20-F 1 nadl20f2017.htm 20-F Document


 
 
 
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________
FORM 20-F
(Mark One)
 
 
o
 
REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
OR
þ
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017
 
 
OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________________ to _________________
 
 
OR
o
 
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: 001-36277
_____________________
NORTH ATLANTIC DRILLING LTD.
(Exact name of Registrant as specified in its charter)

Bermuda
(Jurisdiction of incorporation or organization)

Par-la-Villa Place, 4th Floor, 14 Par-la-Villa Road, Hamilton, HM08, Bermuda
(Address of principal executive offices)

Georgina Sousa, +1 (441)295-9500, gsousa@front.bm
Par-la-Villa Place, 4th Floor, 14 Par-la-Villa Road, Hamilton, HM08, Bermuda
(Name, telephone, Email and address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each Class
None
 
Name of each exchange on which registered
Not Applicable
Securities registered or to be registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.10 per share
(Title of Class)
_____________________
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, 2017, there were 24,114,232 shares of common stock, 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
 o
 
No
þ
 

If this report is an annual 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
 o
 
No
þ
 

Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

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.
 
Yes
þ
 
No
 o
 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).
 
Yes
þ
 
No
 o
 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See the definitions of “large accelerated filer” and “accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o
 
Accelerated filer o
 
 
Non-accelerated filer þ
 
Emerging growth company o
 

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. o

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
þ
 
U.S. GAAP
 
 o
 
International Financial Reporting Standards as issued by the international Accounting Standards Board
 
 o
 
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:
 
 o
Item 17
 
 o
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
o
 
No
þ
 





TABLE OF CONTENTS
 
 
 
Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
PART I
 
ITEM 1.
IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
 
ITEM 2.
OFFER STATISTICS AND EXPECTED TIMETABLE
 
ITEM 3.
KEY INFORMATION
 
ITEM 4.
INFORMATION ON THE COMPANY
 
ITEM 4A.
UNRESOLVED STAFF COMMENTS
 
ITEM 5.
OPERATING AND FINANCIAL REVIEW AND PROSPECTS
 
ITEM 6.
DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
 
ITEM 7.
MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
 
ITEM 8.
FINANCIAL INFORMATION
 
ITEM 9.
OFFER AND THE LISTING
 
ITEM 10.
ADDITIONAL INFORMATION
 
ITEM 11.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
ITEM 12.
DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
PART II
 
ITEM 13.
DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
 
ITEM 14.
MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
 
ITEM 15.
CONTROLS AND PROCEDURES
 
ITEM 16A
AUDIT COMMITTEE FINANCIAL EXPERT
 
ITEM 16B.
CODE OF ETHICS
 
ITEM 16C
PRINCIPAL ACCOUNTING FEES AND SERVICES
 
ITEM 16D
EXEMPTIONS FROM LISTING STANDARDS FOR AUDIT COMMITTEES
 
ITEM 16E
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASES    
 
ITEM 16F
CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT
 
ITEM 16G
CORPORATE GOVERNANCE
 
ITEM 16H
MINE SAFETY DISCLOSURE
PART III
 
ITEM 17.
FINANCIAL STATEMENTS
 
ITEM 18.
FINANCIAL STATEMENTS
 
ITEM 19.
EXHIBITS



3




CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

We desire to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, or the PSLRA, and are including this cautionary statement in connection therewith. The PSLRA provides safe harbor protections for forward-looking statements in order 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 in this annual report, important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include:

the impact of active negotiations and contingency planning efforts with respect to a comprehensive restructuring of our debt, the outcome of which is uncertain and involve Chapter 11 proceedings with the U.S. Bankruptcy Court for Southern District of Texas, Victoria division;
our ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;
our ability to maintain and obtain adequate financing to support our business plans post-emergence from Chapter 11;
the length of time that we will operate under Chapter 11 protection;
risks associated with third party motions in the Chapter 11 proceedings that may interfere with the solicitation and ability to confirm and consummate a plan of reorganization;
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 comply with certain covenants in our debt financing agreements;
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 jurisdictions;
limitations on insurance coverage, such as war risk coverage, in certain areas;
our 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;
recruitment and retention of personnel;

4




regulatory or financial requirements to comply with foreign bureaucratic actions, including potential limitations on drilling activity, changing taxation policies and other forms of government regulation and economic conditions that are beyond our control;
the level of expected capital expenditures, our expected financing of such capital expenditures and the timing and cost of completion of capital projects;
fluctuations in interest rates or exchange rates and currency devaluations relating to foreign or U.S. monetary policy;
effects of remediation efforts to address the material weakness discussed in "Item 15. Controls and Procedures "
tax matters, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Bermuda, Norway, the United Kingdom and Russia;
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 Securities and Exchange Commission, or the Commission.

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




5




PART I
ITEM 1.    IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2.    OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3.    KEY INFORMATION

Throughout this annual report, unless the context otherwise requires, references to “NADL,” the “Company,” “we,” “us,” “Group,” “our” and words of similar import refer to North Atlantic Drilling Limited, its subsidiaries and its other consolidated entities.

References in this annual report to “Seadrill” refer to Seadrill Limited, our parent and majority shareholder. We consolidate certain subsidiaries of Ship Finance International Limited, or “Ship Finance.”

References in this annual report to “Statoil,” “ConocoPhillips,” “Shell,” “Total,” “ExxonMobil,” “KMNG,” “Jurong”, "Nexen" and “Rosneft” refer to Statoil ASA, Conoco Phillips Company, Royal Dutch Shell, Total S.A., Exxon Mobil Corporation, Karmorneftegaz SARL, Jurong Shipyard Pte Ltd., Nexen Petroleum UK Ltd and Rosneft Oil Company, respectively, and certain of each of their subsidiaries that are our current or former customers.

Unless otherwise indicated, all references to “US$” and “$” in this annual report are to, and amounts are presented in, U.S. dollars and all references to “NOK” are to Norwegian kroner. References in this annual report to “ft” means “feet.”

References in this annual report to our common shares are adjusted to reflect the consolidation of our common shares through a one-for-ten reverse stock split, which became effective on December 31, 2015.

A.    Selected Financial Data
Our selected statement of operations and other financial data with respect to the fiscal years ended December 31, 2017, 2016 and 2015 and our selected balance sheet data with respect to the fiscal years ended December 31, 2017 and 2016 have been derived from our consolidated financial statements included in Item 18 of this annual report, which have been prepared in accordance with accounting principles generally accepted in the United States, or U.S. GAAP.

Our selected statement of operations and other financial data for the fiscal years ended December 31, 2014 and 2013 and our selected balance sheet data with respect to the fiscal years ended December 31, 2015, 2014 and 2013 have been derived from our consolidated financial statements which are not included herein.

The following financial data should be read in conjunction with “Item 5. Operating and Financial Review and Prospects” and our consolidated financial statements and the notes thereto, which are included herein. Our 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 our statement regarding going concern as described in "Note 1 - General information".

(in millions of U.S. dollars except
common share and per share data)
 
Year ended December 31,
2017
2016
2015
2014
2013
 
 
 
 
 
 
Statement of Operations Data
 
 
 
 
 
Total operating revenues
257.5

534.7

747.7

1,263.7

1,324.3

Net operating (loss)/income
(133.0
)
90.8

97.5

(116.4
)
360.6

Net (loss)/income
(286.4
)
(52.4
)
(56.8
)
(304.0
)
235.6

(Loss)/Earnings per share, basic and diluted (1)
(12.35
)
(2.77
)
(3.03
)
(13.18
)
10.35

Dividends declared per share (1)



4.80

9.05

Weighted average common shares outstanding, in millions
24.1

24.1

24.1

24.0

22.8



6




(in millions of U.S. dollars except
common share and per share data)
 
Year ended December 31,
2017
2016
2015
2014
2013
 
 
 
 
 
 
Balance Sheet Data (at end of period):
 
 
 

 

 
Cash and cash equivalents
$
29.5

$
68.7

$
150.9

$
116.2

$
84.1

Drilling units
2,325.5

2,528.8

2,738.0

2,923.5

2,377.8

Newbuildings



172.6

312.9

Goodwill




480.6

Total assets (2)
2,621.2

2,918.4

3,255.1

3,651.0

3,679.0

Interest bearing debt (including current portion) (3)
2,119.2

2,280.2

2,434.9

2,706.8

2,427.6

Total equity
91.3

386.0

418.7

468.0

857.5

Common shares outstanding
2.4

2.4

2.4

1,205.7

1,138.1

 
 
 
 
 
 
Other Financial Data:
 
 
 

 

 
Net cash (used in)/provided by continuing operations
(9.0
)
128.7

339.9

199.1

425.2

Net cash (used in)/ provided by investing activities from continuing
operations
(0.8
)
1.3

(39.0
)
(447.5
)
(103.9
)
Net cash (used in)/provided by financing activities from continuing operations
(29.2
)
(218.2
)
(264.1
)
271.2

(334.0
)
____________________
(1)
As a result of the 1-for-10 reverse stock split and related reduction in authorized capital in 2015, the earnings per share and dividends declared per share have been retrospectively adjusted by a factor of 10 for the years ended December 31, 2014 and 2013. Please see "Note 17–Common share capital" to our consolidated financial statements included herein for more information.
(2)
Historically, we presented balances due to or from Ship Finance International Limited (NYSE: "SFL"), or Ship Finance, on a gross basis. Beginning on June 30, 2015 we elected to present this on a net basis, due to the fact that the right of offset is established in the long-term loan agreements, and the balances are intended to be settled on a net basis, providing a more appropriate description of our related party net debt position. Accordingly, we have represented from amounts due from related parties (current assets) to offset against long-term debt due to related parties (non-current liabilities). The total amounts represented were nil as at December 31, 2015, $14.3 million as at December 31, 2014 and $0 million as at December 31, 2013.
(3)
Includes $1,688.9 million which has been reclassified into liabilities subject to compromise. Please see "Note 3 - Chapter 11 proceedings" to our consolidated financial statements included herein for more information.

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, or intended to engage, in offshore contract drilling for the oil and gas industry in harsh environments in the territorial waters and outer continental shelf jurisdiction of Norway, the United Kingdom, Ireland, Denmark, the Netherlands, the east coast of Greenland, Russia (west of the island of Diksonskiy) and all countries within the Baltic Sea and the Gulf of Bothnia, which we refer to as the "North Atlantic Region," including ultra-deepwater environments. The following risks relate principally to 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, 2017. 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.

Risk Relating to the Bankruptcy Proceedings
 
We, along with Seadrill and a substantial number of its consolidated subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code, and we are subject to the risks and uncertainties associated with such bankruptcy proceedings.

On September 12, 2017, we, together with Seadrill and certain of Seadrill’s consolidated subsidiaries (collectively, the Company Parties), 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). Ship Finance International Limited and three of its subsidiaries ("SFL"), which charter three

7




drilling units to the Company Parties, also executed the RSA. In connection with the RSA, the Company Parties entered into an investment agreement ("the Investment Agreement") under which Hemen Investments Limited, an affiliate of Seadrill’s largest shareholder Hemen Holding Ltd. and a consortium of additional investors, including the bondholder parties to the RSA (collectively, the "Commitment Parties"), committed to provide up to $1.08 billion in new cash, subject to certain terms and conditions.

On September 12, 2017, to implement the transactions contemplated by the RSA and Investment Agreement, the Company Parties (collectively, the "Debtors") commenced prearranged reorganization proceedings (the "Chapter 11 proceedings") under Chapter 11 of Title 11 of the United States Code (the "Bankruptcy Code") in the Southern District of Texas (the "Bankruptcy Court").

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 ship yards with which the Debtors had a contractual relationship to build new rigs. On February 26, 2018, the Debtors announced a global settlement with the Ad Hoc Group, the official committee of unsecured creditors (the “Committee”) and other major creditors in their Chapter 11 cases, including Samsung Heavy Industries Co., Ltd. and Daewoo Shipbuilding & Marine Engineering Co., Ltd., 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 the 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 of Seadrill, NADL and Sevan under the plan of reorganization, 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 of reorganization.

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 (the “Plan”). By the voting deadline of April 5, 2018, the Plan received approval from every single class of creditors and holders of interests entitled to vote, exceeding the required thresholds for acceptance of the Plan.

We are subject to a number of risks and uncertainties associated with the Chapter 11 proceedings, which may lead to potential adverse effects on our liquidity, results of operations or business prospects. We cannot assure you of the outcome of the Chapter 11 proceedings. Risks associated with the Chapter 11 proceedings include the following:
our ability to continue as a going concern;
our ability to obtain Bankruptcy Court approval with respect to motions in the Chapter 11 proceedings and the outcomes of Bankruptcy Court rulings of the proceedings in general;
our ability to comply with and to operate under the cash collateral order and any cash management orders entered by the Bankruptcy Court;
the length of time we will operate under the Chapter 11 proceedings and our ability to successfully emerge, including with respect to obtaining any necessary regulatory approvals and to complete certain corporate reorganizations;
our ability to negotiate, confirm and consummate a plan of reorganization with respect to the Chapter 11 proceedings;
risks associated with third party motions, proceedings and litigation in the Chapter 11 proceedings, including by third parties that are not party to the RSA or the Investment Agreement, which may interfere with our plan of reorganization;
the ability to maintain sufficient liquidity throughout the Chapter 11 proceedings;
increased costs related to the bankruptcy filing, operating in Chapter 11 and other litigation;
our ability to manage contracts that are critical to our operation, and to obtain and maintain appropriate credit and other terms with customers, suppliers and service providers;
our ability to attract, retain and motivate key employees;
our ability to fund and execute our business plan;
the disposition or resolution of all pre-petition claims against us; and
our ability to maintain existing customers and vendor relationships and expand sales to new customers.

The Chapter 11 proceedings limit the flexibility of our management team in running the Debtors’ business.
While we operate our business as debtors-in-possession under supervision by the Bankruptcy Court, we are required to obtain the approval of the Bankruptcy Court with respect to our business, and in some cases, the Consenting Stakeholders under the terms of the RSA and the Commitment Parties under the terms of the Investment Agreement, prior to engaging in certain activities or transactions described therein, including activities and transactions that are outside the ordinary course of business. Bankruptcy Court approval of non-ordinary course activities entails preparation and filing of appropriate motions with the Bankruptcy Court, negotiation with various parties-in-interest, including any statutory committees appointed in our Chapter 11 proceedings, and one or more hearings. Such committees and parties-in-interest may be heard at any Bankruptcy Court hearing and may raise objections with respect to these motions. This process could delay major transactions and limit our ability to respond quickly to opportunities and events in the marketplace. Furthermore, in the event the Bankruptcy Court does not approve a proposed activity or transaction, we could be prevented from engaging in activities and transactions that we believe are beneficial to us.

Additionally, the terms of the cash collateral order entered by the Bankruptcy Court will limit our ability to undertake certain business initiatives. These limitations may include, among other things, our ability to:
sell assets outside the normal course of business;
consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

8




grant liens;
incur debt for borrowed money outside the ordinary course of business;
prepay prepetition obligations; and
finance our operations, investments or other capital needs or to engage in other business activities that would be in our interests.

The Chapter 11 proceedings may disrupt our business and may materially and adversely affect our operations.
We have attempted to minimize the adverse effect of the Chapter 11 proceedings on our relationships with our employees, suppliers, customers and other parties. Nonetheless, our relationships with our customers, suppliers and employees may be adversely impacted by negative publicity or otherwise and our operations could be materially and adversely affected. In addition, the Chapter 11 proceedings could negatively affect our ability to attract new employees and retain existing high performing employees or executives, which could materially and adversely affect our operations.

The Investment Agreement is subject to significant conditions and milestones which may be difficult for us to satisfy.
We, and the other Company Parties entered into the Investment Agreement with the Commitment Parties, pursuant to which, among other things, the Commitment Parties have committed to provide up to $1.08 billion in new cash. The obligations of the Commitment Parties under the Investment Agreement are subject to certain material conditions and milestones, including confirmation of the Plan, and the occurrence of the effective date of the Plan prior to an outside date. Our ability to timely complete such milestones is subject to risks and uncertainties that may be beyond our control. If the Commitment Parties are not required to provide the new cash under the Investment Agreement, the Plan may not be confirmed or may not become effective, in which case we would need to develop an alternative plan of reorganization.

The RSA is subject to significant conditions which may be difficult for us to satisfy.
We, and the other Company Parties entered into the RSA pursuant to which, among other things, we agreed to file the Plan. While the Consenting Stakeholders who are entitled to vote have agreed to vote in favor of the Plan when properly solicited to do so, there are certain material conditions that must be satisfied, including our timely filing of the Plan and taking all steps reasonably necessary and desirable to consummate the restructuring transactions in accordance with the RSA, and certain events under which the RSA may be terminated, including upon certain terminations of the Investment Agreement or upon entry of an order of the Bankruptcy Court denying the confirmation of the Plan. Our ability to satisfy such conditions or avoid such termination events is subject to risks and uncertainties that may be beyond our control. If the Consenting Stakeholders who are entitled to vote are not required to vote for the Plan, the Plan may not be confirmed, in which case we would need to develop an alternative plan of reorganization.

We may not be able to obtain Bankruptcy Court confirmation of the Plan or may have to modify the terms of the Plan.
Although we have received approval of the Plan by each class of holders of claims and interests entitled to vote (a "Voting Class"), the Bankruptcy Court may, as a court of equity, exercise substantial discretion and could choose not to confirm the Plan. Bankruptcy Code Section 1129 requires, among other things, a showing that confirmation of the Plan will not be followed by liquidation or the need for further financial reorganization for the Debtors, and that the value of distributions to dissenting holders of claims and interests will not be less than the value such holders would receive if the Debtors liquidated under Chapter 7 of the Bankruptcy Code. Although we believe that the Plan will satisfy such tests, there can be no assurance that the Bankruptcy Court will reach the same conclusion.

Confirmation of the Plan will also be subject to certain conditions. These conditions may not be met and there can be no assurance that we and the Consenting Stakeholders will agree to modify or waive such conditions as required under the RSA. Further, changed circumstances may necessitate changes to the Plan. Any such modifications could result in less favorable treatment of any non-accepting class, as well as any classes junior to such non-accepting class, than the treatment that will currently be provided in the Plan in accordance with the RSA. Such less favorable treatment could include a distribution of property (including new securities) to the class affected by the modification of a lesser value than what the RSA contemplates
will be provided in the Plan or no distribution of property whatsoever under the Plan. Changes to the Plan may also delay the confirmation of the Plan and the Debtors’ emergence from bankruptcy.  

The Plan may not become effective.
In the event the Plan is confirmed by the Bankruptcy Court, it may not become effective because it is subject to the satisfaction of certain conditions precedent (some of which are beyond our control). There can be no assurance that such conditions will be satisfied, and therefore, that the Plan will become effective and that the Debtors will emerge from the Chapter 11 proceedings as contemplated by the Plan. If the transactions contemplated by the Plan are not completed, it may become necessary to amend the Plan. Any new plan of reorganization would require the approval of the Bankruptcy Court and the approval of the required creditors, which could subject the Debtors to more lengthy and costly Chapter 11 proceedings. The Investment Agreement requires that the Plan be consummated by an outside date.

