31, 2018 and December 31, 2017, one of our subsidiaries settled certain balances related to a shareholder loan provided by Seadrill. On account of the loan's structure these payments have been treated as equity distributions.
A total cash distribution of $6.2 million has been distributed to Seadrill in the year ended December 31, 2018.
In the year ended December 31, 2017, a total balance of $15.3 million has been distributed to Seadrill, comprised of a $6.1 million cash distribution and a $9.2 million non-cash distribution that was offset against certain trading balances owed to us by Seadrill.
These transactions were presented in the Consolidated Statement of Changes in Members Capital in the year ended December 31, 2018 and December 31, 2017.
Spare parts agreement with Seadrill
During the year ended December 31, 2015, we entered an agreement with Seadrill to store spare parts of the West Sirius rig while it was cold stacked. Seadrill may use the spare parts during the stacking period, but must replace them at its own cost when the West Sirius returns to operations.
Guarantees
Seadrill has provided performance guarantees to certain of our customers on our behalf. These totaled $7 million as at December 31, 2018 (December 31, 2017: $165.4 million).
Indemnifications
Under our omnibus agreement with Seadrill at the time of the IPO (the "Omnibus Agreement") and purchase and sale agreements relating to acquisitions from Seadrill subsequent to the IPO, Seadrill has agreed to indemnify the Company against certain liabilities arising from the operation of the assets contributed or sold to the Company prior to the time they were contributed or sold.

Note 15 – Risk management and financial instruments
We are exposed to various market risks, including interest rate, foreign currency exchange and concentration of credit risks. We may enter into a variety of derivative instruments and contracts to maintain the desired level of exposure arising from these risks.
Interest rate risk management
Our exposure to interest rate risk relates mainly to our floating interest rate debt and balances of surplus funds placed with financial institutions. This exposure is managed through the use of interest rate swaps. Our objective is to obtain the most favorable interest rate borrowings available without increasing its exposure to fluctuating interest rates. Surplus funds are used to repay revolving credit tranches, or placed in accounts and deposits with reputable financial institutions in order to maximize returns, while providing us with flexibility to meet all requirements for working capital and capital investments. The extent to which we utilize interest rate swaps to manage our interest rate risk is determined by our net debt exposure and our views on future interest rates.

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Interest rate swap agreements
As of December 31, 2018, we had interest rate swaps for a combined outstanding principal amount of $2,764.9 million, (December 31, 2017: $2,793.9 million) swapping floating rate for an average fixed rate of 2.49% per annum. The fair value of the interest rate swaps outstanding as of December 31, 2018 was an asset of $9.9 million (December 31, 2017: liability of $29 million). The collateral vessels under our TLB have been pledged as collateral against our interest rate swap liabilities. The interest rate swaps and TLB debt rank pari passu.
We record interest rate swaps on a net basis where netting is as allowed under International Swaps and Derivatives Association, Inc. (" ISDA ") Master Agreements. We classify the asset or liability within other current assets or current liabilities. We have not designated any interest swaps as hedges and accordingly any changes in the fair values of the swap agreements are included in the Consolidated Statement of Operations under "Gain/(loss) on derivative financial instruments".
The total realized and unrealized gain recognized under "Gain/(loss) on derivative financial instruments" in the Consolidated Statement of Operations relating to interest rate swap agreements for 2018 was 24.9 million (2017: loss of $13.9 million, 2016: loss of $18.0 million). Included in the $13.9 million net loss for the year ended December 31, 2016 was an out of period gain of $21.8 million recognized in respect of the Company's own creditworthiness.
Our interest rate swap agreements as of December 31, 2018, were as follows:
Maturity date
Outstanding principal as of December 31, 2018
Receive rate
Pay rate
 
 
(In US$ millions)
 
 
 
February 21, 2021
2,764.9

3-month LIBOR
 2.45% to 2.52%
(1) (2)
Total outstanding principal
$
2,764.9

 
 