We may have insufficient liquidity for our business operations during the Chapter 11 proceedings.
Although we believe that we will have sufficient liquidity to operate our businesses during the pendency of the Chapter 11 proceedings, there can be no assurance that the revenue generated by our business operations and cash made available to us under the cash collateral order or otherwise in our restructuring process will be sufficient to fund our operations, especially as we expect to incur substantial professional and other fees related to our restructuring. We have not made arrangements for financing in the form of a debtor-in-possession credit facility, or DIP facility. In the event that revenue flows and other available cash are not sufficient to meet our liquidity requirements, we may be required to seek additional financing. There can be no assurance that such additional financing would be available or, if available, offered on terms that are acceptable. If, for one or more reasons, we are

9




unable to obtain such additional financing, we could be required to seek a sale of the company or certain of its material assets or our businesses and assets may be subject to liquidation under Chapter 7 of the Bankruptcy Code, and we may cease to continue as a going concern.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may not be successful in its execution.
Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure, (ii) our reorganization within the Seadrill corporate organization, which will include the introduction of two intermediate holding companies and a new group that will issue new secured notes under the terms of the Plan, (iii) our ability to obtain adequate liquidity and financing sources, (iv) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them, (v) our ability to retain key employees and (vi) the overall strength and stability of general economic conditions in the global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, net income, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure and our corporate structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

As a result of the Chapter 11 proceedings, realization of assets and liquidation of liabilities are subject to uncertainty.
While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements.

As a result of the Chapter 11 proceedings, our historical financial information may not be indicative of our future financial performance.
Our capital structure and our corporate structure will likely be altered under any plan of reorganization ultimately confirmed by the Bankruptcy Court. Under fresh-start accounting and reporting rules that could apply to us upon the effective date of a plan of reorganization, our assets and liabilities would be adjusted to fair values and our accumulated surplus would be restated to zero. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from Chapter 11 proceedings would not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection with the Chapter 11 proceedings and the development of a plan of reorganization, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to our consolidated financial position and results of operations in any given period.

Trading in our securities during the term of the Chapter 11 proceedings is highly speculative and poses substantial risks.
Trading in securities of an issuer in bankruptcy is extremely speculative, and there is a very significant risk that investors will lose all or a substantial portion of their investment. While the Plan provides for, under certain circumstances, some recoveries to holders of our debt securities, and no recoveries to our equity holders, we can provide no assurances that the Plan will be confirmed and consummated, whether such certain circumstances will arise and the amount of any recoveries. Therefore, we can give no assurance at this time whether holders of our securities will receive any distribution with respect to, or be able to recover any portion of, their investments. We believe it is likely that holders of our common stock will receive no recovery. Trading prices for our securities may bear little or no relationship to actual recovery, if any, by holders thereof during the term of the Chapter 11 proceedings.

We caution and urge existing and future investors to carefully consider the significant risks with respect to investments in our securities.
Risks Relating to Our Company and Industry

The success and growth of our business depends 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:
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;

10




advances in exploration, development and production technology;
the ability of the Organization of 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.

Declines 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 conditions 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 March 31, 2018, the price of Brent crude was approximately $70 per barrel. The significant decrease in oil and natural gas prices is expected to continue to reduce many of our customers’ demand for our services in 2018 due to significant decreases in budgeted expenditures for offshore drilling.

Declines in capital spending levels, coupled with additional newbuild supply, are likely to continue to intensify price competition and 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 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. We

11




currently have four 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.

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.

Our future business depends on the level of oil and gas activity in the North Atlantic Region and our ability to operate outside of Norway and the United Kingdom.
Our future business depends significantly on the future level of oil and gas activity in the North Atlantic Region and our ability to expand into North Atlantic Region markets outside Norway and the United Kingdom. Expansion of our business outside Norway and the United Kingdom depends on our ability to operate in other areas of the North Atlantic Region. Any such expansion may be adversely affected by local regulations requiring us to award contracts to local operators and the number and location of new drilling concessions granted by foreign governments. Restrictions or requirements that may be imposed in the countries in which we operate could have a material adverse effect on our financial position, results of operations or cash flows. If we are unable to expand our operations within the geographic area where we currently operate, or gain contracts in the North Atlantic Region markets outside of Norway and the United Kingdom, our future business, financial condition and results of operations may be adversely affected.

There is substantial doubt regarding our ability to continue as a going concern.
As described in Note 1 to our Consolidated Financial Statements appearing in Item 18, we do not currently expect that our cash flows from operations would be sufficient to repay our indebtedness and, accordingly, we have sought a reorganization under Chapter 11 of the Bankruptcy Code. The accompanying financial statements have been prepared on the basis of accounting principles applicable to a going concern. Our ability to continue as a going concern is contingent upon, among other things, our ability to: (i) develop and successfully implement a restructuring plan within the timeframe required by the terms of the RSA and the Investment Agreement, (ii) comply with the covenants contained in the cash collateral order, including compliance with the approved budget, and the covenants contained in any post-restructuring financing arrangements, (iii) reduce debt and other liabilities through the restructuring process, (iv) generate sufficient cash flow from operations and (v) obtain financing sources to meet our future obligations. The accompanying consolidated financial statements also do not include any adjustments that might be necessary should we be unable to continue as a going concern. We believe the consummation of a successful Chapter 11 proceeding is critical to our continued viability and long-term liquidity. While we are working towards achieving these objectives, there can be no certainty that we will be successful in doing so.

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, 2017, we had $430.3 million in principal amount of interest-bearing debt (including related party debt of $121.5 million), representing approximately 22,305.2% of our total market capitalization, of which $308.8 million was secured by, among other things, liens on our drilling units. We expect to amend our secured credit facilities and to equitize certain of our unsecured debt under the terms of the Plan. Nonetheless, our outstanding indebtedness and future indebtedness that we may incur could affect our future operations, since a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes. Covenants contained in our debt agreements require us to meet certain financial tests and non-financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business or economic conditions, 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. The amendments to our secured credit facilities under the terms of the Plan may introduce additional restrictive covenants, as well as revise certain financial tests we must meet. While the RSA remains in force and effect, our lenders have agreed to waive any breach of, and any default or event of default under, our debt agreements which arise as a result of or is related to, directly or indirectly, the Chapter 11 proceedings, and the actions or transactions required by, implemented by or undertaken pursuant to RSA.
Our ability to meet our debt service obligations and to fund planned expenditures, including construction costs for our newbuilding projects, 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 our debt, raise new debt, sell assets or repay the debt with the proceeds from equity offerings.

12




Our ability to amend our existing secured credit facilities and to refinance or retire other indebtedness is dependent on our effecting the terms of the Plan as contemplated by the RSA. Please also see “Item 5. Operating and Financial Review and Prospects-B. Liquidity and Capital Resources.”

The covenants in our credit facilities impose operating and financial restrictions on us, breach of which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed.
Our debt agreements (as amended in April 2016 and as further amended to date) 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;
changing the management and/or ownership of the drilling units;
making capital expenditures; and
competing effectively to the extent our competitors are subject to less onerous restrictions.

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. In addition, certain of our debt agreements, including those expected to be amended in accordance with the terms of the Plan, require us to maintain specified financial ratios and to satisfy financial covenants, including ratios and covenants that pertain to, among other things, our total equity, our total indebtedness and the market value of our drilling units. In the future, we may be required to record impairment charges to our investments or other assets. Any impairment charges could adversely impact our ability to comply with the restrictions and covenants in our debt agreements, including meeting financial ratios and tests in those agreements. The amendments to our secured credit facilities under the terms of the Plan may introduce additional restrictive covenants, as well as revise certain financial tests we must meet. While the RSA remains in force and effect, our lenders have agreed to waive any breach of, and any default or event of default under, our debt agreements which arise as a result of or is related to, directly or indirectly, the Chapter 11 proceedings, and the actions or transactions required by, implemented by or undertaken pursuant to RSA.

If we or Seadrill are unable to comply with the restrictions and covenants in our debt agreements, or in current or future debt financing agreements, and we are unable to obtain a waiver or amendment from our lenders for such noncompliance, 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 in some circumstances accelerate the outstanding loans and declare all amounts borrowed due and payable. All of our external facility 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 and certain other assets also serve as security for our commercial bank indebtedness. 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, 2017, we had $308.8 million of interest-bearing debt secured by, among other things, liens on our drilling units and certain other assets. We expect that, under the terms of the Plan, additional security under the amended secured credit facilities will be granted to our lenders.

If any of the aforementioned events occur, our assets may be insufficient to repay in full all of our outstanding indebtedness, 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 find are 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, including through the issuance of guarantees.

Seadrill may not honor its guarantee of our debt.
Seadrill guarantees our NOK 1,500 million senior unsecured bond, our $2,000 million Senior Secured Credit Facility, and our charter payments to SFL Linus Ltd in connection with its $475 million secured term loan, which is consolidated in our financial statements. Our current and future indebtedness could also affect our future operations, as a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes. Covenants contained in our debt agreements require Seadrill to meet certain financial tests and non-financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business or economic conditions, 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. Cross-default clauses exist between our secured credit facilities and bonds and Seadrill's debt. While the RSA remains in force and effect, our lenders have agreed to waive any breach of, and any default or event of default under, our debt agreements which arise as a result of or is related to, directly or indirectly, the Chapter 11 proceedings, and the actions or transactions required by, implemented by or undertaken pursuant to RSA.

We are highly dependent on Seadrill and its affiliates to assist us in operating our business. Any inability of Seadrill or its associates to honor its guarantees of our debt or provide us with sufficient liquidity could negatively impact our business. Please see “—We are a holding company dependent on our

13




subsidiaries and certain affiliates of Seadrill, including Seadrill Management AS, or Seadrill Management, to assist us in operating and satisfying our financial obligations" below.

We are a holding company dependent on our subsidiaries and certain affiliates of Seadrill, including Seadrill Management Limited, or Seadrill Management, to assist us in operating and satisfying our financial obligations.
We are a holding company, and our subsidiaries, which are all directly and indirectly wholly-owned by us, conduct all of our operations and own all of our operating assets. As a result, our ability to satisfy our financial obligations in the future depends on the ability of our subsidiaries to generate profits available for distribution to us. Our ability to enter into new drilling contracts and expand our customer and supplier relationships also depends largely on our ability to leverage our relationship with Seadrill and its reputation and relationships in the offshore drilling industry. If Seadrill suffers material damage to its reputation or relationships, it may harm our ability to:
renew existing drilling contracts upon their expiration;
obtain new drilling contracts;
efficiently and productively carry out our drilling activities;
successfully interact with shipyards;
obtain financing and maintain insurance on commercially acceptable terms; or
maintain satisfactory relationships with suppliers and other third parties.

Pursuant to a services agreement between us and Seadrill Management, or the Services Agreement, Seadrill Management provides us with treasury and financial advisory services, insurance placement and building supervisory services. We also receive corporate, secretarial and certain other administrative services relating to the jurisdiction of Bermuda from Frontline Management (Bermuda) Ltd. under the Services Agreement with Seadrill Management. In addition, we receive management services from Seatankers Management Norway AS. Pursuant to our cooperation agreement with Seadrill, or the Cooperation Agreement, we also have the right of first refusal to participate in any business opportunity identified by Seadrill for drilling activities in the North Atlantic Region and have provided Seadrill with a right of first refusal to participate in any business opportunity identified by us for drilling activities outside the North Atlantic Region. Our operational success and ability to execute our growth strategy will depend significantly upon the satisfactory performance of these agreements. Our business will be harmed if Seadrill and its affiliates fail to perform satisfactorily under these agreements, if they cancel their agreements with us or if they stop providing these services to us. Please see “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions.”

For example, on January 31, 2017, we entered into a $25 million revolving credit facility with Seadrill, which was originally set to mature on March 31, 2017, and then was extended until April 30, 2017. On April 25, 2017, the revolving credit facility was increased to $50 million and extended to June 30, 2017. On June 27, 2017, the facility was increased to $150 million and extended to July 31, 2017. On July 27, 2017, the facility was extended to September12, 2017. On September 8, 2017, the facility was increased to $200 million. This interim funding arrangement has been put in place while comprehensive restructuring negotiations continue at both companies.

Although Seadrill has historically provided us with significant financial resources, Seadrill may diminish or cease providing such financial resources in the future. If Seadrill were to reduce its ownership in us to a minority interest, we can provide no assurance that Seadrill would continue to provide support and management services to us, and we can provide no assurance that we would be able to replace Seadrill’s support and services with the support and services of a third party that would be of the same quality or at the same cost. If funding is insufficient at any time in the future, we may be unable to fund maintenance requirements, take advantage of business opportunities or respond to competitive pressures, any of which could adversely impact our financial condition and results of operations.

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. For example, on September 27, 2016, we received a notice of termination from Statoil for the West Epsilon drilling contract, which was effective upon the rig completing its activities mid-October. Pursuant to the termination provisions in the contract, we received a lump sum payment of approximately $11 million.

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.

In the current environment our customers may seek to renegotiate our contracts 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.

14





Reduced day rates in our customer contracts and cancellation of drilling contracts (with or without early termination payments) may lead to reduced revenues from our operations and performance of our business and adversely affect our performance.

Our contract backlog for our fleet of drilling units may not be realized.
As of March 31, 2018, our contract backlog was approximately $1.5 billion, including the recently announced awards and extensions. The contract backlog presented in this annual report 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 loss of this drilling contract.

For example, on September 27, 2016, we received a notice of termination from Statoil for the West Epsilon drilling contract, resulting in a potential backlog reduction.

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 been terminated.
During the recent 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 March 31, 2018, we had four contracts that expire in 2018 (relating to the West Phoenix and West Elara), one contract that expires in 2019 (relating to the West Linus ), two contracts that expire in 2020 (relating to the West Phoenix and West Elara) and two contracts that expire in 2027 and 2028 (relating to the West Linus and West Elara). As at March 31, 2018, we had four units stacked and uncontracted, the West Alpha, West Epsilon, the West Navigator, and the West Venture. Our ability to renew these 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. Customers may also choose not to award drilling contracts to us due to our debt restructuring activities.

If we are unable to secure contracts for our drilling units, including for when newbuildings are delivered to us and 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 March 31, 2018, we had four 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. 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 and cost-overruns on our newbuild projects.”

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 contracts 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 which risk we may be unable to push down to other contractors, are unable or unwilling at competitive prices to insure against and which therefore 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 we have commissioned 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. During 2017, the estimated fair value of our drilling units, based upon various broker valuations, has decreased by approximately 11.4% (including the effect of the rig ages increasing by a year). If the offshore contract drilling industry suffers further adverse developments in the future, the fair market value of our drilling units may decline further. 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:

15




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" and "-The covenants in our credit facilities impose operating and financial restrictions on us, breach of which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed."

Under certain of our secured bank credit facilities, we are required to comply with loan-to-value or minimum-value-clauses, which could require us to post additional collateral or prepay a portion of the outstanding borrowings should the value of the drilling units securing borrowings under each of such agreements decrease below required levels. If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness or in current or future debt financing agreements, a default could occur under the terms of those agreements. While the RSA remains in force and effect, our lenders have agreed to waive any breach of, and any default or event of default under, our debt agreements which arise as a result of or is related to, directly or indirectly, the Chapter 11 proceedings, and the actions or transactions required by, implemented by or undertaken pursuant to RSA.

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, craterings, 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 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 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, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, 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 all these risks. Customers may seek to cap indemnities or narrow the scope of their coverage, reducing our level of contractual protection. 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".

In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a 2012 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), the U.S. District Court for the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties under the U.S. Clean Water Act under a drilling contract governed by U.S. maritime law as a matter of public policy. 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.


16




The amount recoverable under insurance may also: be less than the related impact on enterprise value after a loss; 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.

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. Among our four customers for the year ending December 31, 2017, Statoil accounted for 32%, Conoco Phillips accounted for 49%, Total accounted for 8% and Nexen accounted for 11% of our total revenues. Among our four customers for the year ended December 31, 2016, Statoil accounted for 40%, ExxonMobil accounted for 25%, Conoco Phillips accounted for 25%, and Total accounted for 10% of our total revenues. As at March 31, 2018, most of our future contracted revenues, or contract backlog, is contracted with ConocoPhillips.

In addition, mergers among oil and gas exploration and production companies have reduced, and may from time to time 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 outline 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.

We may not commence operations under the drilling contracts with Rosneft Oil Company, and we may not close the acquisition of the land drilling business from Rosneft Oil Company.
In July 2014, we entered into six offshore drilling contracts with Rosneft. In August 2014, we entered into an agreement to acquire a significant portion of Rosneft's land drilling fleet in Russia, along with new five-year contracts awarded by Rosneft for the land drilling units being acquired pursuant to a framework agreement, or the Framework Agreement. In November 2014, we and Rosneft agreed to delay to May 2015 the closing of these transactions that are contemplated in the Framework Agreement and on April 16, 2015 and subsequently May 31, 2017, we mutually agreed to further extend the date of termination of the Framework Agreement until May 31, 2019, whereby both parties can effectively terminate the Framework Agreement and / or any offshore drilling contracts at any time prior to May 31, 2019 at no cost. In June 2015, the parties agreed to cancel any restrictions of business included within the terms of the Framework Agreement, and replaced this with a requirement for us, subject to applicable law, to inform Rosneft of any material developments affecting us. Due to recent and ongoing developments and events, we believe that it will be extremely unlikely to close these transactions on the same terms contemplated in the executed agreements.

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 and cost-overruns on our new-build projects.
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.
In order 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 cost increases, 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 semiannually, 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. Shorter-term contracts normally do not contain escalation provisions. 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.


17




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 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 depends 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 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, 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 and result 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 timely secure the necessary approvals or permits, 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, 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.

The international nature of our operations involves additional risks including foreign government intervention in relevant markets.
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:
terrorist acts, armed hostilities, war and civil disturbances;
acts of piracy, which have historically affected ocean-going vessels;
significant governmental influence over many aspects of local economies;
the seizure, nationalization or expropriation of property or equipment;
uncertainty of outcome in foreign court proceedings;
the repudiation, nullification, modification or renegotiation of contracts;
limitations on insurance coverage, such as war risk coverage, in certain areas;
political unrest;
foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;
the inability to repatriate income or capital;
complications associated with repairing and replacing equipment in remote locations;
import-export quotas, wage and price controls, and the imposition of trade barriers;

18




U.S. and foreign sanctions or trade embargoes;
compliance with various jurisdictional regulatory or financial requirements;
compliance with and changes with taxation;
other forms of government regulation and economic conditions that are beyond our control; and
governmental 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:
the equipping and operation of drilling units;
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.

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 governmental 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.

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 that banned offshore oil and gas drilling in large area of the Arctic and the Atlantic Seaboard. It is presently unclear how long this ban will remain in effect. 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 of the environment.

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

19




units. These requirements include, but are not limited to the United Nation’s International Maritime Organization, or the 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. 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.

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 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, 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. 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.

Our insurance coverage 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.
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

20




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 our 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. For instance, our affiliated company Sevan has previously disclosed that its predecessor entity, Sevan Drilling ASA, has been accused of breaches of Norwegian law in respect of payments made in connection with the performance during 2012 to 2015 of drilling contracts originally awarded by Petrobras to subsidiaries of Sevan Marine ASA in the period between 2005 and 2008. Furthermore, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

If our drilling units are located in countries that are subject to economic sanctions 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.
Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions in particular are targeted against countries (such as Russia, Venezuela, Iran, Myanmar and Sudan, among others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities.

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 sanctioned activities involving Iran during the timeframe covered by the report. At this time, we are not aware of any violations, conducted by us or by any affiliate, which is likely to trigger such a disclosure requirement.

On November 24, 2013, the P5+1 (the United States, United Kingdom, Germany, France, Russia and China) entered into an interim agreement with Iran entitled the “Joint Plan of Action,” or the JPOA. Under the JPOA it was agreed that, in exchange for Iran taking certain voluntary measures to ensure that its nuclear program is only used for peaceful purposes, the United States and the European Union would voluntarily suspend certain sanctions for a period of six months. On January 20, 2014, the United States and the European Union began implementing the temporary relief measures provided for under the JPOA.

The JPOA was subsequently extended twice. 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 does not involve 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.

U.S. sanctions prohibiting certain conduct that is now permitted under the JCPOA have not actually been repealed or permanently terminated at this time. Rather, the U.S. government has implemented changes to the sanctions regime by: (1) issuing waivers of certain statutory sanctions provisions; (2) committing to refrain from exercising certain discretionary sanctions authorities; (3) removing certain individuals and entities from OFAC's sanctions lists; and (4) revoking certain Executive Orders and specified sections of Executive Orders. These sanctions will not be permanently "lifted" until the earlier of “Transition Day,” set to occur on October 20, 2023, or upon a report from the IAEA stating that all nuclear material in Iran is being used for peaceful activities.

On October 13, 2017, the current U.S administration announced it would not certify Iran's compliance with the JCPOA. This did not withdraw the U.S. from the JCPOA or re-instate any sanctions. However, they have criticized the JCPOA and threatened to withdraw the U.S. from the JCPOA. Further, the administration must periodically renew sanction waivers and his refusal to do so could result in the reinstatement of certain sanctions currently suspended under the JCPOA.

OFAC acted several times in 2017 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. Moreover, 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.


21




In addition to the sanctions against Iran, 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.

In addition to the sanctions against Iran, subject to certain 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 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. With the exception of an investment and co-operation agreement with Rosneft Oil Company, or Rosneft, for activity in Russian Arctic and deepwater areas, as mentioned below, 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 of our customers or other parties with whom we have entered into contracts may be 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 may be affiliated with persons or entities that are the subject of such sanctions. 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 closing the previously announced transactions with Rosneft, or 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.

As stated above, we believe that we are in compliance with all applicable 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. Any such violation could result in fines 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, or market perceptions concerning these and related issues, European countries 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.

In June 2016, the U.K. voted to exit from the European Union (commonly referred to as “Brexit”). The impact of Brexit and the resulting U.K and European relationship are uncertain for companies doing business both in the U.K. and the overall global economy.


22




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.

If our lenders are not confident that we are able to employ our assets, we may be unable to secure additional financing on terms acceptable to us or at all for the remaining installment payments we are obligated to make before the delivery of our remaining newbuildings and our other capital requirements, including principal repayments.

The Deepwater Horizon oil spill in the U.S. Gulf of Mexico has and may result in more stringent laws and regulations governing offshore drilling, which could have a material adverse effect on our business, results of operations or financial condition.
On April 20, 2010, there was an explosion and a related fire on the Deepwater Horizon, an ultra-deepwater semi-submersible drilling rig that is not connected to us, while it was servicing a well in the U.S. Gulf of Mexico. This catastrophic event resulted in the death of 11 workers and the total loss of that drilling rig, as well as the release of large amounts of oil into the U.S. Gulf of Mexico, impacting the environment and the region’s key industries. This event was investigated by several federal agencies, including the U.S. Department of Justice and by the U.S. Congress, and was also the subject of numerous lawsuits. On January 3, 2013, Transocean Deepwater Inc. agreed to plead guilty to violating the U.S. Clean Water Act and to pay $1.4 billion in civil and criminal fines and penalties for its conduct in relation to the incident. On May 30, 2010, the U.S. Department of the Interior issued a six-month moratorium on all deepwater drilling in the outer continental shelf regions of the U.S. Gulf of Mexico and the Pacific Ocean. On October 12, 2010, the U.S. government lifted the drilling moratorium, subject to compliance with enhanced safety requirements. All drilling in the U.S. Gulf of Mexico must comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule), which took effect October 22, 2012, and the Workplace Safety Rule on Safety and Environmental Management Systems and various requirements imposed through Notices to Lessees and Operators, or SEMS. Operators were required to implement a SEMS program by November 15, 2011 and submit their first completed SEMS audit to BSEE by November 15, 2013. The original SEMS rule was later modified by the SEMS II final rule which became effective June 4, 2013. SEMS II enhanced and supplemented operators' SEMS programs with employee training, empowering field level personnel with safety management decisions and strengthening auditing procedures by requiring them to be completed by independent third parties. Operators had until June 4, 2014 to comply with SEMS II, except for certain auditing requirements. All SEMS audits had to comply with SEMS II by June 4, 2015. The U.S. Occupational Safety and Health Act imposes additional record keeping obligations concerning occupational injuries and illnesses for Mobile Offshore Drilling Units attached to the outer continental shelf.

While we do not currently operate any of our drilling rigs in the U.S. Gulf of Mexico, these developments could have a substantial impact on the offshore oil and gas industry worldwide. Governmental investigations and proceedings may result in significant changes to existing laws and regulations and substantially stricter governmental regulation of our drilling rigs. For example, Norway’s Petroleum Safety Authority assessed the results of the investigations into the Deepwater Horizon oil spill and issued a preliminary report of its recommendations in June 2011, and a final report in February 2014. The Oil & Gas United Kingdom has established the Oil Spill Prevention and Response Advisory Group, which issued its final report on industry practices in the United Kingdom in September 2011. In addition, BP plc, a company not affiliated with us and the rig operator of the Deepwater Horizon, has reached an agreement with the U.S. government to establish a claims fund of $20 billion, which far exceeds the $75 million strict liability limit set forth under the U.S. Oil Pollution Act of 1990. The settlement was approved in April 2016. Amendments to existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and the production of oil and gas, may be highly restrictive and require costly compliance measures that 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 amended or new legislation or regulations.

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, 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.


23




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 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. With the exception of some of our bonds, the majority of our debt arrangements have floating interest rates. As such, after our emergence from Chapter 11 proceedings, significant movements in interest rates could have an adverse effect on our earnings and cash flow. In order to manage our exposure to interest rate fluctuations, we use interest rate swaps to effectively fix a part of our floating rate debt obligations. The principal amount covered by interest rate swaps is evaluated continuously and determined based on our debt level, our expectations regarding future interest rates and our overall financial risk exposure. Although we enter into various interest rate swap transactions to manage exposure to movements in interest rates, there can be no assurance that we will be able to continue to do so at a reasonable cost or at all.

If we are unable to effectively manage our interest rate exposure through interest rate swaps 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.

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 and U.K. pounds sterling 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.
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 certain 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, 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.

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 averse 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.


24




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 and the IMO have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. Currently, the emissions of greenhouse gases from international shipping are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which entered into force in 2005 and pursuant to which adopting countries have been required to implement national programs to reduce greenhouse gas emissions or the Paris Agreement, which resulted from the 2015 United Nations Framework Convention Climate Change Conference in Paris and entered into force on November 4, 2016. As at January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted by the IMO’s Maritime Environment Protection Committee or the MEPC in July 2011, relating to greenhouse gas emissions. The European Union has indicated that it intends to propose an expansion of the existing European Union Emissions Trading Scheme to include emissions of greenhouse gases from marine vessels. A roadmap for a “comprehensive IMO strategy on a reduction of GHG emissions from ships” was also approved by MEPC at its 70th session in October 2016. These requirements could cause us to incur additional compliance costs.

In addition, the European Union has indicated that it intends to propose an expansion of the existing European Union Emissions Trading Scheme to include emissions of greenhouse gases from marine vessels. In April 2015, a regulation was adopted requiring that large ships (over 5,000 gross tons) calling at European Union ports from January 2018 collect and publish data on carbon dioxide emissions and other information. In the United States, the Environmental Protection Agency, or the EPA, has issued a finding that greenhouse gases endanger the public health and safety and has adopted regulations to limit greenhouse gas emissions from certain mobile sources and large stationary sources. Although the mobile source emissions regulations do not apply to greenhouse gas emissions from drilling units, such regulation of drilling units is foreseeable, and the EPA has received petitions from the California Attorney General and various environmental groups seeking such regulation. In the United States, individual states can also enact environmental regulations. For example, California has introduced caps for greenhouse gas emission and, in the end of 2016, signaled it might take additional actions regarding climate change.

Compliance with changes in laws, regulations and obligations relating to climate change could increase our costs related to operating and maintaining 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 long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business, including capital expenditures to upgrade our drilling rigs, which we cannot predict with certainty at this time.

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 and other proceedings that could have an adverse effect on us.
We are currently involved in various litigation matters, and we anticipate that we will be involved in litigation matters from time to time in the future. The operating hazards inherent in our business expose us to litigation, including personal injury litigation, environmental litigation, contractual litigation with customers, intellectual property litigation, tax or securities litigation 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 litigation matter, or a combination of these. If we are involved in any future litigation, 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, and the diversion of management’s attention to these matters.


25




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.

To the extent claims are filed on existing litigious matters, those claims are being adjudicated as part of the Chapter 11 proceedings.

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.

We depend on directors who are associated with affiliated companies, which may create conflicts of interest.
Our principal shareholder is Seadrill. Mrs. Kate Blankenship and Mr. Paul M. Leand Jr are also directors of Seadrill, and serve as directors of other related companies. The aforementioned 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.

Seadrill and its affiliates may compete against us.
Pursuant to our cooperation agreement, or the Cooperation Agreement, with Seadrill, we have the right of first refusal to participate in any business opportunity identified by Seadrill for drilling activities in the North Atlantic Region and Seadrill has a right of first refusal to participate in any business opportunity identified by us for drilling activities outside the North Atlantic Region. The Cooperation Agreement, however, contains significant exceptions that may allow Seadrill or any of its affiliates to compete with us, and in certain cases Seadrill has provided Seadrill Partners LLC, or Seadrill Partners, with the right to purchase any drilling rig in Seadrill’s fleet in the event that any such rig enters into a contract with a term of five years or more, which could restrict our growth prospects. Please see “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions.”

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.
Under the Sarbanes-Oxley Act, 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, 2017, 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.

Risks Relating to Our Common Shareholders
The Plan provides that holders of our common shares will receive no recoveries in respect of their common shares.
Under the terms of the Plan, we expect our existing common stock will be cancelled on the effective date of the Plan, with no recoveries to holders of our common stock. We can provide no assurances that the Plan will be confirmed and consummated, and we cannot predict recoveries at this time,

26




however, we believe it is likely that our common shareholders will receive no recovery in respect of their common shares. Trading prices for our common shares during the term of the Chapter 11 proceedings may bear little or no relationship to actual recovery, if any, by holders thereof.

The NYSE has suspended trading in and delisted our common shares.
The NYSE has determined that our common stock is no longer suitable for listing pursuant to Listed Company Manual Section 802.01D because of our announcement on September 12, 2017 that the Company and other consolidated subsidiaries of Seadrill filed prearranged Chapter 11 cases in the Southern District of Texas. In reaching its delisting determination, NYSE Regulation noted that the shareholders of the Company will receive no recovery and therefore continued listing was no longer suitable. The NYSE suspended trading in our common stock prior to the open of markets on September 13, 2017 and subsequently delisted our common stock.

The market price of our common shares has fluctuated widely and may fluctuate widely in the future.
Our common stock now trades in the United States over-the-counter market and on the Norwegian OTC List, where it is traded since February 24, 2011. Securities traded in the over-the-counter market generally have significantly less liquidity than securities traded on a national securities exchange, due to factors such as the reduced number of investors that will consider investing in the securities, the reduced number of market makers in the securities, and the reduced number of securities analysts that follow such securities. As a result, holders of shares of our common stock may find it difficult to resell their shares at prices quoted in the market or at all. The market price of our common shares has fluctuated widely and may continue to do so in the future. The market price of our common shares has declined significantly. For our share price history, please see "Item 9. The Offer and Listing-A. Offer and Listing Details."

We may not pay dividends in the future.
Under our bye-laws, any dividends declared will be in the sole discretion of our Board of Directors, or the Board, and will depend upon earnings, market prospects, current capital expenditure programs and investment opportunities. Under Bermuda law, we may not declare or pay a dividend, or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (a) we are, or would after the payment be, unable to pay our liabilities as they become due or (b) the realizable value of our assets would thereby be less than our liabilities. 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. As part of additional amendments to other covenants contained in our senior secured credit facilities in April 2016, as further amended in 2017, we are currently restricted from paying dividends or making distributions effectively until a restructuring of our senior secured credit facilities is agreed to, including the extension of their tenor and the amendment of financial covenants. Under the terms of the Plan, our common shares will be cancelled on the effective date of the Plan. During the Chapter 11 proceedings, we would need to seek approval of the Bankruptcy Court to pay any dividend. We do not expect to seek such approval during the Chapter 11 proceedings.

Seadrill controls a substantial ownership stake in us and Seadrill’s interests could conflict with interest of our other shareholders.
As the date of this Annual Report, Seadrill owns approximately 70.4% of our outstanding common shares. As a result of this substantial ownership interest, Seadrill currently has the ability to exert significant influence over certain actions requiring shareholders’ approval, including, increasing or decreasing the authorized share capital, the election of directors, declaration of dividends, the appointment of management, and other policy decisions. While transactions with Seadrill could benefit us, the interests of Seadrill could at times conflict with the interests of our other shareholders. Conflicts of interest may arise between us and Seadrill or its affiliates.

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.




27




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 purposes of these tests, income derived from the performance of services does not constitute “passive income.” U.S. shareholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the 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, as 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 of the common shares arising in an investor’s particular situation under U.S. federal, state, local or foreign law.

ITEM 4.    INFORMATION ON THE COMPANY

A.    History and Development of the Company

The Company
North Atlantic Drilling Ltd. was formed as an exempted company limited by shares under the laws of Bermuda on February 10, 2011, by our parent, Seadrill (NYSE: SDRL), as a new offshore drilling subsidiary focused on operations in the North Atlantic Region, which includes only the territorial waters and outer continental shelf jurisdiction of Norway, the United Kingdom, Ireland, Denmark, the Netherlands, the east coast of Greenland, Russia (west of the island of Diksonskiy), and all countries within the Baltic Sea and the Gulf of Bothnia. On February 17, 2011, we entered into an agreement with Seadrill to acquire six harsh environment drilling rigs, including all relevant contracts, spares, stores and offshore personnel related to the drilling rigs, which we refer to as the North Atlantic Restructuring. The North Atlantic Restructuring closed on March 31, 2011 and our business is a direct continuation of the North Atlantic business of Seadrill. We did not engage in any business or other activities prior to the North Atlantic Restructuring, except in connection with our formation. The North Atlantic Restructuring was limited to entities that were under the control of Seadrill and its affiliates, and, as such, the North Atlantic Restructuring was accounted for as a transaction between entities under common control.

In February 2014, we completed our underwritten initial public offering of 13,513,514 common shares at $9.25 per share. We also completed our offer to exchange all of the unregistered common shares that we previously issued in our prior equity private placements (other than the common shares owned by our affiliates) for common shares that have been registered under the Securities Act of 1933, as amended, or the Securities Act, in which an aggregate of 53,068,404 common shares were validly tendered and exchanged. The shares traded on the Norwegian OTC List under the symbol “NADL.”

On December 31, 2015, our shareholders, in a special general meeting, approved a capital reorganization including a 1-for-10 reverse stock split of our issued and outstanding common shares and reducing par value from $5.00 to $0.10. The high and low prices presented as at December 30, 2016 and prior to this have been re-presented to reflect the change from the 1-for-10 reverse stock split.

On September 12, 2017, NADL and certain other of NADL's consolidated subsidiaries commenced prearranged reorganization proceedings under Chapter 11 of title XI of the United States Code in the Southern District of Texas. As a result of the bankruptcy proceedings, the NYSE delisted NADL's common stock in October 2017.


28




The outstanding debt of NADL as of December 31, 2017 amounted to $1,689 million, of which $1,089 million is guaranteed by Seadrill. On filing for Chapter 11, the outstanding debt balance is held as a "liability subject to compromise" in the Consolidated Balance Sheet as at December 31, 2017.

Our principal executive 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.

Management of the Company
As described under section D of Item 3, upon the filing of voluntary petitions to restructure under the protections Chapter 11 of the Bankruptcy Code, we operate the business as debtors-in-possession under supervision of the Bankruptcy Court. Debtors-in-possession status requires that we obtain approval of the Bankruptcy Court with respect to our business, and in some cases, the Consenting Stakeholders under the terms of the RSA and the Commitment Parties under the terms of the Investment Agreement, prior to engaging in certain activities or transactions. Accordingly, ultimate discretion of many operational and non-routine activities is subject to final supervision of the Bankruptcy Court and does not reside in solely with management.

The Board has organized the provision of management services through Seadrill Management Ltd., or Seadrill Management, a subsidiary of Seadrill Limited incorporated in the United Kingdom. The Board has defined the scope and terms of the services to be provided by Seadrill Management. The Board 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.

Recent Developments

Significant Developments for the Period from January 1, 2015 through and including December 31, 2017

Restructuring Agreement and Bankruptcy Proceedings under Chapter 11
Over the past two years we, together with Seadrill, have been engaged in extensive discussions with our secured lenders and potential new money investors regarding the terms of a comprehensive restructuring. These discussions have also included an ad hoc committee of bondholders. The objectives of the restructuring are to build a bridge to a recovery and achieve a sustainable capital structure. Seadrill have proposed to achieve this by extending bank maturities, reducing fixed amortization, amending financial covenants and raising new capital.

On April 4, 2017, Seadrill reached an agreement with its banking group, including our secured lenders, to extend the comprehensive restructuring plan negotiating period until July 31, 2017. Further the related covenant amendments and waivers expiring on June 30, 2017 were extended to September 30, 2017 and lender consent was received to extend the maturity dates of certain facilities falling due within that period. This provided Seadrill and the Company additional time to advance ongoing negotiations regarding the terms of the comprehensive restructuring plan.