 
(1) The outstanding principal of these amortizing swaps falls with each capital repayment of the underlying loans.
(2) The Company has a LIBOR floor of 1% whereby the Company receives 1% when LIBOR is below 1%.
As of December 31, 2018, $319.8 million of our debt was exposed to interest rate fluctuations, compared to $611.9 million as of December 31, 2017. An increase or decrease in short-term interest rates of 100 bps would thus increase or decrease, respectively, our interest expense by approximately $3.2 million on an annual basis as of December 31, 2018, as compared to $6.1 million in 2017.
The credit exposure of interest rate swap agreements 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 ISDA Master 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 us.
Foreign currency risk
We use the US Dollar as the functional currency of all our subsidiaries because the majority of our revenues and expenses are denominated in US Dollars. Therefore, we also use US Dollars as our reporting currency. We do, however, earn revenue and incur expenses in Canadian Dollars due to the operations of the West Aquarius in Canada and as such, there is a risk that currency fluctuations could have an adverse effect on the value of the Company's cash flows. The impact of a 10% appreciation or depreciation in the exchange rate of the Canadian Dollar against the US Dollar would not have a material impact on our results.
Our foreign currency risk arises from:
•
the measurement of monetary assets and liabilities denominated in foreign currencies converted to US Dollars, with the resulting gain or loss recorded as "Foreign exchange gain/(loss)"; and
•
the impact of fluctuations in exchange rates on the reported amounts of the Company's revenues and expenses which are denominated in foreign currencies.
We do not use foreign currency forward contracts or other derivative instruments related to foreign currency exchange risk.
Credit risk
We have financial assets which expose us to credit risk arising from possible default by a counterparty. Our counterparties primarily include our customers, which are international oil companies, national oil companies or large independent companies or financial institutions. We consider these counterparties to be creditworthy and do not expect any significant loss due to credit risk. We don't demand collateral from our counterparties in the normal course of business.
Concentration of Credit Risk
There is a concentration of credit risk with respect to revenue as two of our customers that each represent more than 10% of total revenues. Refer to Note 4 - "Segment Information" for an analysis of our revenue by customer. The market for our services is the offshore oil and gas industry, and our customers consist primarily of major oil and gas companies, independent oil and gas producers and government-owned oil companies. We perform ongoing credit evaluations of our customers and generally do not require collateral from them. Reserves for potential credit losses are maintained when necessary.

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There is a concentration of credit risk with respect to cash and cash equivalents as most of the amounts are deposited with Nordea Bank Finland Plc and Danske Bank A/S. We consider these risks to be remote given the strong credit rating of these banks.
Note 16 – Fair Value Measurement
Fair Values
GAAP emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and should be determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, GAAP establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within levels one and two of the hierarchy) and the reporting entity's own assumptions about market participant assumptions (unobservable inputs classified within level three of the hierarchy).
Level one input utilizes unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Level two inputs are inputs other than quoted prices included in level one that are observable for the asset or liability, either directly or indirectly. Level two inputs may include quoted prices for similar assets and liabilities in active markets, as well as inputs that are observable for the asset or liability, other than quoted prices, such as interest rates, foreign exchange rates and yield curves that are observable at commonly quoted intervals. Level three inputs are unobservable inputs for the asset or liability, which are typically based on an entity's own assumptions, as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability
Fair value of financial assets and liabilities measured at amortized cost
The carrying value and estimated fair value of our financial instruments that are measured at amortized cost as of December 31, 2018 and December 31, 2017 are as follows:
 
2018
 
2017
(In US$ millions)
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Assets
 
 
 
 
 
 
 