In July 2017, Seadrill reached an agreement with the bank group, including our secured lenders, to further extend the date by which a comprehensive restructuring plan must be agreed until September 12, 2017 providing an additional period for negotiations to continue over a comprehensive restructuring plan. Seadrill also extended the maturities of its US$400 million credit facility and the US$450 million credit facility provided to Seadrill Eminence Ltd to September 14, 2017.

On September 12, 2017, we, together with Seadrill and certain of Seadrill’s consolidated subsidiaries (collectively, the Company Parties) entered into the RSA with the Consenting Stakeholders. Ship Finance International Limited 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 and a consortium of investors, including the bondholder parties to the RSA, committed to provide $1.06 billion in new cash commitments, subject to certain terms and conditions.

On September 12, 2017, to implement the transactions contemplated by the RSA and Investment Agreement, we, and the other Company Parties (collectively, the "Debtors") commenced prearranged Chapter 11 proceedings under the Bankruptcy Code in the Southern District of Texas, [case number 17-60079]. During the course of the bankruptcy proceedings, the Debtors continue to operate their business as a debtor in possession.

On the Petition Date, the Bankruptcy Court issued certain additional customary interim and final orders with respect to the Debtors’ first day motions and other operating motions that allow the Debtors to operate their businesses in the ordinary course. The first-day motions provided for, among other things, the payment of certain pre-petition employee and retiree expenses and benefits, the use of the Debtors’ existing cash management system, the payment of certain pre-petition amounts to certain critical vendors, the ability to pay certain pre-petition taxes and regulatory fees, the payment of certain pre-petition claims owed on account of insurance policies and programs and authorizing the use of cash collateral.

On February 26, 2018, the Debtors announced a global settlement with various creditors, including an ad hoc group of holders of unsecured bonds, the official committee of unsecured creditors (the “Committee”) and other major creditors in its Chapter 11 cases, including Samsung Heavy Industries Co., Ltd. and Daewoo Shipbuilding & Marine Engineering Co., Ltd., two of the Debtors’ newbuild shipyards, and an affiliate of Barclays Bank PLC, 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 the inclusion of the Ad Hoc Group and Barclays into the

29




Capital Commitment as Commitment Parties, increased the Capital Commitment to $1.08 billion, increased recoveries for general unsecured creditors of Seadrill, NADL, and Sevan under the plan of reorganization, 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 of reorganization as well as the Debtors’ rejection and recognized termination of the newbuild contracts.

The Investment Agreement, as amended, provides for certain milestones for the Debtors’ restructuring: (1) the Bankruptcy Court must enter an order confirming the Plan by June 9, 2018 (the “Confirmation Date”) and (2) the effective date of the Plan must 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. On February 26, 2018, the Bankruptcy Court entered an order approving (i) the adequacy of the Disclosure Statement, (ii) the solicitation and notice procedures with respect to confirmation of the Debtors’ proposed Plan, (iii) the rights offering procedures for the rights offerings contemplated by the Plan and (iv) other related matters. The voting deadline for the Plan was April 5, 2018, and the confirmation hearing for the Plan is currently scheduled for April 17, 2018. By the voting deadline of April 5, 2018, the Plan received approval from every single class of creditors and holders of interests entitled to vote, exceeding the required thresholds for acceptance of the Plan.

Assuming that the Plan is confirmed and becomes effective, we expect our existing common stock will be cancelled on the effective date of the Plan, with no recoveries to holders of our common stock, and we will become a wholly owned subsidiary of Seadrill.

Concurrent with the commencement of the prearranged reorganization proceedings in the Bankruptcy Court, Seadrill, NADL and Sevan (collectively, the “Bermuda Debtors”) commenced provisional liquidation proceedings pursuant to section 161 and 170 of the Bermuda Companies Act 1981 by presenting “winding up” petitions to the Bermuda Court. Upon the application of the Bermuda Debtors, the Bermuda Court appointed three joint provisional liquidators for each of the Bermuda Debtors. Under the Order to appoint the joint provisional liquidators, the joint provisional liquidators’ powers are limited such that the Bermuda Debtors’ management team and boards of directors remain in control of the Bermuda Debtors’ day-to-day operations. Upon the appointment of the joint provisional liquidators in respect to each of the Bermuda Debtors, a statutory stay of proceedings in Bermuda against those three entities or their assets automatically arose. The next hearing in the Bermuda Court with respect to the “winding up” petitions was set for April 27, 2018. In addition to the statutory stay, as soon as practicable following the effective date (in accordance with the Plan of Reorganization), the provisional liquidators’ Bermuda law counsel, with the support of the Debtors, will apply for winding up orders in respect of each of the Bermuda Debtors. The join provisional liquidators will also seek formal recognition of the Confirmation Order from the United States Bankruptcy Court in Bermuda.

Please see "Item 4. Information on the company - B. Business Overview - Restructuring Agreement and Bankruptcy Proceedings under Chapter 11" for more information.

Contract award and extension for the West Elara and West Linus
On April 11, 2017, we announced the contract awards and extension for the jack-ups West Elara and West Linus with ConocoPhillips Skandinavia AS, or ConocoPhillips, for work in the Greater Ekofisk Area. The contracts are for a period of 10 years and the total additional backlog for the new contract awards is estimated at $1.4 billion, excluding performance bonuses. The contracts include market indexed dayrates and the estimated backlog is subject to change based on market conditions.

Capital Expenditures
We had total capital expenditures, including payments on long-term maintenance, of approximately $11.8 million, $22.1 million and $73.8 million in the years 2017, 2016 and 2015, respectively. Our capital expenditures relate primarily to our newbuild program, capital additions and equipment purchases to our existing drilling units and payments for long term maintenance. In May 2014, we reclassified $589.1 million from newbuilds to drilling units relating to the delivery of the West Linus. We financed our capital expenditures through cash generated from operations and secured and unsecured debt arrangements.

Newbuilding deferral
On December 2, 2015, as further extended in June 2016, August 2016, October 2016 and January 2017, we signed an amendment with Jurong for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel. The deferral period was until July 6, 2017, and we continued to market the unit for an acceptable drilling contract whilst the unit remained at Jurong yard in Singapore. On December 26, 2017, Jurong announced that a sale agreement, subject to conditions which had been signed for the West Rigel on April 5, 2018. We entered into a settlement and release agreement 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 consider this agreement provides additional evidence of the value of the asset held for sale at December 31, 2017, and have therefore reflected the agreed share of sales proceeds in the value of the asset held for sale at the balance sheet date. Please see Note 12 to our Consolidated Financial Statements included herein for further information.


30




Drilling Contract Terminations
On March 13, 2015, we received a termination notice from Rosneft of the drilling contract for the West Navigator. The drillship was scheduled to commence operations under a five-year contract with Rosneft during the summer of 2015. The termination of the drilling contract for the West Navigator reduced our contract backlog by $1.0 billion. We are currently marketing the West Navigator for alternative future opportunities.

On September 27, 2016, we received notice of termination from Statoil for the West Epsilon drilling contract. The West Epsilon was originally contracted for drilling services in Norway until the end of December 2016. In accordance with the termination provisions in the contract, we received a lump sum payment of approximately $11 million.

Rosneft Framework Agreement
On May 26, 2014, we entered into an investment and co-operation agreement, or the Investment and Co-Operation Agreement, with Seadrill and Rosneft to pursue onshore and offshore growth opportunities in the Russian market. In connection with the Investment and Co-Operation Agreement, we entered into the Framework Agreement with Seadrill and Rosneft, pursuant to which, among other things, Rosneft agreed to sell, and we agreed to purchase, 100% of the share capital of Rosneft’s Russian land drilling subsidiary, RN Burenie LLC, together with its subsidiaries, in exchange for such number of our newly issued common shares, based on an agreed share price of $9.25 per share, as payment of the agreed purchase price, subject to certain cash adjustments. The Framework Agreement provided for an original closing date of no earlier than November 10, 2014, which was first extended until May 31, 2015 and further extended until May 31, 2019.

The parties have agreed to use their reasonable endeavors to renegotiate, by no later than May 31, 2019, the terms of the transactions contemplated in the Framework Agreement, the characteristics of the transactions contemplated in the Framework Agreement and the terms of the related offshore drilling contracts. During this time, we are permitted to market our offshore drilling rigs subject to existing drilling contracts with Rosneft, enter into binding contracts with third parties in respect of those rigs, delay the mobilization of those rigs under the Rosneft contracts in order to comply with the terms of any contracts with third parties, delay the construction or delivery of any of those rigs, and extend the construction period or shipyard stay of any of those rigs.

In June 2015, the parties agreed to cancel any restrictions of business included in the terms of the Framework Agreement and replaced such restrictions with a requirement for us, subject to applicable law, to inform Rosneft of any material developments affecting us. We can provide no assurance that we will be able to reach an agreement with Rosneft by May 31, 2019. Even if an agreement is reached, the terms of such agreement may differ materially from the terms contemplated in the original Framework Agreement.

B.    Business Overview
We are an offshore drilling contractor focused on operations in the North Atlantic Region. While we currently operate exclusively offshore Norway and the United Kingdom, we intend to grow our position in the North Atlantic Region by continuing to provide excellent service to our customers with our modern, technologically advanced harsh environment fleet, together with our approximately 631 experienced and skilled employees. We contract our drilling units primarily on a dayrate basis for periods between one and five years to drill wells for our customers, typically oil super-majors and major integrated oil and gas companies, state-owned national oil companies and independent oil and gas companies.
Our drilling rigs are under contracts with major oil companies such as Statoil, ConocoPhillips and Nexen.

Restructuring Agreement and Bankruptcy Proceedings under Chapter 11
Over the past two years we, together with Seadrill, have been engaged in extensive discussions with our secured lenders and potential new money investors regarding the terms of a comprehensive restructuring. These discussions have also included an ad hoc committee of bondholders. The objectives of the restructuring are to build a bridge to a recovery and achieve a sustainable capital structure. Seadrill have proposed to achieve this by extending bank maturities, reducing fixed amortization, amending financial covenants and raising new capital.

On April 4, 2017 Seadrill reached an agreement with its banking group, including our secured lenders, to extend the comprehensive restructuring plan negotiating period until 31 July 2017. Further the related covenant amendments and waivers expiring on 30 June 2017 were extended to 30 September 2017 and lender consent was received to extend the maturity dates of certain facilities falling due within that period. This provided Seadrill and the Company additional time to advance ongoing negotiations regarding the terms of the comprehensive restructuring plan.

In July 2017, Seadrill reached an agreement with the bank group, including our secured lenders, to further extend the date by which a comprehensive restructuring plan must be agreed until September 12, 2017 providing an additional period for negotiations to continue over a comprehensive restructuring plan. We also extended the maturities of its $400 million credit facility and the $450 million credit facility provided to Seadrill Eminence Ltd to September 14, 2017.

The $440 million facility provided to Seadrill Eminence Ltd was further amended in August 2017 by way of a scheme of arrangement under section 99 of the Companies Act 1981 of Bermuda to align the maturity of the facility with that of (i) our $400 million credit facility and (ii) the revolving credit facility provided to NADL.


31




On September 12, 2017, we, together with Seadrill and certain of Seadrill’s consolidated subsidiaries (collectively, the Company Parties) entered into the RSA with the Consenting Stakeholders. Ship Finance International Limited 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 and a consortium of investors, including the bondholder parties to the RSA, committed to provide $1.06 billion in new cash commitments, subject to certain terms and conditions.

On September 12, 2017, to implement the transactions contemplated by the RSA and Investment Agreement, we, and the other Company Parties (collectively, the "Debtors") commenced prearranged Chapter 11 proceedings under the Bankruptcy Code in the Southern District of Texas [case number 17-60079]. During the course of the bankruptcy proceedings, the Debtors continue to operate their business as a debtor in possession.

On the Petition Date, the Bankruptcy Court issued certain additional customary interim and final orders with respect to the Debtors’ first day motions and other operating motions that allow the Debtors to operate their businesses in the ordinary course. The first-day motions provided for, among other things, the payment of certain pre-petition employee and retiree expenses and benefits, the use of the Debtors’ existing cash management system, the payment of certain pre-petition amounts to certain critical vendors, the ability to pay certain pre-petition taxes and regulatory fees, the payment of certain pre-petition claims owed on account of insurance policies and programs and authorizing the use of cash collateral.

Concurrent with the commencement of the prearranged reorganization proceedings in the Bankruptcy Court, Seadrill, NADL and Sevan (collectively, the “Bermuda Debtors”) commenced provisional liquidation proceedings pursuant to section 161 and 170 of the Bermuda Companies Act 1981 by presenting “winding up” petitions to the Bermuda Court. Upon the application of the Bermuda Debtors, the Bermuda Court appointed three joint provisional liquidators for each of the Bermuda Debtors. Under the order to appoint the joint provisional liquidators, the joint provisional liquidators’ powers are limited such that the Bermuda Debtors’ management team and boards of directors remain in control of the Bermuda Debtors’ day-to-day operations. Upon the appointment of the joint provisional liquidators in respect to each of the Bermuda Debtors, a statutory stay of proceedings in Bermuda against those three entities or their assets automatically arose. The next hearing in the Bermuda Court with respect to the “winding up” petitions was set for April 27, 2018. In addition to the statutory stay, as soon as practicable following the effective date (in accordance with the Plan of Reorganization), the provisional liquidators’ Bermuda law counsel, with the support of the Debtors, will apply for winding up orders in respect of each of the Bermuda Debtors. The join provisional liquidators will also seek formal recognition of the Confirmation Order from the United States Bankruptcy Court in Bermuda

On February 26, 2018 the Debtors filed a second amended joint Chapter 11 plan of reorganization, amended disclosure statement, amendment to the RSA, and amendment to the investment agreement. The amendments were the result of the Debtors reaching a global settlement with the Consenting Stakeholders and certain newbuild counterparties whereby certain creditor parties were included as Commitment Parties to the Investment Agreement, the size of the new cash infusion of the Investment Agreement increased from $1.06 billion to $1.08 billion, certain cash pools were established for the benefit of various creditor groups and also for the fees and expenses of their advisors, immediate cessation of all litigation and discovery efforts on the part of the creditor groups and committees was agreed, and a three month extension to the maturities of the senior credit facilities under the original terms of the RSA was agreed.

The RSA may be terminated upon the occurrence of certain events, including the failure to meet specified milestones relating to the filing, confirmation, and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the RSA. The RSA is subject to termination if the effective date of the Plan has not occurred within 11 months of the Petition Date. As a result, there is no assurance the confirmation and effectiveness of the Plan contemplating the RSA will occur.

Plan of Reorganization
Consistent with the RSA, 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 its various creditors, including an ad hoc group of holders of unsecured bonds and ship yards with the Debtors had a contractual relationship to build new rigs. On February 26, 2018, the Debtors announced a global settlement with the Ad Hoc Group, the official committee of unsecured creditors and other major creditors in its Chapter 11 cases, including Samsung Heavy Industries Co., Ltd. and Daewoo Shipbuilding & Marine Engineering Co., Ltd., two of the Debtors’ newbuild shipyards, and an affiliate of Barclays Bank PLC, 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 the inclusion of the Ad Hoc Group and Barclays into the Capital Commitment as Commitment Parties, increased recoveries for general unsecured creditors of Seadrill, NADL, and Sevan under the plan of reorganization, 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 of reorganization.

The Investment Agreement, as amended, provides for certain milestones for the Debtors’ restructuring: (1) the Bankruptcy Court must enter an order confirming the Plan by June 9, 2018 and (2) the effective date of the Plan must 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. On February 26, 2018, the Bankruptcy Court entered an order approving (i) the adequacy of the Disclosure Statement, (ii)

32




the solicitation and notice procedures with respect to confirmation of the Debtors’ proposed Plan, (iii) the rights offering procedures for the rights offerings contemplated by the Plan and (iv) other related matters. By the voting deadline of April 5, 2018, the Plan received approval from every single class of creditors and holders of interests entitled to vote, exceeding the required thresholds for acceptance of the Plan. The confirmation hearing for the Plan is currently scheduled for April 17, 2018. Assuming a confirmation of the Plan by the Bankruptcy Court, once each of the conditions precedent to the Plan’s effectiveness have been satisfied or waived, the Plan will become effective and each of the Debtors will emerge from the Chapter 11 proceedings.

The Plan provides for, among other things, that:

Seadrill Limited and North Atlantic Drilling Ltd will be dissolved under the laws of Bermuda following the confirmation of the Plan;
the Debtors will enter into amended senior credit facilities with its senior credit facility lenders;
holders of general unsecured claims will receive 15% of the common stock of Seadrill Limited’s successor, “New Seadrill” (such shares, “New Seadrill Common Shares”) (prior to dilution by the Primary Structuring Fee and the Employee Incentive Plan as defined below under “-Issuance and Distribution of the New Securities under the Plan and the Investment Agreement”);
the Debtors will conduct the rights offerings described below under “-Rights Offering,” with certain non-eligible holders of general unsecured claims entitled to participate pro rata in a $23 million cash recovery pool;
an additional $17 million in cash will be distributed to holders of general unsecured claims, other than claims held by the Commitment Parties as of September 12, 2017 or January 5, 2018, as applicable;
an additional $17 million in cash, less fees and expenses, will be distributed to the shipyards; and
if the general unsecured claims vote in favor of the Plan, holders of Seadrill’s existing equity will receive 2% of the New Seadrill Common Shares (prior to dilution by the Primary Structuring Fee and the Employee Incentive Plan defined below under “-Issuance and Distribution of the New Securities under the Plan and the Investment Agreement”).

Assuming that the Plan is confirmed and becomes effective, we expect our existing common stock will be cancelled on the effective date of the Plan, with no recoveries to holders of our common stock, and we will become a wholly owned subsidiary of Seadrill.

The RSA may be terminated upon the occurrence of certain events, including the failure to meet specified milestones relating to the filing, confirmation, and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the RSA. The Restructuring Support Agreement is subject to termination if the effective date of the Plan has not occurred within 11 months of the Petition Date. As a result, there is no assurance the confirmation and effectiveness of the Plan contemplating the RSA will occur.

Rights Offerings

Pursuant to the Plan and an order of the Bankruptcy Court approving the rights offering procedures, eligible holders in certain classes of general unsecured claims against the Debtors will be offered the right to participate in (i) a rights offering (the “Notes Rights Offering”) of up to $119.1 million in aggregate principal amount of new secured notes (“New Secured Notes”) to be issued by a subsidiary of New Seadrill (“NSNCo”) and a corresponding pro rata portion of 57.5% of New Seadrill Common Shares issued to holders who participate in the Notes Rights Offering and (ii) a rights offering of up to $48.1 million in value of New Seadrill Common Shares (the “Equity Rights Offering”). The New Secured Notes and the New Seadrill Common Shares to be acquired by the Commitment Parties under the Investment Agreement will be reduced to the extent the rights are exercised in each of the Notes Rights Offering and the Equity Rights Offering. The Commitment Parties will not participate in either the Notes Rights Offering or the Equity Rights Offering in accordance with the terms of the Investment Agreement.

Issuance and Distribution of the New Securities under the Plan and the Investment Agreement

Subject to the terms and conditions of the Plan and the Investment Agreement, on the Effective Date, (i) NSNCo will issue approximately $880 million in principal amount of New Secured Notes; and (ii) New Seadrill expects to issue:

up to 25% of the New Seadrill Common Shares (prior to dilution by the Primary Structuring Fee and the Employee Incentive Plan), plus any excess New Seadrill Common Shares, in exchange for $200 million paid in cash by the Commitment Parties to the Investment Agreement, which amount paid by the Commitment Parties will be reduced by an amount up to $48.1 million paid by participants in the Equity Rights Offering;
up to 57.5% of the New Seadrill Common Shares (prior to dilution by the Primary Structuring Fee and the Employee Incentive Plan) to the purchasers of the New Secured Notes, which will include the Commitment Parties and the participants in the Notes Rights Offering, on a pro rata basis in accordance with the amount of New Secured Notes issued to such purchasers;
(i) 5% of the New Seadrill Common Shares (prior to dilution by the Employee Incentive Plan) to Hemen on account of a primary structuring fee (the “Primary Structuring Fee”) and (ii) 0.5%
of the New Seadrill Common Shares to certain other Commitment Parties (prior to dilution by the Primary Structuring Fee and the Employee Incentive Plan) on a pro rata basis in accordance with each such Commitment Party’s respective equity commitment percentage.


33




Subject to the conditions of the Investment Agreement, the Commitment Parties agreed to purchase the full principal amount of the New Secured Notes and the associated 57.5% of the New Seadrill Common Shares (prior to dilution by the Primary Structuring Fee and the Employee Incentive Plan) for $880 million in cash, less the principal amount purchased by participants in the Notes Rights Offering.

On the Effective Date, an employee incentive plan will be implemented by New Seadrill (the “Employee Incentive Plan”) which will (a) reserve an aggregate of 10% of the New Seadrill Common Shares, on a fully diluted, fully distributed basis, for grants made from time to time to employees of New Seadrill; and (b) 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 New Seadrill.

Assuming that the Plan is confirmed and becomes effective, we expect our existing common stock will be cancelled on the effective date of the Plan, with no recoveries to holders of our common stock, and we will become a wholly owned subsidiary of Seadrill.

Our Business Strategies
Our operations are focused on state-of-the-art offshore drilling units primarily in harsh environments and the North Atlantic Region. We believe we have one of the most capable fleets in this sector of the drilling industry and believe that by combining quality assets with experienced and skilled employees we will be able to provide our customers with safe and effective operations, and establish, develop and maintain a position as a preferred provider of harsh environment drilling services for our customers.

We intend to leverage the relationships, expertise and reputation of Seadrill to assist in re-contracting our fleet under long-term contracts. Seadrill is one of the world’s largest international offshore drilling contractors and owned 70.4% of our outstanding common shares as of the date of this annual report. We are highly dependent on Seadrill to provide liquidity and support our operations. Please see "Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources" and "Item 3. Information on the Company—D. Risk Factors" for more information.

The key elements in our strategy are as follows:
commitment to provide customers with safe and effective operations;
combine state-of-the-art mobile drilling units with experienced and skilled employees; and
focus and develop our strong position in harsh environments.

Management of Our Business
Our Board of Directors has the authority to oversee and direct our operations, management and policies on an exclusive basis. Our Board of Directors has organized the provision of certain management and other services through North Atlantic Management, our wholly-owned subsidiary, and Seadrill Management Limited, a wholly-owned subsidiary of Seadrill.

North Atlantic Management provides support functions to the Company and its subsidiaries in accordance with the terms of the general management agreement, or the General Management Agreement. North Atlantic Management is responsible for, among other things, corporate governance services, budgeting and accounting functions, the financing of our activities, commercial management including marketing of our drilling rigs, and the purchase and sale of assets.

North Atlantic Management employs our senior management, including our Chief Executive Officer. Our Chief Financial Officer has been provided to North Atlantic Management from Seadrill Management, a subsidiary of Seadrill. North Atlantic Management has contracted in certain other management services from Seadrill Management in accordance with the terms of the Services Agreement. In addition, the costs attributable to one of our directors is charged from Seatankers. The agreement can be terminated by either party upon one month's notice. In consideration of the services provided, we will pay Seadrill a fee that includes the operating costs attributable to us plus a margin of 8%.

Pursuant to the Services Agreement and the General Management Agreement (which is a general management agreement between us and North Atlantic Management), supporting activities are provided by Seadrill Management and North Atlantic Management. Seadrill Management’s offices are located at Building 11, 2nd Floor, Chiswick Business Park, 566 Chiswick High Road, London W4 5YS, United Kingdom, and North Atlantic Management’s offices are located at Drammensveien 228, 0283 Oslo, P.O. Box 224, 1326 Lysaker, Norway. North Atlantic Management's telephone number at that address is +47 51 30 90 00. North Atlantic Management also has offices in Bergen and Stavanger, Norway and Aberdeen, United Kingdom.

Market Overview
We operate within the harsh environment segment of the offshore drilling market, which constitutes a part of the international oil and gas service industry. Our operating fleet of seven harsh environment offshore drilling rigs consists of one ultra-deepwater drillship, three semi-submersibles and three jack-up rigs. While we currently operate exclusively in Norway and the United Kingdom, we pursue harsh environment drilling operations in other locations in the North Atlantic Region. The North Atlantic Region has historically offered long-term contracts, high utilization and competitive dayrates compared to the international offshore drilling market for similar drilling rigs.

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

34




and many other factors. 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 also affect customers’ drilling programs. Oil and gas prices are volatile, which has historically led to significant fluctuations in expenditures by customers for drilling services. Variations in market conditions impact us in different ways, depending primarily on the length of drilling contracts we have for our rigs. Short-term changes in these markets may have a minimal short-term impact on revenues and cash flows, unless the timing of contract renewals coincides with short-term movements in the market.

The Global Fleet of Drilling Units
The global fleet of offshore drilling units consists of drillships, semi-submersible rigs, jack-up rigs and tender rigs. Currently, the existing worldwide fleet totals 816 units including 116 drillships, 144 semi-submersible rigs, 526 jack-up rigs and 30 tender rigs. In addition, there are 28 drillships, 14 semi-submersible rigs, 90 jack-up rigs and 6 tender rigs under construction. The water depth capabilities vary depending on type and design of the rigs. Jack-up rigs normally work in water depths up to 450ft while semi-submersible rigs and drillships can work in water depths up to 12,000ft. Tender rigs work in water depths up to 410ft for tender barges and up to 6,000ft for semi-tenders. All offshore rigs are capable of working in benign environment, but there are certain additional requirements for rigs to operate in harsh environments due to extreme marine and environmental conditions. The number of rigs outfitted for such operations are limited, and the present number of rigs operating in harsh environments in Norway and the United Kingdom total 54 rigs, of which there are 37 floaters and 17 jack-ups.

Seasonality
In general, seasonal factors do not have a significant direct effect on our business as typical drilling contracts are based on long-term demand from oil companies and the cyclical nature in the contract drilling market is normally multi-year. However, the 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 winter season offshore Norway and the United Kingdom.

Employment of Our Fleet
Our customers consist primarily of major integrated oil companies. We currently have contracts with ConocoPhillips, Total and Statoil.

Our contract backlog includes firm commitments only, which are represented by signed drilling contracts. As of March 31, 2018, our contract backlog was approximately $1,533 million, and was attributable to revenues we expect to generate from all of our drilling rigs. We calculate our contract backlog by multiplying the contractual dayrate by the minimum expected number of days committed under the contracts (excluding options to extend), assuming full utilization. The actual amount of revenues earned and the actual periods during which revenues are earned may differ from the amounts and periods shown in the table below due to, for example, shipyard and maintenance projects, downtime and other factors that result in lower revenues than our average contract backlog per day.

The actual amount of revenues earned may also fluctuate due to parts of the dayrates being received in Norwegian kroner. Approximately 20% to 50% of the dayrates are payable in Norwegian kroner, which approximately corresponds to the amount of operational expenses paid in Norwegian kroner. As a result, our net operational profit measured in U.S. dollars is minimally affected by currency fluctuations on a historical basis even though operational expenses and revenues may be affected individually. Norwegian kroner elements of future contract revenue and dayrate information provided throughout this annual report have been converted into U.S. dollars using an exchange rate of USD $1 to NOK8.21, as of December 31, 2017. In addition, we may enter into drilling contracts that contain bonus payments in excess of the stated dayrate if we meet certain agreed operational objectives under the applicable contract.


35




The firm commitments that comprise our contract backlog as of March 31, 2018 are as follows.
Drilling Rig
Contracted
Location
 
Customer 
Contractual
Daily Rate
 
$'000s
Contract Start
Date
  
Earliest
Expiration
Date
 
West Alpha
Norway
Available (4)
$—
West Elara
Norway
ConocoPhillips (1)
$95
March 4, 2018
August 31, 2018
$195
August 31, 2018
March 31, 2020
market rate including agreed percentage discount
April 1, 2020
September 30, 2027
West Epsilon
Norway
Available (3), (4)
$—
West Linus
Norway
ConocoPhillips (2)
$205
April 1, 2018
May 25, 2019
market rate including agreed percentage discount
June 1, 2019
December 31, 2028
West Navigator
Norway
Available (4)
$—
West Phoenix
UK
Total
$140
May 1, 2018
July 5, 2018
Nexen
$267
January 1, 2020
October 27, 2020
West Venture
Norway
Available (4)
$—
 
For our drilling rigs operating in Norway, the dayrates listed in the table above include adjustments, as applicable, effective from July 1, 2013, pursuant to the NR (Norges Rederiforbund) tariff, a Norwegian offshore industry tariff. The daily rate for the West Phoenix, which operates in the United Kingdom, is subject to annual rate revisions based on changes in indices derived from the U.S. Department of Labor, Bureau of Labor Statistics.

(1)
The West Elara contract with ConocoPhillips is expected to commence in August 2018 and includes a period of fixed dayrates until March 2020 and contributes approximately $113 million of contract backlog. A market indexed rate is applicable thereafter until September 2027, which we believe will contribute an estimated $530 million of contract backlog.
(2)
The West Linus contract with ConocoPhillips has been extended from May 2019 until the end of 2028 at a market indexed dayrate, which we believe will contribute an estimated $677 million of contract backlog. As part of the agreement, we have agreed to a dayrate adjustment on the existing West Linus contract effective from April 2017, resulting in an approximate $58 million reduction in current backlog.
(3)
In September 2016, we received a notice of termination from Statoil for the West Epsilon drilling contract. Pursuant to the termination provisions in the contract, we received a lump sum payment of approximately $11 million.
(4)
The West Alpha, West Epsilon, West Navigator, and West Venture are currently cold stacked.

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. The table below shows the percentage of our consolidated revenues attributable from each customer, including certain of their subsidiaries, for the years ended December 31, 2017, 2016 and 2015:
Contract revenue split by client:
 
Year ended December 31,
 
 
2017
 
2016
 
2015
Statoil
 
32
%
 
40
%
 
44
%
ExxonMobil
 
%
 
25
%
 
25
%
Conoco Phillips
 
49
%
 
25
%
 
18
%
Total
 
8
%
 
10
%
 
13
%
Nexen
 
11
%
 
%
 
%
Total
 
100
%
 
100
%
 
100
%

Our contract backlog, as of March 31, 2018, totaled approximately $1.5 billion. Of the total contract backlog, $0.1 billion is attributable to our semi-submersible rigs and drillships and $1.4 billion attributable to our jack-up units. We expect approximately $0.03 billion of our contract backlog to be realized in the remainder of 2018. Contract backlog for our drilling fleet is calculated as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Contract backlog excludes revenues for mobilization and demobilization, contract preparation, and customer reimbursables.  The amount of actual revenues earned and the actual periods during which revenues are earned will be different from the backlog projections due to various factors.  Downtime, caused by unscheduled repairs, maintenance, weather and other operating factors, may result in lower applicable dayrates than the full contractual operating dayrate.


36




All of our drilling contracts have fixed terms, but may be terminated early due to certain events or we may be unable to realize revenue under these contracts in the event of unanticipated developments, such as the deterioration in the general business or financial condition of a customer, resulting in its inability to meet its obligations under our contracts.

In light of the current environment, we are encountering and may in the future encounter situations where counterparties request relief to contracted dayrates or seek early contract termination. In the event of early termination for the customer's convenience, an early termination amount is typically payable to us, in accordance with the terms of the drilling agreement. While we are confident that our contract terms are enforceable, we may be willing to engage in discussions to modify such contracts if there is a commercial agreement that is beneficial to both parties. Please refer to “Item 3. Key Information-D. Risk Factors-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.”

Competition
The offshore drilling industry is highly competitive, with market participants ranging from large multinational companies to smaller companies with fewer than five drilling rigs.

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. For example, contracts in shallow waters for jack-up rig activities are shorter term, so a deterioration or improvement in market conditions for such units tends to quickly impact revenues and cash flows from those operations. On the other hand, contracts in deepwater for semi-submersible rigs and drillships tend to be longer term, so a change in market conditions tends to have a more delayed impact. Accordingly, short-term changes in these markets may have a minimal short-term impact on revenues and cash flows, unless the timing of contract renewals coincides with short-term movements in the market.

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, condition and integrity of equipment, its record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and client relations.

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 modifications of the drilling rig and its equipment to specific regional requirements. For example, drilling rigs operating in the North Atlantic Region and in other harsh environment drilling locations require specialized equipment and modifications, including without limitation, unique structuring of drilling rig hulls and protection from exposure to weather and low temperatures. Not all rigs can be modified to operate in harsh environment conditions. The large investment in specialized or modified drilling equipment required to operate in harsh environment conditions creates barriers to entry. In addition, Norway imposes added requirements for drilling facilities, including, among other things, strict standards relating to safety, drilling rig technical specifications, crew accommodations and certain other compliance measures, known as Acknowledgment of Compliance, or AOC, which must be satisfied in order to operate in the Norwegian Continental Shelf. All of our drilling rigs meet, or are being constructed to meet, AOC requirements.

We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future. While we believe that our fleet of well-maintained and technologically advanced drilling rigs provides us with a competitive advantage over competitors with older fleets, as our drilling rigs are generally better suited to meet the requirements of customers for drilling in harsh environments, certain competitors may have greater financial resources than we do, which may enable them to better withstand periods of low utilization, and compete more effectively on the basis of price.

For further information on current market conditions and global offshore drilling fleet, please refer to “Item 5. Operating and Financial Review and Prospects—D. Trend Information.”

Environmental and Other Regulations

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 permit 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. Please 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 us to liability, or limit our drilling activity.”

Flag State Requirements

37




All of our drilling units are subject to regulatory requirements of the flag state where the drilling unit is registered. These include engineering, safety and other requirements related to the drilling industry and to maritime vessels in general. 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.

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.”

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, recent 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 subject to a feasibility review. The amendments also establish new tiers of stringent nitrogen oxide emissions standards for new marine engines, depending on their date of installation. All of our rigs are in compliance with these requirements.

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 our units considered in operational status are in full compliance with the staged implementation of the BWM Convention by International Maritime Organization guidelines.

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.”


38




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 the safety regulations applicable to our industry following the 2010 Deepwater Horizon incident, in which we were not involved, that led to the Macondo well blow out situation. Other countries are also 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 April 2016, the U.S. Department of the Interior’s Bureau of Safety and Environmental Enforcement (“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. The rule adds new requirements and amends existing ones to, among other things, set new baseline standards for the design, manufacture, inspection, repair and maintenance of blow-out preventers and the use of double shear rams. The rule contains a number of other requirements, including third-party verification and certifications, real-time monitoring of deepwater and certain other activities, and sets criteria for safe drilling margins. In December 2017, BSEE proposed to revise or eliminate certain of the requirements under the rule. To the extent these requirements remain in effect, they are likely to increase the costs of our operations and may lead our customers to not pursue certain offshore opportunities because of the increased costs, delays and regulatory risks. In July 2016, U.S. Department of the Interior’s Bureau of Ocean Energy Management (“BOEM”) issued a final Notice to Lessees and Operators substantially revising and making more stringent supplemental bonding procedures for the decommissioning of offshore wells, platforms, pipelines, and other facilities. In June 2017, BOEM announced that the implementation timeline would be extended, except in circumstances where there is a substantial risk of nonperformance of such obligations. In addition, in December 2015, BSEE announced that it is launching a pilot risk-based inspection program for offshore facilities. New requirements resulting from the program may cause us to incur costs and may result in additional downtime for our drilling units in the U.S. Gulf of Mexico. Also, if material spill events similar to the Deepwater Horizon incident were to occur in the future, the United States or other countries could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue additional safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The EU has also undertaken a significant revision of its safety requirements for offshore oil and gas activity through the issuance of the EU Directive 2013/30 on the Safety of Offshore Oil and Gas Operations.

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.

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. Although these requirements have not had material impact on our operations in the past, they could have a material impact on our earnings, operations and financial condition in the future.

Norwegian Regulation
Our drilling operations in Norway are governed by various regulations relating to environmental safety. The Norwegian Petroleum Act of November 29, 1996, or the Petroleum Act, gives Norway the exclusive right to award licenses for development, exploration and production projects in Norwegian fields. Such licenses are granted by the Norwegian Ministry on Petroleum and Energy, and as holders of such licenses, we are subject to strict liability for any pollution damage suffered as a result of a petroleum leak by facilities for which we hold licenses. Under the Petroleum Act, we are also subject to certain health, safety and environment regulations, which require us to conduct our operations with a reasonable standard of care, taking into consideration the safety of our employees and the environment. Other regulations proscribed by the Norwegian Ministry on Petroleum and Energy and the Norwegian Ministry of the Environment may also affect our operations.

The Norwegian Petroleum Safety Authority oversees technical and operational safety, emergency preparedness and the environment. Each drilling facility operating on the Norwegian Continental Shelf must obtain an Acknowledgement of Compliance, or AOC. The AOC is a government-issued certificate that acknowledges compliance with Norway’s laws and regulations relating to safety and emergency preparedness, drilling rig technical specifications, crew accommodations, management systems, and other requirements. Such certificates are granted upon successful completion of an inspection by Petroleum Safety Authority, based on information that a company provides about its facility, as well as any information gathered by the Norwegian Petroleum Safety Authority in its follow-up review of a drilling facility. An AOC alone does not grant a company the right to begin operations on the Norwegian Continental Shelf, but it is mandatory for most petroleum operations in that location, including drilling, production, storage, and offloading facilities. All of our drilling rigs meet the specifications required by the Petroleum Safety Authority and we have obtained an AOC for each of our drilling rigs that are currently in operation.

United Kingdom Regulation
Drilling activities in the United Kingdom are subject to environmental regulations. Under the Petroleum Act 1998, oil and gas companies are required to obtain approval from the U.K. Department for Business, Energy and Industrial Strategy, or BEIS (formerly the Department of Energy and Climate Change, or the DECC) prior to the commencement of any drilling activity onshore or on the U.K. Continental Shelf.