Cash and cash equivalents
$
841.6

 
$
841.6

 
$
848.6

 
$
848.6

 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
Term Loan B
2,115.1

 
2,662.7

 
2,249.8

 
2,802.3

Other external debt facilities
383.4

 
396.4

 
514.7

 
540.8

Long-term debt to related party
—

 
—

 
23.8

 
24.7

Level 1
The carrying value of cash and cash equivalents, which are highly liquid, is a reasonable estimate of fair value and categorized at level 1 on the fair value measurement hierarchy.
The loans under the Term Loan B are freely tradable and their fair value has been set equal to the price at which they were traded on December 31, 2018 and December 31, 2017. This has been categorized at level 1 on the fair value measurement hierarchy.
Level 2
Loans under other external debt facilities being the West Vela facility (previously the $1,450 million Senior Secured Credit Facility), West Polaris facility, Tender Rig facility (previously the $440 million Rig Financing Agreement) and the West Vencedor facility are not freely tradable. For the years ended December 31, 2018 and December 31, 2017 the fair value of the current and long-term portion of these debt facilities was derived using the Discounted Cash Flow (DCF) model. A cost of debt of 8.16% (December 31, 2017 8.36%) was used to estimate the present value of the future cash flows. This is categorized at level 2 on the fair value measurement hierarchy.

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Financial instruments measured at fair value on a recurring basis
Other financial instruments that are measured at fair value on a recurring basis:
 
 
Fair value measurements
at reporting date using
 
Total fair value as of December 31, 2018
Quoted Prices
in Active
Markets for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(In US$ millions)
 
(Level 1)
(Level 2)
(Level 3)
Current assets:
 
 
 
 
Derivative instruments - Interest rate swap contracts
$
9.9

—

9.9

—

Total assets
9.9

—

9.9

—

 
 
 
 
 
Current liabilities:
 
 
 
 
Related party deferred and contingent consideration
(59.0
)
—

(59.0
)
—

Total liabilities
$
(59.0
)
—

(59.0
)
—

 
 
Fair value measurements
at reporting date using
 
Total fair value as of December 31, 2017
Quoted Prices
in Active
Markets for
Identical Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(In US$ millions)
 
(Level 1)
(Level 2)
(Level 3)
Current liabilities:
 
 
 
 
Derivative instruments - Interest rate swap contracts
(29.0
)
—

(29.0
)
—

Related party deferred and contingent consideration
(87.7
)
—

(87.7
)
—

Total liabilities
$
(116.7
)
—

(116.7
)
—

The fair values of interest rate swap contracts are calculated using well-established independent valuation techniques, applied to contracted cash flows and expected future LIBOR interest rates, and counterparty non-performance credit risk assumptions as of December 31, 2018 and December 31, 2017. The calculation of the credit risk in the swap values is subject to a number of assumptions including an assumed Credit Default Swap rate based on the Company's traded debt, plus a curve profile and recovery rate.
The fair value of the related party deferred and contingent consideration payable to Seadrill relating to the purchase of the West Vela and the West Polaris are estimated based on discounted future cash flows. These liabilities are considered to be at estimated market rates. These are categorized at level 2 on the fair value measurement hierarchy.
Fair value considerations on one-time transactions
In the year ended December 31, 2018, a $3.2 million loss on impairment of goodwill is included in operating income resulting from early adoption of the new standard 2017-04 ASC 350, which requires comparing the fair value of the goodwill against its carrying value. Under this assessment the goodwill's carrying amount exceeded its fair value and was written off.