Our activities in the United Kingdom must comply with the regulations adopted by the U.K. Health and Safety Executive, or the HSE, including the Offshore Installations Prevention of Fire and Explosion, and Emergency Response (PFEER) Regulations 1995. In order to comply with the U.K. Offshore

39




Installations (Safety Case) Regulations 2005, we are also required to submit a periodic safety case report, or Safety Case, to the HSE as a measure of our ability to control risks and appropriately implement health and safety management systems for each of our rigs operating in the U.K. The Safety Cases are subject to revision every five years, however the HSE can require resubmission earlier particularly in the event any of the contents or assumptions of the original Safety Case materially changes during the five-year period. The HSE also requires that we keep our operating risks “as low as reasonably practicable.”

As of the date of this annual report, two of our units, the West Phoenix and the West Navigator, have obtained acceptance of their Safety Cases for drilling operations in the United Kingdom.

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.
Risk of Loss and Insurance Coverage
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, destroy the equipment involved or cause serious environmental damage. Offshore drilling contractors such as us are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our marine insurance package policy provides insurance coverage for physical damage to our drilling rigs, loss of hire and third-party liability.

a) Physical Damage Insurance
Seadrill purchases hull and machinery insurance to cover for physical damage to its drilling rigs and charges us for the cost related to our fleet. We retain the risk for the deductibles relating to physical damage insurance on our rig fleet. The deductible is currently a maximum of $5 million per occurrence.

b) Loss of Hire Insurance
Seadrill purchases insurance to cover for loss of revenue in the event of extensive downtime caused by physical damage to its drilling rigs, where such damage is covered under Seadrill’s physical damage insurance, and charges us for the cost related to our fleet. We retain the risk related to loss of hire during the initial 60 days after the occurrence of physical damage. Thereafter, insurance policies according to which we are compensated for loss of revenue are limited to 210 days per event and aggregated per year. The daily indemnity will vary from 75% to 100% of the contracted dayrate. We retain the risk that the repair of physical damage takes longer than the total number of days in the loss of hire policy.

c) Protection and Indemnity Insurance
Seadrill purchases protection and indemnity insurance and excess liability 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 per event and in aggregate. In the event of no drilling activities, the excess liability insurance is suspended and therefore the limit is reduced from $500 million to $350 million. We retain the risk for the deductible of up to $25,000 per occurrence relating to protection and indemnity insurance.

C.     Organizational Structure
North Atlantic Drilling Ltd. is a company organized under the laws of Bermuda. We are a majority owned subsidiary of Seadrill, which owns approximately 70.4% of our outstanding common shares as of the date of this annual report. We own our drilling rigs through separate wholly-owned subsidiaries that are incorporated in Bermuda. If the Plan is confirmed and becomes effective, we expect we will become a wholly owned subsidiary of Seadrill.
Please see Exhibit 8.1 to this annual report for a list of our current subsidiaries.


40




D.    Property, Plants and Equipment

Our Fleet
Our fleet of seven harsh environment offshore drilling rigs consists of three semi-submersibles, one ultra-deepwater drillship and three jack-up rigs. The following table sets forth certain information regarding our drilling rigs as of the date of this annual report:
Drilling Rig
Generation /
Type
Year Built 
Water
Depth
Capacity
(in feet) 
Drilling
Depth
Capacity
(in feet) 
Floaters
 
 
 
 
Semi-Submersibles
 
 
 
 
West Phoenix
6th - HE
2008
10,000
30,000
West Venture
5th - HE
2000
2,600
30,000
West Alpha
4th - HE
1986
2,000
23,000
Drillship
 
 
 
 
West Navigator
Ultra-deepwater - HE
2000
7,500
35,000
Jack-ups
 
 
 
 
West Epsilon
HD - HE
1993
400
30,000
West Elara
HD - HE
2011
450
40,000
West Linus (1)
HD - HE
2014
450
40,000
 _____________

(1)
Pursuant to a sale and leaseback agreement, we sold the West Linus to Ship Finance, and the rig has been chartered back to us on a bareboat charter for a period of 15 years from its delivery date on February 18, 2014. In accordance with accounting principles generally accepted in the United States, or U.S. GAAP, we consolidate SFL Linus Ltd., the Ship Finance subsidiary that owns the rig, in our consolidated financial statements. See “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions.”


In December 2015, we agreed with Jurong Shipyard ("Jurong") to defer delivery of the semi-submersible drilling unit, the West Rigel, to June 2, 2016, and subsequently to July 6, 2018. At the end of the deferral period, if we have not secured acceptable employment for the rig, it will be sold into a joint asset holding company with Jurong, to be owned 23% by us and 77% by Jurong. On December 26, 2017, Jurong announced that a sale agreement, subject to conditions, had been signed for West Rigel. As the agreement is pursuant to conditions being met, we will continue to hold the asset within "Non-current assets held for sale".

ITEM 4A.    UNRESOLVED STAFF COMMENTS
None.

ITEM 5.    OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following presentation of management’s discussion and analysis of results of operations and financial condition should be read in conjunction with our consolidated financial statements and accompanying Notes thereto, included herein. You should also carefully read the following discussion with the sections of this annual report entitled “Cautionary Statements 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, and we draw your attention to the statement regarding going concern as described in Note 1 "General information".

Overview
We provide drilling and related services to the offshore oil and gas industry, and are focused on operations in the North Atlantic Region, which includes only the territorial waters and outer continental shelf jurisdiction of Norway, the United Kingdom, Ireland, Denmark, the Netherlands, the east coast of Greenland, Russia (west of the island of Diksonskiy), and all countries within the Baltic Sea and the Gulf of Bothnia.

Restructuring Agreement and Bankruptcy Proceedings under Chapter 11
On September 12, 2017, we, along with our parent company Seadrill and the other Company Parties, entered into the RSA with the Consenting Stakeholders. In connection with the amendment to the RSA on February 26, 2018, the Company Parties, entered into the investment agreement under which the Commitment Parties committed to provide $1.08 billion in new cash commitments, subject to certain terms and conditions. To implement

41




the transactions contemplated by the RSA and Investment Agreement, the Debtors commenced prearranged Chapter 11 proceedings under the Bankruptcy Code in the Southern District of Texas.

As described in Item 3D, upon the filing of voluntary petitions to restructure under the protections Chapter 11 of the Bankruptcy Code, we operate the business as debtors-in-possession under supervision of the Bankruptcy Court. Debtors-in-possession status requires that we obtain approval of the Bankruptcy Court with respect to our business, and in some cases, the Consenting Stakeholders under the terms of the RSA and the Commitment Parties under the terms of the Investment Agreement, prior to engaging in certain activities or transactions. Accordingly, ultimate discretion of many operational and non-routine activities is subject to final supervision of the Bankruptcy Court and does not reside in solely with management.

For periods subsequent to filing for bankruptcy, we have prepared our consolidated financial statement in accordance with Accounting Standards Codification 852, Reorganizations ("ASC 852"). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Pre-petition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. Please see "Note 1 - General information - Basis of Preparation" and "Note 3 - Chapter 11 Proceedings" for further information.

Please see "Item 4. Information on the company - B. Business Overview - Restructuring Agreement and Bankruptcy Proceedings under Chapter 11" for information on the Restructuring Agreement and Bankruptcy Proceedings.

Our Fleet
For certain information regarding our drilling units, please see “Item 4. Information on the Company—D. Property, Plants and Equipment—Our Fleet.”

Factors Affecting our Results of Operations
The principal factors that we believe have affected our results and are expected to affect our future results of operations and financial position include:
our ability to successfully employ our drilling units at economically attractive dayrates as long-term contracts expire or are otherwise terminated;
the ability to maintain good relationships with our existing customers and to increase the number of customer relationships;
the number and availability of our drilling units,
fluctuations and current decline in the price of oil and gas, which influence the demand for offshore drilling services;
the effective and efficient technical management of our drilling units;
our ability to obtain and maintain major oil and gas company approvals and to satisfy their quality, technical, health, safety and compliance standards;
economic, regulatory, political and governmental conditions that affect the offshore drilling industry;
accidents, natural disasters, adverse weather, equipment failure or other events outside of its control that may result in downtime;
mark-to-market changes in interest rate swaps;
foreign currency exchange gains and losses;
increases in crewing and insurance costs and other operating costs;
the level of debt and the related interest expense and amortization of principal;
the impairment of goodwill, investments, drilling units and other assets;
our restructuring process and the potential future implementation of fresh start accounting on emergence from Chapter 11;
gains on disposals of assets;
interest and other financial items; and
tax expenses.

Please see “Item 3. Key Information—D. Risk Factors” for a discussion of certain risks inherent in our business.

Important Financial Terms and Concepts

Contract revenues
In general, we contract our drilling units to oil and gas companies to provide offshore drilling services at an agreed dayrate for a specified contact 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.

42





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. We recognize revenue for mobilization, capital upgrades and non-contingent demobilization fees on a straight-line basis over the expected contract term. We recognize revenue for contingent demobilization fees as earned upon completion of the 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.

In certain countries, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on our revenues. We record tax-assessed revenue transactions on a net basis in the consolidated statement of income.

Other revenues
Other revenues include amounts recognized as early termination fees under the drilling contracts that have been terminated prior to the contract end date. Contract termination fees are recognized as and when any contingencies or uncertainties associated with our right to receive are resolved.

Economic Utilization
Economic utilization is calculated as the total revenue, excluding bonuses, received divided by the full operating dayrate multiplied by the number of days on contract in the period.

If a drilling unit earns its full operating dayrate throughout a reporting period its economic utilization would be 100%. However, there are many situations that give rise to a dayrate being earned that is less than the contractual operating rate. In such instances economic utilization reduces below 100%.
Examples of situations where the drilling unit would operate at reduced operating dayrates, include, among others, a standby rate, where the rig is prevented from commencing operations for reasons such as bad weather, waiting for customer orders, waiting on other contractors; a moving rate, where the drilling unit is in transit between locations; a reduced performance rate in the event of major equipment failure; or a force majeure rate in the event of a force majeure that causes the suspension of operations. In addition, the drilling unit could operate at a zero rate in the event of a shutdown of operations for repairs where the general repair allowance has been exhausted or for any period of force majeure in excess of a specific number of days allowed under a drilling contract.

Reimbursable Revenues and Expenses
Reimbursable revenues are revenues that constitute reimbursements from our customers for reimbursable expenses. Reimbursable expenses are expenses we incur on behalf, and at the request, of customers, and include provision of supplies, personnel and other services that are not covered under the drilling contract.

Gain/Loss on disposal
From time to time we may sell, or otherwise dispose of, drilling units, businesses, and other fixed assets, to external parties or related parties. In addition, assets may be classified as "held for sale" on our balance sheet when, among other things, we are committed to a plan to sell assets, and consider a sale probable within twelve months. We may recognize a gain/loss on disposal depending on whether the fair value of the consideration received is higher/lower than the carrying value of the asset.

Operating Expenses    
Our operating expenses consist primarily of vessel and rig operating expenses, amortization of favorable contracts, reimbursable expenses, the impairment of goodwill and drilling units, depreciation and amortization, and general and administrative expenses.

43




Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked. This includes the personnel costs of offshore crews, running costs of the rigs, expenditures for repairs and maintenance activities and costs for onshore personnel that provide operational support to the rigs.
Amortization of favorable contracts is amortization expense for acquired drilling contracts with above market rates. Where we acquire an in-progress drilling contract at above market rates through a business combination we record an intangible asset equal to its fair value on the date of acquisition. The asset is then amortized on a straight-line basis over its estimated remaining contract term.
Loss on impairment of goodwill and drilling units is based on management’s review of these assets for impairment, which is done at least once each year or more often if there are factors indicating that it is more likely than not that the fair value of these assets will be lower than their respective carrying value. Please see “-Critical Accounting Estimates” below for further information.
Depreciation and amortization costs are based on the historical cost of our drilling units. Drilling units 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 economic useful life of our rigs, when new, is 30 years. Costs related to periodic surveys and other major maintenance projects are capitalized as part of drilling units and amortized over the anticipated period covered by the survey or maintenance project, which is up to five years. These costs are primarily shipyard costs and the cost of employees directly involved in the work. Amortization costs for periodic surveys and other major maintenance projects are included in depreciation and amortization expense.
General and administrative expenses include the costs of our corporate and regional offices in various locations, legal and professional fees, property cost as well as the remuneration and other compensation of our officers, directors and employees engaged in the management and administration of our Company.

Financial items and other income/expense
Our financial items and other income/expense consist primarily of interest income, interest expense, gain/loss on derivative financial instruments, foreign exchange gain/loss and other non-operating income or expenses.
The amount of interest expense recognized depends on the overall level of debt we have incurred and prevailing interest rates for our agreements. However, overall interest expense may be reduced as a consequence of capitalization of interest expense relating to drilling units under construction. The filing of the bankruptcy petition constituted an event of default with respect to our existing debt obligations. Accordingly, our pre-petition secured and unsecured indebtedness became immediately due and payable and any efforts to enforce such payment obligations are automatically stayed as a result of Chapter 11 cases. Please see "Note 3 Chapter 11 Proceedings - Interest Expense" for further information.
Gains/losses recognized on derivative financial instruments reflect various mark-to-market adjustments to the value of our interest rate and forward currency swap agreements and other derivative financial instruments, and the net settlement amount paid or received on swap agreements. Any related changes in fair value as a result of changes in our own and counterparty credit risk may have a significant impact on our results of operations and financial position.
Foreign exchange gains/losses recognized generally relate to transactions and revaluation of balances carried in currencies other than the U.S. dollar.
"Reorganization items, net" included in the Consolidated Statement of operations includes income, expenses and gains and losses directly associated with reorganization proceedings and include; professional fees directly associated with the Chapter 11 proceedings, unamortized debt issuance costs written off, gains/losses on pre-petition allowable claims and interest income on surplus cash.
Other non-operating income or expense relate to items which generally do not fall within any other categories listed above.

Income taxes
Income tax expense reflects current tax payable and deferred taxes related to our drilling unit owning and operating activities and may vary significantly depending on jurisdictions and contractual arrangements. In most cases the calculation of tax is based on net income or deemed income, the latter generally being a function of gross turnover.

Critical Accounting Estimates
The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that we believe to be reasonable. Our critical accounting estimates are important to the portrayal of both our financial condition and results of operations and require us to make subjective or complex assumptions or estimates about matters that are uncertain. The basis of preparation and our significant accounting policies are discussed in "Note 1–General Information" and "Note 2–Accounting Policies" of our consolidated financial statements appearing elsewhere in this annual report. The following are what we believe to be the critical accounting estimates used in the preparation of the consolidated financial statements. In addition, there are other items within the consolidated financial statements that require estimation.

Drilling Units
The carrying amount of our drilling units is subject to various estimates, assumptions, and judgments related to capitalized costs, useful lives and residual values and impairments. At December 31, 2017 and 2016, the carrying amount of our drilling units was $2.3 billion and $2.5 billion, representing 89% and 87% of our total assets, respectively.


44




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 economic useful life of our semi-submersible drilling rigs, drillships and tender 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.

We determine the carrying value of our assets based on policies that incorporate estimates, assumptions and judgments relative to the carrying value, remaining useful lives and residual values. These assumptions and judgments reflect both historical experience and expectations regarding future operations, utilization and performance. 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.

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 the operating condition or functional capability of our rigs as well as market and economic factors.

The carrying values of our long-lived assets, such as our drilling units, are reviewed 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 disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment is made to the market value or to the discounted future net cash flows. In general, impairment analyses are based on expected costs, utilization and dayrates for the estimated remaining useful lives of the asset or group of assets being assessed. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount is not 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.

During the years ended December 31, 2017, 2016 and 2015 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, with sufficient headroom. 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.

With regard to older drilling units which have relatively short remaining estimate 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 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.

Financial Instruments - Derivative valuations
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 are now held at a terminated value. As such, any credit risk adjustment on these arrangements were taken to the Consolidated Statement of Operations within "Reorganization Items, net". Please refer to Note 22 "Risk management and financial instruments" for further information on the derivatives valuations and impact of Chapter 11 filing.

Income Taxes
We are a Bermudan company. We are not currently required to pay taxes in Bermuda on ordinary income or capital gains. We have received written assurance from the Minister of Finance in Bermuda that we will be exempt from taxation until March 31, 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, 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 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 as our operations are conducted in different tax jurisdictions and the amount of pre-tax income fluctuates.

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 amount, 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 sustainable and on estimates of taxes that will ultimately be due. 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

45




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 of 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.

Recently Adopted and Issued Accounting Standards

Please see "Note 2–Accounting Policies" of our consolidated financial statements included herein, for a list of recently issued and adopted accounting standards, which may impact our consolidated financial statements and related disclosures when adopted.

A.    Results of Operations

Fiscal Year Ended December 31, 2017 compared to Fiscal Year Ended December 31, 2016
The following table sets forth our operating results for the years ended December 31, 2017 and 2016.
(In millions of U.S. dollars)
Year ended December 31, 2017
Year ended December 31, 2016
Change
Total operating revenues
257.5

534.7

(51.8
)%
(Loss)/gain on disposal
(4.6
)
2.4

(291.7
)%
Total operating expenses
(385.9
)
(446.3
)
(13.5
)%
Operating income
(133.0
)
90.8

(246.5
)%
Interest expense
(81.5
)
(106.0
)
(23.1
)%
Other financial items
(78.2
)
(15.0
)
421.3
 %
Loss before taxes
(292.7
)
(30.2
)
869.2
 %
Income taxes
6.3

(22.2
)
(118.0
)%
Net loss
(286.4
)
(52.4
)
446.6
 %

Total operating revenues
The following table sets forth our operating revenues for the years ended December 31, 2017 and 2016.
(In millions of U.S. dollars)
Year ended December 31, 2017
Year ended December 31, 2016
Decrease
Total operating revenues
257.5

534.7

(51.8
)%

Total operating revenues for the year ended December 31, 2017 was $257.5 million, compared to $534.7 million for the year ended December 31, 2016. Total operating revenues are predominantly contract revenues with additional amounts of reimbursable and related party revenue and other revenue. 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.

We also recognized a loss of $4.6 million for the year ended December 31, 2017 ($2.4 million gain in 2016), as a result of a write-off of spare parts. The West Rigel has been classified as held for sale since 2015. On 5 April 2018, Seadrill entered into a settlement and release agreement, subject to Bankruptcy Court approval, with Jurong Shipyard (“Jurong”) in respect of the West Rigel whereby Seadrill agreed that the share of sale proceeds from the sale of the West Rigel by Jurong would be $126 million. The Company considers this agreement provides additional evidence of the value of the asset held for sale at December 31, 2017, and has therefore reflected the agreed share of sales proceeds in the value of the asset held for sale at the balance sheet date. This resulted in an additional $2 million loss on disposal being recognized for the year ended December 31, 2017.