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Note 17 – Commitments and contingencies
Legal Proceedings
From time to time the Company is a party, as plaintiff or defendant, to lawsuits in various jurisdictions in the ordinary course of business or in connection with its acquisition or disposal activities. Our best estimate of the outcome of the various disputes has been reflected in these financial statements as of December 31, 2018.
West Leo
We received notification of a force majeure occurrence on October 1, 2016 in respect of the West Leo which was operating for Tullow Ghana Limited ("Tullow") in Ghana. We filed a claim in the English High Court formally disputing the occurrence of force majeure and seeking declaratory relief from the High Court. Tullow subsequently terminated the drilling contract on December 1, 2016 for (a) 60-days claimed force majeure, or (b) in the alternative, frustration of contract, or (c) in the further alternative, for convenience. We did not accept that the contract had been terminated by the occurrence of force majeure under the terms of the drilling contract and/or that the contract had been discharged by frustration.  Accordingly, we amended our claim in the English High Court to reflect this.
On July 3, 2018 the English High Court ruled the case in our favor and we recovered a total of $250.5 million which included amounts claimed on the termination revenue including interest. Claims to recover VAT were not ruled in our favor. Termination revenues have been recognized in "Other revenues" per our Consolidated Statements of Operations. See Note 7 - "Other revenues" for further details.
Patent infringement
In January 2015, a subsidiary of Transocean Ltd. filed suit ("the Suit") against certain of our subsidiaries for patent infringement. The Suit alleged that two of our drilling rigs that operate in the U.S. Gulf of Mexico violated Transocean patents relating to dual-activity. In the same year, we challenged the validity of the patents via the Inter Parties Review process within the U.S. Patent and Trademark Office. The IPR board held in March 2017 that the patents were valid. In May 2017 we appealed to the U.S. Federal Circuit Court of Appeal and in June 2018 the court affirmed the IPR decision.  

In December 2018, Seadrill and Seadrill Partners reached an amicable agreement with Transocean over alleged patent infringement of the Transocean dual activity patent. Under the terms of the settlement, Seadrill and Seadrill Partners have entered into a global license agreement with Transocean for the dual activity drilling method on our rigs covering alleged past infringements and future use.
Other claims or legal proceedings
We are not aware of any other legal proceedings or claims that we expect to have, individually or in the aggregate, a material adverse effect on the Company.
Commitments
We had no material lease commitments or unconditional purchase obligations at December 31, 2018 and 2017.

Note 18 – Earnings per unit and cash distributions
(in US $ millions, except per unit data)
2018
 
2017
 
2016
Net income attributable to:
 
 
 
 
 
Common unitholders
$
56.1

 
$
141.2

 
$
240.7

Subordinated unitholders
—

 
—

 
37.8

Seadrill member interest
—

 
—

 
2.5

Net income attributable to Seadrill Partners LLC owners
$
56.1

 
$
141.2

 
$
281

 
 
 
 
 
 
Weighted average units outstanding (in thousands):
 
 
 
 
 
Common unitholders
75,278

 
75,278

 
75,278

Subordinated unitholders
16,543

 
16,543

 
16,543

 
 
 
 
 
 
Earnings per unit:
 
 
 
 
 
Common unitholders
$
0.75

 
$
1.88

 
$
3.20

Subordinated unitholders
$
—

 
$
—

 
$
2.28

 
 
 
 
 
 
Cash distributions declared and paid in the period per unit (1) (2)
$
0.4000

 
$
0.4000

 
$
0.7000

 
 
 
 
 
 
Subsequent event: Cash distributions declared and paid relating to the period per unit (2) (3) :
$
0.0100

 
$
0.1000

 
$
0.1000


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(1) Refers to the cash distributions declared and paid during the year.
(2) Distributions were declared and paid only with respect to the common units in 2018.
(3) Refers to the cash distribution relating to the period, declared and paid subsequent to the year-end.
Earnings per unit is calculated using the two-class method where undistributed earnings are allocated to the various member interests. The net income attributable to the common and subordinated unitholders and the holders of the incentive distribution rights is calculated as if all net income was distributed according to the terms of the distribution guidelines set forth in the First Amended and Restated Operating Agreement of the Company (the "Operating Agreement"), regardless of whether those earnings could be distributed. The Operating Agreement does not provide for the distribution of net income; rather, it provides for the distribution of available cash, which is a contractually defined term that generally means all cash on hand at the end of the quarter after establishment of cash reserves determined by the Company's board of directors to provide for the proper conduct of the Company's business including reserves for maintenance and replacement capital expenditure and anticipated credit needs. Therefore, the earnings per unit is not indicative of potential cash distributions that may be made based on historic or future earnings. Unlike available cash, net income is affected by non-cash items, such as depreciation and amortization, unrealized gains or losses on non-designated derivative instruments and foreign currency translation gains (losses).
Under the Operating Agreement, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.3875 per unit per quarter, plus any arrearages in the payment of minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.
Distributions of available cash from operating surplus are to be made in the following manner for any quarter during the subordination period:
•
First, to the common unitholders, pro-rata, until the Company distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
•
Second, to the common unitholders, pro-rata, until the Company distributes for each outstanding common an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for prior quarters during the subordination period; and
•
Third, to the subordinated units, pro-rata, the Company distributes for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter.
In addition, the Seadrill Member currently holds all of the incentive distribution rights in the Company. Incentive distribution rights represent the right to receive an increasing percentage of the quarterly distributions of cash available from operating surplus after the minimum quarterly distribution and target distribution levels have been achieved.
If for any quarter during the subordination period:
•
The Company has distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
•
The Company has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.
then, the Company will distribute any additional available cash from operating surplus for that quarter among the unitholders and the holders of the incentive distributions rights in the following manner:
•
first, 100.0% to all unitholders, until each unitholder receives a total of $0.4456 per unit for that quarter (the "first target distribution");
•
second, 85% to all unitholders, pro rata, and 15.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.4844 per unit for that quarter (the "second target distribution");
•
third, 75.0% to all unitholders, pro rata, and 25.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.5813 per unit for that quarter (the "third target distribution"); and
•
thereafter, 50.0% to all unitholders, and 50.0% to the holders of the incentive distribution rights, pro rata.
The percentage interests set forth above assumes that the Company does not issue additional classes of equity securities.
The subordination period will extend until the second business day following the distribution of available cash from operating surplus in respect of any quarter, ending on or after September 30, 2017, that each of the following tests are met:
•
distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•
the "adjusted operating surplus" (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted weighted average basis during those periods; and
•
there are no outstanding arrearages in payment of the minimum quarterly distribution on the common units.

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In addition, at any time on or after September 30, 2017, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units and subject to approval by the conflicts committee, the holder or holders of a majority of the subordinated units will have the option to convert each subordinated unit into a number of common units at a ratio that may be less than one-to-one on a basis equal to the percentage of available cash from operating surplus paid out over the previous four-quarter period in relation to the total amount of distributions required to pay the minimum quarterly distribution in full over the previous four quarters.
Commencing with the distributions made in February 2016, in respect of the fourth quarter of 2015, no distributions have been made to the holders of the subordinated units and distributions to the common units have been below the minimum quarterly distribution. Arrearages in the payment of the minimum quarterly distribution on the common units must be settled before any distributions of available cash from operating surplus may be made in the future on the subordinated units.
No distributions were paid to the incentive distribution rights holders for the years ending December 31, 2018 , 2017 and 2016 .

Note 19 - Supplementary cash flow information
The table below summarizes the non-cash investing and financing activities relating to the periods presented:
(In US$ millions)
2018
 
2017
 
2016
Other distributions (1)
—

 
9.2

 
—

(1) Non-cash distribution, refer to Note 14 – "Related party transactions" for further information.

Note 20 – Subsequent events
Distribution declared
On January 22, 2019, we declared a distribution for the fourth quarter of 2018 of $0.0100 per common unit, which was paid on February 14, 2019.
On February 21, 2019, we fully repaid $50 million outstanding on the revolving credit facility linked to the Term Loan B.


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SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.
 
 
 
SEADRILL PARTNERS LLC
(Registrant)
 
 
 
 
Date: March 28, 2019
 
 
 
 
 
 
 
 
 
By:
/s/ Mark Morris
 
 
Name:
Mark Morris
 
 
Title:
Chief Executive Officer of Seadrill Partners LLC
(Principal Executive Officer of Seadrill Partners LLC)


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