46




Total operating expenses
The following table sets forth our operating expenses for the years ended December 31, 2017 and 2016:
(In millions of U.S. dollars)
Year ended December 31, 2017
Year ended December 31, 2016
Decrease
Total operating expenses
(385.9
)
(446.3
)
(13.5
)%

Total operating expenses for the year ended December 31, 2017 was $385.9 million, compared to $446.3 million for the year ended December 31, 2016. Total operating expenses consist of vessel and rig operating expenses, depreciation and amortization, impairment charges, general and administrative expenses and reimbursable expenses. Vessel and rig operating expenses decreased by $58.6 million, primarily because of a reduced number of drilling units in operation in 2017 as compared to 2016.

Interest expense
Interest expense for the year ended December 31, 2017 was $81.5 million, compared to $106.0 million for the year ended December 31, 2016. The decrease is mainly due to post-petition contractual interest expenses 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.

Other financial items
Other financial items reported in the income statement include the following items:
(In millions of U.S. dollars)
Year ended December 31, 2017
Year ended December 31, 2016
Gain/(loss) on derivative financial instruments
13.0

(9.9
)
Foreign exchange loss/(gain)
(19.5
)
3.4

Reorganization items
(57.7
)

Other financial items
(14.0
)
(8.5
)
Total other financial items
(78.2
)
(15.0
)

The gain on derivative financial instruments was $13.0 million in 2017, compared to a loss of $9.9 million in 2016. The gain in 2017 was primarily due to gains of $15.9 million on our cross-currency interest swaps which were partially offset by a loss of $2.3 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 $0.9 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 unfavorable movements in the fair market value of these derivative financial instruments.

Foreign exchange loss was $19.5 million for the year ended December 31, 2017, compared to a gain of $3.4 million in the year ended December 31, 2016. This was primarily due to the unrealized loss on the revaluation of the NOK 1.5bn bond loan to U.S dollars.

After the filing of our bankruptcy petition on September 12, 2017, we incurred $23.4 million of post-petition professional fees associated with the bankruptcy cases. Additionally, we incurred non-cash charges of $3.9 million relating to unamortized debt issuance costs and $31.3 million in respect of reversal of issuing entities credit risk on derivatives. These have been recognized as Reorganization items.

Other financial items primarily relates to certain pre-petition costs relating to our financial restructuring and this increased in the year ended December 31, 2017 due to the increased restructuring activity prior to the petition date.

Income taxes
Income tax benefit was $6.3 million for the year ended December 31, 2017, compared to a charge of $22.2 million for the year ended December 31, 2016. Our effective tax rate was a benefit of approximately 2.2% for the year ended December 31, 2017, as compared to a charge of -73.5% for the year ended December 31, 2016. The decrease in tax expense is primarily attributable to lower operating income, benefit from re-measurement of deferred tax liability due to decrease in Norway corporate income tax rate, and various prior period adjustments.

We may be taxable in more than one jurisdiction based on our drilling 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 an overall loss at the consolidated level.

Significant amounts of our income and costs are reported in non-taxable jurisdictions such as Bermuda. The drilling rig operations are normally carried out in taxable jurisdictions. In the tax jurisdictions where we operate, the corporate income tax rates range from 19% to 27% for earned income. Further,

47




losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, the effective tax rate may differ significantly from period to period depending on the level of activity in and mix of each of the tax jurisdictions in which our operations are conducted.

Fiscal Year Ended December 31, 2016 compared to Fiscal Year Ended December 31, 2015

The following table sets forth our operating results for the year ended December 31, 2016 and 2015.
(In millions of U.S. dollars)
Year ended December 31, 2016
Year ended December 31, 2015
Change
 
 
 
 
Total operating revenues
534.7

747.7

(28.5
)%
Loss on disposal
2.4

(82.0
)
(102.9
)%
Operating expenses
(446.3
)
(568.2
)
(21.5
)%
Operating income/(loss)
90.8

97.5

(6.9
)%
Interest expense
(106.0
)
(97.7
)
8.5
 %
Other financial items
(15.0
)
(12.5
)
20.0
 %
Loss before taxes
(30.2
)
(12.7
)
137.8
 %
Income taxes
(22.2
)
(44.1
)
(49.7
)%
Net Loss
(52.4
)
(56.8
)
(7.7
)%

Total operating revenues
The following table sets forth our total operating revenues for the year ended December 31, 2016 and 2015.
(In millions of U.S. dollars)
Year ended December 31, 2016
Year ended December 31, 2015
Decrease
Total operating revenues
534.7

747.7

(28.5
)%

Total operating revenues for the year ended December 31, 2016 were $534.7 million, compared to $747.7 million for the year ended December 31, 2015. Total operating revenues are predominantly contract revenues with additional amounts of reimbursable and related party revenue and other revenue.
The primary reason for the decrease is that the West Alpha and West Phoenix finished their contracts and entered into cold stack in August 2016. The
West Epsilon also ended its contract in October 2016.

Gain/(Loss) on disposals
As a result of the agreement with Jurong in 2015, we concluded that the West Rigel drilling unit should be classified as “Held for Sale”, and accordingly
we recognized a loss on disposal of $82.0 million for the year ended December 31, 2015. Refer to Note 12 - "Asset held for sale" to our consolidated financial statements included herein for more information. We recognized a gain of $2.4 million for the year ended December 31, 2016, as a result of sale of spare parts, related to West Rigel, to Seadrill.

Total operating expenses
The following table sets forth our total operating expenses for the year ended December 31, 2016 and 2015.
(In millions of U.S. dollars)
Year ended December 31, 2016
Year ended December 31, 2015
Decrease
Total operating expenses
(446.3
)
(568.2
)
(21.5
)%

Total operating expenses for the year ended December 31, 2016 were $446.3 million compared to $568.2 million for the year ended December 31, 2015. Total operating expenses consist of vessel and rig operating expenses, depreciation and amortization, general and administrative expenses and reimbursable expenses. Vessel and rig operating expenses decreased by $88.9 million, primarily because the West Phoenix and West Alpha completed their contracts, as discussed in the revenues section above. The West Phoenix was also cold stacked in October 2016, resulting in lower operating costs. In addition our cost-cutting initiatives resulted in lower personnel and repairs and maintenance costs across all units in 2016 when compared to 2015. General and administration expenses decreased by $30.1 million in 2016 as compared to 2015 following the implementation of our cost cutting measures.


48




Interest expense
Interest expense for the year ended December 31, 2016 was $106.0 million, compared to $97.7 million for the year ended December 31, 2015. The increase was primarily due to there being no interest capitalized on the West Rigel during 2016, after the deferral agreement was signed with Jurong.

Other financial items
Other financial items reported in the income statement include the following items:
(In millions of U.S. dollars)
Year ended December 31, 2016
Year ended December 31, 2015
 
 
 
Loss on derivative financial instruments
(9.9
)
(35.6
)
Foreign exchange gain
3.4

28.3

Other financial items
(8.5
)
(5.2
)
Total other financial items
(15
)
(12.5
)
 
The loss on derivative financial instruments related to fair value adjustments and net settlements on our interest rate swaps, cross currency swaps and forward exchange contracts. During the year ended December 31, 2016, the recognized loss from derivative financial instruments was $9.9 million compared to a loss of $35.6 million for the year ended December 31, 2015. These figures include realized net settlements on the derivative financial instruments of $25.2 million and $37.1 million for the year ended December 31, 2016 and December 31, 2015 respectively. The unrealized losses were due to the falls in the fair market value of these derivative financial instruments.

Foreign exchange gain was $3.4 million for the year ended December 31, 2016, compared to a gain of $28.3 million in the year ended December 31, 2015. This was primarily due to the Norwegian kroner weakening against the U.S. dollar during 2016 and 2015, with gains recognized in respect of our NOK-denominated debt.

Income taxes
Income tax expense was $22.2 million for the year ended December 31, 2016, compared to $44.1 million for the year ended December 31, 2015. Our effective tax rate was approximately -73.5% for the year ended December 31, 2016, as compared to -347.2% for the year ended December 31, 2015. The negative tax rate means that we continue to pay tax on local operations but reported an overall loss before tax inclusive of discrete items. In particular,
the negative effective tax rate is primarily due to the loss on derivatives, which is recognized in Bermuda, a zero tax rate jurisdiction. In addition, the
decrease in the tax expense in 2016 in comparison to 2015 is mainly due to deferred tax liability recorded on unremitted earnings in 2015.

We may be taxable in more than one jurisdiction based on our drilling 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 an overall loss at the consolidated level.

Significant amounts of our income and costs are reported in non-taxable jurisdictions such as Bermuda. The drilling rig operations are normally carried
out in taxable jurisdictions. In the tax jurisdictions where we operate, the corporate income tax rates range from 20% to 27% for earned income. Further,
losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, the effective tax rate may differ significantly
from period to period depending on the level of activity in and mix of each of the tax jurisdictions in which our operations are conducted.


B.    Liquidity and Capital Resources

Overview
We operate in a capital-intensive industry. Historically, our investment in newbuild drilling units, secondhand drilling units and our acquisition of other companies has been financed through cash generated from operations, and a combination of equity issuances, bond and convertible bond offerings, and borrowings from commercial banks and export credit agencies. Our liquidity requirements relate to servicing and repaying our debt, funding investment in drilling units, funding working capital requirements, funding potential dividend payments and maintaining adequate cash reserves to mitigate the effects of fluctuations in operating cash flows. Most of our contract and other revenues are received monthly in arrears, and most of our operating costs are paid on a monthly basis.

During the Chapter 11 proceedings, Seadrill has agreed to fund our liquidity needs on an ordinary course. No interest will be charged on such balances after the Petition date.


49




Our funding and treasury activities are conducted within corporate policies 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 and GBP.

This section discusses the most important factors affecting the liquidity and capital resources of the company, including:
summary of our borrowing activities;
liquidity outlook;
our newbuilding program;
key financial covenants contained in our borrowings;
sources and uses of cash; and
our Chapter 11 process discussed in item 4B "Business Overview"

Summary of our borrowing activities
As of December 31, 2017, we had total outstanding borrowings under our credit facilities of $2,118.4 million, compared to $2,289.3 million as at December 31, 2016. This includes interest bearing debt under loan agreements with related parties of $121.5 million.

We have issued a variety of secured and unsecured borrowings. The debt is secured by, among other things, liens on our drilling units. In addition, all of our loan 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 unsecured debt consists of bonds denominated primarily in U.S. dollars, but also in Norwegian Kroner.

On September 12, 2017, we, together with Seadrill and certain of Seadrill's consolidated subsidiaries (collectively, the Company Parties) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the Southern District of Texas. On this date we entered into the RSA with the Consenting Stakeholders. Ship Finance International Limited and three of its subsidiaries, which charter three drilling units to the Company Parties, also executed the RSA. The RSA contemplates that each of the Company Parties’ credit facilities will be amended to provide, among other things:

approximately 4 to 5.5 year maturity extensions;
significant amortization relief with no amortization payments until 2020;
no maintenance covenants except minimum liquidity until Q1 2021; and
cross-collateralization of the existing credit facilities.

The RSA and Investment Agreement contemplate the formation of an intermediate holding company to issue the new secured notes. Rig-owning entities and certain other assets will be contributed to a subsidiary of that intermediate holding company, which will guarantee and facilitate cross-collateralization of the amended credit facilities. The RSA provides for amendments to SFL’s charter agreements with the Company Parties on terms generally consistent with the credit facility amendments.

Our bankruptcy filing on September 12, 2017 constituted an event of default with respect to our pre-bankruptcy debt obligations and as a result of the filing, certain pre-petition long-term debt facilities are included in Liabilities Subject to Compromise in the consolidated balance sheet as of December 31, 2017. Refer to Note 1- “Restructuring Agreement and Bankruptcy Proceedings under Chapter 11 for the detail of our pre-bankruptcy debt.
  
During the year ended December 31, 2017 external facility debt repayment totaled $184.2 million, compared to $214.1 million in 2016.

Seadrill guarantees our NOK 1,500 million senior unsecured bond, our $2,000 million Senior Secured Credit Facility, and our charter payments to SFL Linus Ltd. in connection with its $475 million senior secured credit facility, which is consolidated in our financial statements.

In 2014 we issued a bond, or the Senior Unsecured Notes, with an aggregate principal of $600 million, coupon rate of 6.25%, and maturity in 2019. We used the gross proceeds of the senior unsecured notes issuance for the prepayment of indebtedness and transaction expenses and general corporate purposes. Seadrill has purchased approximately 31.1% of the aggregate principal amount of the Senior Unsecured Notes.

On January 31, 2017, Seadrill provided a $25 million revolving credit facility to us that was set to mature on March 31, 2017. On March 15, 2017, the maturity was extended until April 30, 2017. On April 25, 2017, the revolving credit facility was increased to $50 million and extended to June 30, 2017. On June 27, 2017, the facility was increased to $150 million and extended to July 31, 2017. On July 27, 2017, the facility was extended to September12, 2017. On September 8, 2017, the facility was increased to $200 million.

Following the Chapter 11 filing the Company no longer has access to the RCF facility. Seadrill has agreed to fund our liquidity needs on an ordinary course. No interest will be charged on such balances after the Petition date.


50




The table below shows the outstanding debt not reported as liabilities subject to compromise as of December 31, 2017, repayable as follows:
(In millions of U.S. dollars) 
Year ending December 31,
Year ended December 31, 2018
47.5

Year ended December 31, 2019
261.3

Year ended December 31, 2020

Year ended December 31, 2021

Year ended December 31, 2022
122.1

Year ended December 31, 2023 and thereafter

Total debt   
430.9


Liquidity outlook
Our short-term liquidity requirements relate to servicing our debt amortizations, interest payments, and funding working capital requirements. Sources of liquidity include existing cash balances, and contract and other revenues. We have historically relied on our cash generated from operations to meet our short-term liquidity needs. Following the Chapter 11 filing, Seadrill has agreed to fund our liquidity needs on an ordinary course. No interest will be charged on such balances after the Petition date. However, as a result of the downturn in the offshore industry, we have been required to obtain additional liquidity to fully meet our short-term liquidity requirements.

In order to achieve this, we commenced the restructuring program described in Item 4B. Business Overview. In order to implement the transactions contemplated as part of our restructuring, we commenced Chapter 11 proceedings under the Bankruptcy Code on September 12, 2017. Although we anticipate that our restructuring plan will address our liquidity concerns, uncertainty remains over the bankruptcy courts approval of our plan of reorganization, and therefore substantial doubt exists over our ability to continue as a going concern for twelve months after the date the financial statement are issued.

Financial information in this report have been prepared on the basis that the Company will continue as a going concern, which presumes that it will be able to realize its assets and discharge its liabilities in the normal course of business as they come due. Financial information in this report does not reflect the adjustments to the carrying values of assets and liabilities and the reported expenses and balance sheet classifications that would be necessary if the Company were unable to realize its assets and settle its liabilities as a going concern in the normal course of operations. Such adjustments could be material. Upon emergence from Chapter 11 proceedings adjustments to the carrying values and classifications of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Please refer to “Item 3. Key Information—D. Risk Factors— Factors—"Risks Relating to the Bankruptcy Proceedings".

Covenants contained within our borrowings
As part of the RSA entered into on September 12, 2017, the lenders have agreed to waive any breach of, or default under, our debt agreements after this date, which arise as a result of or is, directly or indirectly, related to the commencement of Chapter 11 proceedings or any of the steps contemplated in, or to be undertaken pursuant to, the RSA including any failure to comply with any of the financial covenants in the debt agreement.
Please refer to Note 14 "Long-term interest bearing debt" to our Consolidated Financial Statements included herein for further information on the RSA agreement and the impact on our covenants contained within our credit facilities and bonds.

Our Newbuilding Program
We have entered into a construction contract for one sixth-generation harsh environment semi-submersible, the West Rigel, with corresponding contractual commitments, including project management, operation preparations, and variation orders, totaling $717.5 million of which we have paid $204.3 million to date. The West Rigel was initially scheduled to be delivered to us in the fourth quarter of 2015.

On December 2, 2015, we signed an amendment with Jurong for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel. The deferral period originally lasted until June 2016 but was subsequently amended to July 6, 2018. Following completion of the deferral period, the Company and Jurong have agreed to form a Joint Asset Holding Company for joint ownership of the West Rigel, to be owned 23% by the Company and 77% by Jurong, in the event no employment is secured for the West Rigel and no alternative transaction is completed. Until the end of the deferral period, we will continue to market the unit for an acceptable drilling contract, and the West Rigel will remain at the Jurong shipyard in Singapore. The Company and Jurong may also consider other commercial opportunities for the West Rigel during this period. On December 26, 2017, Jurong announced that a sale agreement, subject to conditions, had been signed for West Rigel. As the agreement is pursuant to conditions being met, the Company will continue to hold the asset within "non-current assets held for sale".

On 5 April 2018 we entered into a settlement and release agreement with Jurong Shipyard (“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.


51




Sources and Uses of Cash
At December 31, 2017, we had cash and cash equivalents totaling $29.5 million, as compared to $68.7 million in 2016.

In the year ended December 31, 2017, we incurred a cash outflow of $9.0 million from operations, used $0.8 million in investing activities, and cash outflows from financing activities were $29.2 million. In the year ended December 31, 2016, we generated cash from operations of $128.7 million, generated $1.3 million from investing activities, and used $218.2 million in financing activities. In the year ended December 31, 2015, we generated cash from operations of $339.9 million, used $39.0 million in investing activities, and had outflows of $264.1 million from financing activities.

 
Years Ended December 31,
 
2017
 
2016
 
2015
Net cash (used in)/ provided by operating activities
(9.0
)
 
128.7

 
339.9

Net cash (used in)/ provided by investing activities   
(0.8
)
 
1.3

 
(39.0
)
Net cash used in financing activities   
(29.2
)
 
(218.2
)
 
(264.1
)
Effect of exchange rate changes on cash and cash equivalents
(0.2
)
 
6.0

 
(2.1
)
Net (decrease)/increase in cash and cash equivalents
(39.2
)
 
(82.2
)
 
34.7

Cash and cash equivalents at beginning of the period
68.7

 
150.9

 
116.2

Cash and cash equivalents at the end of period
29.5

 
68.7

 
150.9


Net cash (used by)/provided by operating activities
The net cash generated from operations became a net outflow in 2017 compared to 2016 primarily due to working capital outflows in the year. Net changes in operating assets and liabilities were an outflow of $38.2 million in 2017 compared to an inflow of $22.9 million in 2016.

Net cash (used in)/provided by investing activities
The net cash used in investing activities was $0.8 million in 2017, compared to net cash provided by investing activities of $1.3 million in 2016.

Net cash used in financing activities
The net cash used in financing activities was $29.2 million in 2017, compared to cash used by financing activities of $218.2 million in 2016. During the year ended December 31, 2017 the Company made external debt repayments of $184.2 million, compared to $214.1 million in 2016, made related party repayments of $131.5 million and received proceeds from related party loans of $286.5 million.

In 2017, we raised no new debt, paid no dividends, and made no repayments of related party and shareholder loans.

Dividends
For the years ended December 31, 2017 and 2016, we did not pay any dividends. Please see "Item 8. Financial Information—A. Consolidated Statements and Other Financial Information—Dividend Policy" for more information.

Restrictions
North Atlantic Drilling Ltd., as the parent company of its operating subsidiaries, is not a party to any drilling contracts directly and is therefore dependent on receiving cash distributions from its subsidiaries and other investments to meet its payment obligations. Cash dividend payments and intercompany loans are regularly made by the various subsidiaries. Surplus funds are deposited to maximize returns while providing us with flexibility to meet all requirements for working capital and capital investments.

Hedging of market risk
Prior to filing for Chapter 11, we used financial instruments to reduce the risk associated with fluctuations in interest and foreign exchange rates. As a result of filing, this triggered an event of default on our derivative agreements and these were subsequently terminated on September 13, 2017.

Please see "Item 11–Quantitative and qualitative disclosures about market risk" for a more detailed discussion of how changes in the economic environment would affect our Company.

Please see "Note 22–Risk management and financial instruments" to our consolidated financial statements included herein, for further information on financial instruments related to our loan facilities and bonds.


52




Ability to continue as a going concern
The Company’s consolidated financial statements have been prepared on a going concern basis and contemplate the realization of assets and satisfaction of liabilities in the normal course of business. The Company’s going concern assumption is based on management’s expectation that the current restructuring program, described in Note 3 - "Chapter 11 Proceedings" to the Consolidated Financial Statements included herein, will alleviate the conditions when completed. Furthermore, our business operations are unaffected by the Chapter 11 Proceedings and the restructuring efforts, and we expect to meet our ongoing customer and business counterparty obligations during the course of the proceedings.
We have been engaged in discussions with our banks, potential new investors, existing stakeholders and bondholders in order to restructure our secured credit facilities and unsecured liabilities and infuse our balance sheet with new capital. These collaborative efforts resulted in the signing of a Restructuring Support and Lock-Up Agreement (“RSA”) on September 12, 2017, subsequently amended on February 26, 2018, which provides for several conditions to be met in order to fully effectuate the intended restructuring. Although we anticipate that our restructuring plan will address our liquidity concerns, uncertainty remains over the Court's approval of our plan of reorganization, and therefore substantial doubt exists over the ability to continue as a going concern for twelve months after the date the financial statement are issued.



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 offshore drilling market is currently entering the fifth year of a downturn and the timing of recovery remains uncertain. The below table show the average oil price over the period 2013 to 2017.

 
 
2013
 
2014
 
2015
 
2016
 
2017
 
Average Brent oil price ($/bbl)
 
108.70

 
99.49

 
53.60

 
45.13

 
54.74

 

Brent oil prices have been in the range $45-$55 throughout most of 2017 before increasing in the last quarter and early 2018. The Brent oil price on March 31, 2018 was $70.

Oil and gas companies have responded to the decrease in oil price over the downturn by decreasing their upstream expenditures. During 2017, oil and gas companies have continued to focus on preserving cash, in some cases consciously allowing the production decline rate on producing fields to accelerate because of reduced infill drilling and well intervention. Based on the decreased level of investment since 2014, we expect that production decline rates will increase. Further, the longer the period of lower investment persists, the more new projects and infill drilling will be required to replace the lost production.

The below table shows the global number of rigs on contract at March 31, 2018 and for each of the four preceding years.
 
 
Mar-14
 
Mar-15
 
Mar-16
 
Mar-17
 
Mar-18
 
Contracted floating rigs
 
260

 
237

 
170

 
135

 
125

 
Contracted jack-up rigs
 
415

 
398

 
322

 
297

 
294

 

During 2017, we have seen an increase in the activity level in the floater market, albeit primarily for short-term work at extremely competitive dayrates. This improvement was from a low base and we still expect utilization in the floater market to get worse before it improves. Whether the recent increase in oil price will lead to a recovery in offshore exploration and development expenditure in 2018 remains uncertain. It is important to recognize that the resetting of costs across the value chain may facilitate increased activity with only a marginal increase in oil prices.

At the same time, the offshore drilling market remains oversupplied. Offshore drilling contractors have continued to aggressively market their rigs, often focusing on utilization over returns. The below table shows the utilization of the global fleet at March 31, 2018 and for each of the four proceeding years.


53




 
 
Mar-14
 
Mar-15
 
Mar-16
 
Mar-17
 
Mar-18
 
Global fleet - floaters
 
320

 
313

 
303

 
282

 
259

 
Global fleet - jack-up
 
517

 
540

 
541

 
539

 
526

 
Utilization - floaters
 
81
%
 
76
%
 
56
%
 
48
%
 
48
%
 
Utilization - jack-up
 
80
%
 
74
%
 
60
%
 
55
%
 
56
%
 

Older units that roll off contract that may require significant capital expenditure to return to the working fleet are therefore more likely to be cold stacked and ultimately scrapped. We expect the combination of declining rates and accelerated scrapping activity to lead to a balanced market at some point. Based on the expected level of scrapping activity and the number of units that are anticipated to be cold stacked, a relatively small increase in spending could meaningfully tighten the floater and tender markets.

Floaters - outlook

Based on the level of current activity and the aging floater fleet, we expect scrapping activity to continue. A total of 103 floaters have been scrapped or retired since the beginning of 2014, equivalent to 29% of the total fleet, and currently there are 28 cold or warm stacked units with no follow-on work identified that are 30 years old or older, which are prime scrapping candidates. In the next 18 months, a further 22 units that are 30 years old or older will be coming off contract with no follow-on work identified which represents 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. Significant cold stacking activity would represent a positive development in the market, effectively reducing marketed supply and helping to stabilize utilization and pricing until a more fundamental recovery is in place.

Currently 125 floaters out of 259 floaters are under contract, representing 48% marketed utilization. It is estimated that 180-200 rigs are needed in the floater fleet to maintain long-term average decline curves.

Currently the global floater order book stands at approximately 42 units, comprised of 28 drillships and 14 semi-submersible rigs. 12 are scheduled for delivery in 2018, 17 in 2019 and 13 in 2020 and beyond. Due to the subdued level of contracting activity, it is likely that a significant number of newbuild orders will be delayed or canceled until an improved market justifies taking delivery.

Jack-ups

Tendering activity in the jack-up market during 2017 continued, albeit at low dayrates. The shorter-term contract profile in this market lends itself to more turnover and the market has likely reached the base level of units required to maintain existing decline curves.

Globally, marketed utilization is 56%. For units built before 2007 marketed utilization is 50% while for newer units marketed utilization is 63%. While utilization is still far from levels required for pricing power, we believe that customers continue to demonstrate a preference for newer and more capable equipment that can provide safer and more efficient operations.

Currently there are 56 cold stacked units that are 30 years old or older. Additionally, in the next 18 months 91 units that are 30 years old or older will be coming off contract with no follow-on work identified. Together these 147 units, or 28% of the delivered fleet, represent prime scrapping candidates.

90 additions to the fleet 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 of December 31, 2017 or 2016, 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 variable interest entities and guarantees towards third parties such as surety performance guarantees towards customers as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these

54




guarantees are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2017, we had not been required to make collateral deposits with respect to these agreements.

The maximum potential future payments are summarized in "Note 23–Commitments and contingencies" to our consolidated financial statements included herein.

F.     Tabular Disclosure of Contractual Obligations

According to the US bankruptcy code, the Debtors have the right to assume or reject certain contracts, subject to the approval of the US Bankruptcy Court and certain other conditions. The table does not reflect any potential changes to our contractual obligations and other commitments that may result from the Chapter 11 reorganization process and activities contemplated by the Plan. At December 31, 2017, we had the following contractual obligations and commitments:
(In millions of U.S. dollars)
Years Ended December 31,
2018
2019 - 2020
2021 - 2022
Thereafter
Total
$475 Million Credit Facility
47.5

261.3



308.8

$125 Million related party loan



121.5

121.5

Total interest payments (2)
61.4

7.8



69.2

Related party interest payments
5.6

11.2

11.2

36.6

64.6

Financial Guarantee fee charged by Seadrill
0.9

0.8



1.7

Pension obligations (3)
3.0

6.0

6.0

15.0

30.0

Leased premises
3.1

5.4

4.4


12.9

Total contractual cash obligations
121.5

292.5

21.6

173.1

608.7


(1)
This has been converted using an exchange rate of USD $1 to NOK8.20 as of December 31, 2017. Please see “Item 11. Quantitative and Qualitative Disclosures about Market Risk” for details on cross currency swaps.
(2)
During bankruptcy proceedings, interest payments on the secured credit facilities are treated as adequate protection payments which are recognized as a reduction in the principal balance of secured credit facilities held within "Liabilities subject to compromise" in the Consolidated Balance Sheets.
(3)
Pension obligations are the forecasted employer's contributions to our defined benefit plans, expected to be made over the next ten years.

In addition to the above, we have recognised uncertain tax positions at December 31, 2017 of $7.9 million.


G.     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.


ITEM 6.    DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES


55




A.    Directors and Senior management
Set forth below are the names, ages and positions of our current directors and executive officers.
Name 
Age 
Position 
Kate Blankenship
53
Director and Audit Committee Member
Paul M. Leand, Jr.
51
Director
Bote de Vries
59
Director
Hunter Cochrane
62
Director
Georgina Sousa
67
Company Secretary
Alf Ragnar Løvdal
60
Chief Executive Officer of North Atlantic Management
Scott McReaken
39
Chief Financial Officer of North Atlantic Management

Biographical information concerning the directors and executive officers listed above is set forth below.

Kate Blankenship has served as a director on our Board of Directors since February 2011. Mrs. Blankenship has also served as a director of Frontline Ltd since 2003. Mrs. Blankenship joined Frontline Ltd. in 1994 and served as its chief accounting officer and company secretary until October 2005. Mrs. Blankenship has been a director of Ship Finance since October 2003, Seadrill since its inception in May 2005, Seadrill Partners since June 2012, Independent Tankers Corporation Limited, since February 2008, Golden Ocean Group Limited since March 2015, Archer Ltd., or Archer, since its incorporation in 2007 and Avance Gas Holding Ltd since October 2013. Mrs. Blankenship served as a director of Golar LNG Limited from July 2003 until September 2015 and Golar LNG Partners from September 2007 until September 2015. She is a member of the Institute of Chartered Accountants in England and Wales.

Paul M. Leand, Jr. has served as a director on our Board of Directors since February 2012. Mr. Leand has been the Chief Executive Officer and director of AMA Capital Partners LLC, or AMA, an investment bank specializing in the maritime industry since 2004. Mr. Leand has worked extensively in U.S. capital markets in connection with AMA’s restructuring and mergers and acquisitions practices. Mr. Leand currently serves as a member of the Investment Committee of AMA Shipping funds, a series of private equity funds formed and managed by AMA. From 1989 to 1998, Mr. Leand served at the First National Bank of Maryland where he managed the bank’s Railroad Division and its International Maritime Division. Mr. Leand has also served as a director of Ship Finance since 2003, Golar LNG Partners LP since 2011, Seadrill since April 2013 and Eagle Bulk Shipping Inc. since 2014.

Bote de Vries was appointed as a director on our Board of Directors in March 2016. Mr. de Vries has extensive legal, asset advisory and financial services experience, specifically in the shipping and maritime sectors. He is a board member of Artilium Plc, TBS Shipping Services Inc., Lloydsfonds AG, Metro Exploration Holding Corporation and Vallianz Holdings; and member of four supervisory boards in shipping, healthcare, banking and building societies in the Netherlands.

Hunter Cochrane was appointed as a director on our Board of Directors in March 2016. Mr. Cochrane has extensive experience in industrial distribution and the oil and gas industry. He is also a board member of Chloe Marine Corp Ltd. and Golden Close Marine Corp Ltd; and holds advisory positions with Bovaro Partners LLC, a merchant banking partnership.

Georgina Sousa has served as a director on our Board of Directors from September 2013 until September 2016, and as our company secretary since our inception in February 2011. She is also currently a director of Frontline Ltd. and Seadrill, and the company secretary of Seadrill, Seadrill Partners, Ship Finance and Archer. Until January 2007, she was vice-president of corporate services of Consolidated Services Limited, a Bermuda Management Company, having joined the firm in 1993 as manager of corporate administration. From 1976 to 1982, Mrs. Sousa was employed by the Bermuda law firm of Appleby, Spurling & Kempe as a company secretary and from 1982 to 1993 she was employed by the Bermuda law firm of Cox & Wilkinson as senior company secretary.

Alf Ragnar Løvdal has served as Chief Executive Officer of North Atlantic Management since January 2013. Mr. Løvdal served as Senior Vice President for Seadrill in the Asia Pacific region from April 2009 until December 2012. Mr. Løvdal has also held several other senior positions at Seadrill, including as general manager of operations for its mobile units. Mr. Løvdal has served as a director of Archer since 2014. Mr. Løvdal has 35 years of experience in the oil and gas industry, including ten years in the well services business of the drilling contractor Smedvig, which Seadrill acquired in early 2006. Prior to his employment with Smedvig and Seadrill, Mr. Løvdal held various positions in different oil service companies, including five years of offshore field experience with Schlumberger Limited and serving as the chief executive officer of Seawell Management AS. He has a degree in mechanical engineering from Horten Engineering Academy in Norway.

Scott McReaken has served as Chief Financial Officer of North Atlantic Management since August 2015. Mr. McReaken has also served as Chief Executive Officer of Sevan Drilling since November 2013 and Director of Sevan Drilling since December 2016. He was previously director of finance for Seadrill in the Americas region from July 2012 to November 2013. Mr. McReaken was Director Financial Planning and Analysis at Vantage Drilling Company from March 2010 to July 2012 and held various positions at Pride International from May 2005 to March 2010, including assignments in West Africa and the divestiture of the Latin American onshore drilling and oil field services division. From the onset of his career at Arthur Andersen LLP in

56




2001, Mr. McReaken worked in audit and advisory services for various companies until 2005. He has a degree in accounting from The University of Texas at Austin and is a Certified Public Accountant and Certified Internal Auditor. Mr. McReaken has served as the Treasurer and Secretary of the International Association of Drilling Contractors since January 2013.

B.    Compensation

For the year ended December 31, 2017, we paid $0.4 million in total compensation to directors. None of the members of our Board of Directors or officers will receive any benefits upon termination of their directorships or officers positions.

All references in this annual report to “our officers” include those officers of North Atlantic Management, Seadrill Management Ltd, and Sevan Drilling Management AS, who perform or performed, as the case may be, executive officer services for our benefit. For the year ending December 31, 2017, the Chief Executive Officer of North Atlantic Management AS, our Principal Executive Officer, and the Chief Financial Officer of North Atlantic Management AS, our Principal Financial Officer, were paid total combined aggregate compensation of $1.0 million in relation to their services to us.

In addition to cash compensation, during 2017 we also recognized an expense of $0.4 million relating to restricted stock units granted to certain of our directors and executive officers. The fair values of awards are based on the market share price on the grant date, which was $96.50 for the restricted stock units granted in 2013, $14.10 for the grants in May 2015, $3.70 for the grants in December 2015, and $3.62 for the grants in December 2016.

C.    Board Practices

Each director holds office until his or her term expires at the next annual general meeting of shareholders or until his or her death, resignation, removal or the earlier termination of his or her term of office. All directors whose term expires are eligible for re-election. Officers are appointed from time to time by our Board of Directors and hold office until a successor is appointed or their employment is terminated.

Our Board of Directors currently consists of four members, of whom four are considered independent according to Rule 10A-3 of the Securities Exchange Act of 1934, as amended, or the Exchange Act: Mrs. Kate Blankenship, Mr. Paul Leand Jr, Mr. Hunter Cochrane and Mr. Bote de Vries.

We do not maintain service contracts with any of our directors providing for benefits upon termination of employment.

Committees of the Board of Directors
Our Board of Directors has established an audit committee that consists of one director, Mrs. Kate Blankenship. Our audit committee is responsible for ensuring that we have an independent and effective internal and external audit system. Additionally, the audit committee supports our Board of Directors in the administration and exercise of its responsibility for supervisory oversight of financial reporting and internal control matters and maintains appropriate relationships with our auditors. Our Board of Directors has determined that Mrs. Blankenship qualifies as “independent” under Rule 10A-3 under the Exchange Act and as an “audit committee financial expert” for purposes of the Commission's rules and regulations.

Our Board of Directors has also established a conflicts committee composed of at least two members of our Board of Directors to review all transactions that the Board of Directors believes may involve conflicts of interest, including without limitation, the exercise of the right of first refusal or any waiver of rights under the Cooperation Agreement, and will determine if such transaction and the resolution of the conflict of interest is fair and reasonable to us. At least 50% of the members of the conflicts committee may not be officers or employees of us or directors, officers or employees of Seadrill or its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, and not a breach by our directors of any duties any of them may owe us or our shareholders. The current members of the conflicts committee are Mr. de Vries and Mr. Cochrane.

Our Board of Directors may, in the future, establish such other committees as it determines from time to time.

D.    Employees

 
Year ended December 31, 2017
 
Year ended December 31, 2016
 
Year ended December 31, 2015
Offshore
572

 
545

 
1,017

Onshore
59

 
49

 
65

Total
631

 
594

 
1,082


Some of our employees and our contracted labor, who work in 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

57




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 23–Commitments and contingencies" to our consolidated financial statements included herein.

E.    Share ownership

The common shares beneficially owned by our directors and our executive officers are disclosed in “Item 7. Major Shareholders and Related Party Transactions - A. Major Shareholders.”

Equity Compensation Plans
On February 14, 2011, our Board of Directors resolved to establish a share option based incentive plan for our employees and directors, approved a set of rules applicable to the plan and reserved 6,000,000 of our authorized, but unissued common shares for use to satisfy future exercises of options granted under the plan. As a result of the 1-for-10 reverse stock split in December 2015, the number of authorized, but unissued, share options was adjusted to 600,000. No options have, to date, been granted under this plan.

Restricted Stock Units
On November 7, 2013, our Board of the Directors approved 278,778 awards under our Restricted Stock Units, or RSU, plan.  During 2016 and 2015, our Board of the Directors approved a further 270,653 and 1,587,719 awards, respectively, under our RSU plan. 

Under the terms of the plan, the holder of an award is entitled to receive a certain number of our common 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 date or upon vesting of the award.  In addition, the holder is entitled to receive an amount equal to the ordinary dividends declared and paid on our shares during the vesting period.

The total outstanding RSUs as of December 31, 2017 were 413,402.

The table below summarizes the outstanding Shares, Share Options and RSU's issued to our directors and executive officers. The awards have been adjusted for the 1 for 10 stock split in December 2015.
Director or Key Employee
Interest in Options and Restricted Stock Units (RSUs)
 
Scheme
 
Total number

 
Number vested

 
Fair Value at Grant Date

 
Expiry Date
Alf Ragnar Løvdal
RSUs
 
3,145